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Regulatory Impact Analysis for the Final
National Emission Standards for Hazardous Air
Pollutants: Gasoline Distribution Technology
Review and Standards of Performance for Bulk
Gasoline Terminals Review
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EPA-452/R-24-002
January 2024
Regulatory Impact Analysis for the Final National Emission Standards for Hazardous Air
Pollutants: Gasoline Distribution Technology Review and Standards of Performance for Bulk
Gasoline Terminals Review
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
We acknowledge the help of the Research Triangle Institute in preparing the compliance cost and
emission reductions for the regulatory options analyzed in this RIA.
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TABLE OF CONTENTS
Table of Contents v
List of Tables viii
List of Figures xi
1 Executive Summary
1-1
1.1 Background 1-1
1.1.1 NESHAP 40 CFR Part 60, Subparts R and BBBBBB 1-2
1.1.2 NSPS 40 CFR part 60, Subpart XX and XXa 1-4
1.2 Market Failure 1-5
1.3 Results for the Final Action 1-6
1.3.1 Baseline for the Regulation 1-6
1.3.2 Differences between the Final and Proposed Action 1-7
1.3.3 GACT6B 1-7
1.3.3.1 Options Examined in this RIA 1-7
1.3.3.2 Overview of Costs and Benefits for the Final Options 1-8
1.3.4 MACTR 1-11
1.3.4.1 Options Examined in this RIA 1-11
1.3.4.2 Overview of Costs and Benefits for the Final Options 1-11
1.3.5 NSPS XX 1-12
1.3.5.1 Options Examined in this RIA 1-12
1.3.5.2 Overview of Costs and Benefits for the Final Options 1-13
1.3.6 All Rules 1-15
1.4 Organization of this Report 1-17
2 Industry Profile
2-1
2.1 Introduction 2-1
2.2 Supply Side 2-1
2.2.1 The Gasoline Distribution Network 2-1
2.2.2 Downstream Marketing Arrangements for Refined Petroleum Products 2-5
2.2.3 Industry Organization 2-7
2.2.3.1 Concentration and Vertical Integration 2-7
2.2.3.2 Entry Barriers 2-10
2.2.3.3 Employment 2-10
2.3 Demand Side 2-12
2.4 Market Conditions 2-17
2.4.1 Consumption 2-17
2.4.2 Prices 2-17
2.4.3 Trends and Projections 2-20
3 Emissions and Engineering Costs Analysis
3-1
3.1 Introduction 3-1
3.2 Emissions Points, Controls, and Model Plants 3-1
3.2.1.1 Bulk Gasoline Terminals 3-2
3.2.1.2 Bulk Gasoline Plants 3-2
3.2.1.3 Pipeline Breakout Stations 3-2
3.2.1.4 Pipeline Pumping Stations 3-2
3,2.2 Emission Points at Regulated Facilities 3-3
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3.2.2.1 Loading Racks 3-3
3.2.2.2 Storage Tanks 3-4
3.2.2.3 Equipment Leaks 3-5
3.2.2.4 Cargo Tanks 3-6
3.2.3 Model Plants 3-8
3.2.3.1 Loading Racks 3-8
3.2.3.2 Storage Tanks 3-9
3.2.3.3 Cargo Tanks 3-10
3.2.3.4 Pipeline Pumping Stations 3-10
3.2.3.5 Pipeline Breakout Stations 3-11
3.2.3.6 Bulk Gasoline Plants 3-11
3.2.3.7 Bulk Gasoline Terminals 3-12
3.2.4 Activity Data 3-13
3.2.5 Baseline 3-14
3.2.6 Product Recovery 3-16
3.3 Description of Regulatory Options 3-17
3.3.1 GACT6B 3-18
3.3.2 MACTR 3-20
3.3.3 NSPSXXa 3-22
3.4 Emissions Reduction Analysis 3-24
3.4.1 Baseline VOC/HAP Emissions Estimates 3-24
3.4.2 Projected VOC/HAP Emissions Reduction 3-25
3.4.3 Projected Secondary Emissions Increases 3-26
3.5 Engineering Cost Analysis 3-28
3.5.1 Detailed Impacts Tables 3-28
3.5.1.1 GACT6B 3-28
3.5.1.2 MACTR 3-31
3.5.1.3 NSPSXXa 3-33
3.5.2 Summary Cost Tables 3-34
4 Human Health Benefits of Emissions Reductions
4-1
4.1 Introduction 4-1
4.2 Health Effects from Exposure to Hazardous Air Pollutants (HAP) 4-1
Benzene 4-2
Hexane 4-3
Toluene 4-3
2,2,4-Trimethylpentane 4-3
Napthalene 4-4
Ethylbenzene 4-4
Xylenes 4-5
Cumene 4-5
Other Air Toxics 4-5
4.3 VOC-RELATED HUMAN HEALTH BENEFITS 4-6
4.3.1 Estimating Ozone Related Health Impacts 4-6
4.3.1.1 Selecting air pollution health endpoints to quantify 4-7
4.3.1.2 Quantifying Cases of Ozone-Attributable Premature Mortality 4-8
4.3.1.3 Economic Valuation 4-9
4.3.1.4 Benefit-per-Ton Estimates 4-11
4.3.2 Ozone Vegetation Effects 4-13
4.3.3 Ozone Climate Effects 4-13
4.4 VOC-Related Ozone Benefits Results 4-13
4.5 Characterization of Uncertainty in the Monetized VOCBenefits 4-18
4.6 Climate Impacts 4-19
4.7 Total Monetized Benefits 4-38
4
2.1
4
2.2
4
2.3
4
2.4
4
2.5
4
2.6
4
2,7
4
2.8
4
2,9
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5,
Economic Impact Analysis and Distributional Assessments
5-1
5.1 Introduction 5-1
5.2 Economic Impact Analysis 5-1
5.2.1 Description of Approach/Model/Framework 5-2
5.2.1.1 Gasoline MarketModel 5-2
5.2.1.2 Model Baseline 5-3
5.2.1.3 Model Parameters 5-4
5.2.2 Economic Impact Results 5-5
5.2.2.1 Market-Level Results 5-5
5.2.2.2 Welfare Change Estimates 5-5
5.2.2.3 Limitations 5-8
5.3 Small Business Impacts Analysis 5-9
5.3.1 Small Business National Overview 5-10
5.3.2 Small Entity Economic Impacts 5-11
5.3.2.1 Main Screening Analysis 5-11
5.3.2.2 Supplementary Screening Analysis 5-14
5.4 Employment Impact Analysis 5-17
6 Comparison of Benefits and Costs
6-1
6.1 Results 6-1
6.2 Uncertainties and Limitations 6-7
References
7-1
.Appendix A: Detailed Market Impact Tables
8-1
Final Options 8-1
Price Impacts 8-1
Quantity Impacts 8-2
8.2 Less Stringent Alternative Options 8-3
1 Price Impacts 8-3
2 Quantity Impacts 8-4
3 More Stringent Alternative Options 8-5
8.3.1 Price Impacts 8-5
8.3.2 Quantity Impacts 8-6
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LIST OF TABLES
Table 1-1: Current and Final Standards for NESHAP GACT 6B 1-8
Table 1-2: Monetized Benefits, Non-monetized Benefits, Compliance Costs, Emission Changes and Net Benefits
for Final Amendments to GACT 6B, 2027-2041 (million 202 l$)a 1-10
Table 1-3: Current and Final Standards for MACT R 1-11
Table 1-4: Monetized Benefits, Non-monetized Benefits, Compliance Costs, and Emissions Reductions for Final
Amendments to MACT R, 2027-2041 (million 2021$)a 1-12
Table 1-5: Current and Final Standards for NSPS XX and NSPS XXa 1-13
Table 1-6: Monetized Benefits, Non-monetized Benefits, Compliance Costs, and Emissions Changes for Final
NSPS XXa, 2027-2041 (million 202 IS) 1-14
Table 1-7: Monetized Benefits, Non-monetized Benefits, Compliance Costs, and Emissions Changes for Final
NSPS XXa and Final Amendments to MACT R and GACT 6B, 2027-2041 (million 2021$)a 1-16
Table 2-1: Pipeline Shipments PADD to PADD (Thousand Barrels) 2-2
Table 2-2: Bulk Gasoline Terminal Working Capacity (Thousand Gallons) 2-4
Table 2-3: Refiner Gasoline Volume by Sales Type (thousand gallons/day) 2-7
Table 2-4: 15 Largest Gasoline Distribution Parent Companies by Facilities Owned 2-9
Table 2-5: NAICS 424710 - Enterprise Size by Employment (2017) 2-12
Table 2-6: U.S. Gasoline Consumption, 2011-2021 (billion gallons) 2-13
Table 2-7: Motor Gasoline Projected Consumption by Sector, Selected Years (quadrillion BTUs) 2-14
Table 2-8: Gasoline Expenditure as Share of Household Expenditure 2-15
Table 2-9: Gasoline Expenditure as a Share of Household Expenditure by Region (2020-2021) 2-15
Table 2-10: Percentage Change in Gasoline Spending and CPI-U 2-16
Table 2-11: Distribution of Gasoline Consumption by PADD, 2009-2019 2-17
Table 2-12: Gasoline Price by PADD ($2021/gallon) 2-19
Table 2-13: Gasoline Price by Refiner Disposition, Average All Grades ($2021/gallon) 2-20
Table 2-14: AEO 2023 Motor Gasoline Growth Rates by Sector, 2022-2050 2-21
Table 2-15: AEO 2023 Baseline Gasoline Projections, 2027-2041 2-21
Table 3-1: Regulated Facilities by Rule 3-2
Table 3-2: Cargo Tank Vapor-Tightness Certification Standards Examined in this RIA (inches WC) 3-7
Table 3-3: NSPS XXa Projected Affected Facilities, 2027-2041 3-13
Table 3-4: Model Plant Distribution and Configurations 3-14
Table 3-5: Assumed Distribution of Controls at Bulk Plants 3-14
Table 3-6: Current and Final Standards for NESHAP GACT 6B 3-19
Table 3-7: Regulatory Options Examined in this RIA - GACT 6B 3-20
Table 3-8: Current and Final Standards for MACT R 3-21
Table 3-9: Regulatory Options Examined in this RIA - MACT R 3-22
Table 3-10: Current and Final Standards for NSPS XX and NSPS XXa 3-23
Table 3-11: Regulatory Options Examined in this RIA - NSPS XXa 3-24
Table 3-12: Baseline Emissions in 2027 (Short Tons) 3-24
Table 3-13: NSPS XXa Baseline Emissions (Tons), 2027-2041 3-25
Table 3-14: Emissions Reductions for Regulatory Options, Tons per Yearabc 3-26
Table 3-15: Emissions Reductions for Regulatory Options (Tons), NSPS XXa, 2027-2041 3-26
Table 3-16: GACT 6B Secondary Emissions Increases (short tons) 3-27
Table 3-17: NSPS XXa Secondary Emissions Increases, Final/Less Stringent/More Stringent Options (Tons).... 3-27
Table 3-18: Final Options, Detailed Impacts by Emissions Point (peryear), GACT 6B 3-29
Table 3-19: Less Stringent Options, Detailed Impacts by Emissions Point (peryear), GACT 6B 3-30
Table 3-20: More Stringent Options, Detailed Impacts by Emissions Point (peryear), GACT 6B 3-30
Table 3-21: Final Options, Detailed Impacts by Emissions Point (peryear), MACT R 3-31
Table 3-22: Less Stringent Options, Detailed Impacts by Emissions Point (per year), MACT R 3-32
Table 3-23: More Stringent Options, Detailed Impacts by Emissions Point (per year), MACT R 3-32
Table 3-24: Final Options, Detailed Impacts by Emissions Point (2027), NSPS XXa 3-33
Table 3-25: Less Stringent Options, Detailed Impacts by Emissions Point (2027), NSPS XXa 3-33
Table 3-26: More Stringent Options, Detailed Impacts by Emissions Point (2027), NSPS XXa 3-34
Table 3-27: Estimated Annual Costs for Regulatory Options ($2021) 3-35
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Table 3-28: Present and Equivalent Annual Values of Compliance Costs of Regulatory Options, 2027-2041 (million
2021$, discounted to 2024) 3-36
Table 3-29: Discounted Capital and O&M Costs, Final Options, for NSPS XXa, MACT R, and GACT 6B, 2027-
2041 (million 2021$, discounted to 2024) 3-38
Table 3-30: Discounted Costs, Final Options, for NSPS XXa, MACT R, and GACT 6B, 2027-2041 (million 2021$,
discounted to 2024) 3-39
Table 4-1: Human Health Effects of Ambient Ozone 4-8
Table 4-2: Gasoline Distribution: Benefit per Ton Estimates of Ozone-Attributable Premature Mortality and
Illness, 2027-2041 (2021$) 4-14
Table 4-3: Gasoline Distribution GACT 6B: Monetized Benefits Estimates of Ozone-Attributable
Premature Mortality and Illness (million 2021$)a b 4-15
Table 4-4: Gasoline Distribution MACT R: Monetized Benefits Estimates of Ozone-Attributable
Premature Mortality and Illness (million 2021$)a b 4-15
Table 4-5: Gasoline Distribution NSPS XXa: Monetized Benefits Estimates of Ozone-Attributable
Premature Mortality and Illness (million 2021$)a b 4-16
Table 4-6: Gasoline Distribution All Rules: Monetized Benefits Estimates of Ozone-Attributable
Premature Mortality and Illness (million 2021$)a b 4-16
Table 4-7: Gasoline Distribution All Rules, Final Regulatory Options: Undiscounted Monetized Benefits Estimates
of Ozone-Attributable Premature Mortality and Illness (million 2021$) 4-17
Table 4-8: Gasoline Distribution All Rules, Less Stringent Regulatory Options: Undiscounted Monetized Benefits
Estimates of Ozone-Attributable Premature Mortality and Illness (million 2021$) 4-17
Table 4-9: Gasoline Distribution All Rules, More Stringent Regulatory Options: Undiscounted Monetized Benefits
Estimates of Ozone-Attributable Premature Mortality and Illness (million 2021$) 4-18
Table 4-10: Interim Global Social Cost of Carbon Values, 2027-2041 (2021$/Metric Ton CO2) 4-29
Table 4-11: Projected Discounted Global CO2 Disbenefits under the Final Amendments, GACT 6B, 2027-2041
(millions 2021$) 4-34
Table 4-12: Projected Discounted Global CO2 Benefits under the Final Amendments, NSPS XX, 2027-2041
(millions 2021$) 4-35
Table 4-13: Projected Discounted Global Climate Benefits under the Proposed Amendments, NSPS XX, MACT R,
GACT 6B, 2027-2041 (millions, 2021$) 4-36
Table 4-14: Projected Undiscounted Global Climate Benefits under Proposed Amendments, NSPS XX, MACT R,
GACT 6B, 2027-2041 (millions, 2021$) 4-37
Table 4-15: Summary of Monetized Benefits PV/EAV for GACT 6B, 2027-2041, (million 2021$) 4-39
Table 4-16: Summary of Monetized Benefits PV/EAV for MACT R, 2027-2041, (million 2021$) 4-40
Table 4-17: Summary of Monetized Benefits PV/EAV for NSPS XXa, 2027-2041, (million 2021$) 4-41
Table 4-18: Summary of Monetized Benefits PV/EAV for All Rules, 2027-2041, (million 2021$) 4-42
Table 5-1: Description of Gasoline Market Model 5-3
Table 5-2: AEO 2021 Baseline Gasoline Projections, 2027-2041 5-4
Table 5-3: Welfare Impacts of Final Options, 2027-2041 (Discounted to 2024, million 2021$) 5-6
Table 5-4: Welfare Impacts of Less Stringent Alternative Options, 2027-2041 (Discounted to 2024, million 2021$)
5-7
Table 5-5: Welfare Impacts of More Stringent Alternative Options, 2027-2041 (Discounted to 2024, million 2021$)
5-7
Table 5-6: SBA Size Standards by NAICS Code 5-9
Table 5-7: Summary Statistics of Potentially Affected Entities 5-11
Table 5-8: Worst-Case Costs by Model Plant 5-12
Table 5-9: Distribution of Estimated Per-Facility Compliance Costs by Rule and Size for Final Options (2021$) 5-12
Table 5-10: Compliance Cost-to-Sales Ratio Distributions for Small Entities, Final Options 5-13
Table 5-11: Compliance Cost-to-Sales Ratio Thresholds for Small Entities - Final Options 5-13
Table 5-12: NAICS 424710 - Small Entity Impacts 5-16
Table 6-1: Summary of Monetized Benefits, Compliance Costs, and Net Benefits PV/EAV for GACT 6B, 2027-
2041 (million 2021$, discounted to 2024) 6-3
Table 6-2: Summary of Monetized Benefits, Compliance Costs, and Net Benefits PV/EAV for MACT R, 2027-2041
(million 2021$, discounted to 2024) 6-4
Table 6-3: Summary of Monetized Benefits, Compliance Costs, and Net Benefits PV/EAV for NSPS XXa, 2027-
2041 (million 2021$, discounted to 2024) 6-5
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Table 6-4: Summary of Monetized Benefits, Compliance Costs, and Net Benefits PV/EAV for All Rules, 2027-
2041 (million 2021$, discounted to 2024)
Table 8-1: Projected Change in Price, Final Options (2021 cents/gallon of gasoline)
Table 8-2: Projected Percentage Change in Price, Final Options
Table 8-3: Projected Change in Quantity, Final Options (gallons of gasoline)
Table 8-4: Percentage Change in Quantity, Final Options
Table 8-5: Projected Change in Price, Less Stringent Alternative Options (2021 cents/gallon of gasoline)
Table 8-6: Projected Percentage Change in Price, Less Stringent Alternative Options
Table 8-7: Projected Change in Quantity, Less Stringent Alternative Options (gallons of gasoline)
Table 8-8: Percentage Change in Quantity, Less Stringent Alternative Options
Table 8-9: Projected Change in Price, More Stringent Alternative Options (2021 cents/gallon of gasoline)
Table 8-10: Projected Percentage Change in Price, More Stringent Alternative Options
Table 8-11: Projected Change in Quantity, More Stringent Alternative Options (gallons of gasoline)
Table 8-12: Percentage Change in Quantity, More Stringent Alternative Options
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LIST OF FIGURES
Figure 2-1: Petroleum Administration Defense Districts for Retail Gasoline 2-4
Figure 2-2: System of Pipelines, Ports, and Waterways for Petroleum Product Transportation 2-4
Figure 2-3: The Gasoline Distribution System 2-5
Figure 2-4: Gasoline Distribution Physical Structure and Marketing Channels 2-6
Figure 2-5: Price of Gasoline by Component 2-18
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1 EXECUTIVE SUMMARY
1.1 Background
The U.S Environmental Protection Agency (EPA) is finalizing amendments to the
National Emissions Standards for Hazardous Air Pollutants (NESHAP) for Gasoline Distribution
Facilities (40 CFR part 60, subparts R and BBBBBB) and the Standards of Performance for Bulk
Gasoline Terminals (40 CFR part 60, subparts XX and XXa). The EPA is finalizing revisions to
NESHAP requirements for storage tanks, loading operations, and equipment leaks to reflect cost-
effective developments in practices, processes, or controls of hazardous air pollutants (HAP).
The EPA is also finalizing New Source Performance Standards (NSPS) to reflect best system of
emissions reduction (BSER) for emissions of volatile organic compounds (VOC) from loading
operations and equipment leaks at bulk gasoline terminals. This final action also includes
revisions related to emissions during periods of startup, shutdown, and malfunction (SSM);
additional requirements for electronic reporting of performance test results, performance
evaluation reports, and compliance reports; revisions to monitoring and operating requirements
for control devices; and other minor technical improvements. The final amendments would
cumulatively reduce projected emissions of HAP from this source category by over 2,200 short
tons (English tons) per year and would reduce emissions of VOC by 45,400 short tons per year.
The great majority of these projected HAP and VOC emission reductions would occur as a result
of the final area source NESHAP 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, 2016), the EPA prepared a
Regulatory Impact Analysis (RIA) for the proposal of this action that analyzed 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. Prior to the amendments
made by E.O. 14094, the proposal of this rule was significant under E.O. 12866 Section 3(f)(1)
due to its likely annual effect on the economy of $100 million or more in any one year on the
economy, a sector of the economy, productivity, competition, jobs, the environment, public
health or safety, or state, local, or Tribal governments or communities. Specifically, monetized
health benefits from projected VOC reductions associated with the proposed amendments to 40
CFR part 60 subpart BBBBBB exceeded $100 million per year. On April 6, 2023, President
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Biden issued E.O. 14094: Modernizing Regulatory Review, which increased the threshold for
significance under E.O. 12866 Section 3(f)(1) from $100 million to $200 million. This final
action is significant under E.O. 12866 Section 3(f)(1) as amended by E.O. 14094. Accordingly,
the EPA has prepared this Regulatory Impact Analysis (RIA).
1.1.1 NESHAP 40 CFR Part 60, Subparts R and BBBBBB
The statutory authority for the final NESHAP amendments is provided by sections 112
and 301 of the Clean Air Act (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 the EPA to
review standards set under CAA section 112 every 8 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 action,
which finalizes amendments proposed in June 2022.
In the first stage of the CAA section 112 standard setting process, the EPA promulgates
technology-based standards under CAA section 112(d) for categories of sources identified as
emitting one or more of the HAP listed in CAA section 112(b). Sources of HAP emissions are
either major sources or area sources, and CAA section 112 establishes different requirements for
major source standards and area source standards. "Major sources" are those that emit or have
the potential to emit 10 tons per year (tpy) or more of a single HAP or 25 tpy or more of any
combination of HAP. All other sources are "area sources." For major sources, CAA section
112(d)(2) provides that the technology-based NESHAP must reflect the maximum degree of
emission reductions of HAP achievable (after considering cost, energy requirements, and non-air
quality health and environmental impacts). These standards are commonly referred to as MACT
standards. CAA section 112(d)(3) also establishes a minimum control level for MACT standards,
known as the MACT "floor" In certain instances, as provided in CAA section 112(h), the EPA
may set work practice standards in lieu of numerical emission standards. The EPA must also
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consider control options that are more stringent than the floor. Standards more stringent than the
floor are commonly referred to as beyond-the-floor standards. For area sources, CAA section
112(d)(5) allows the EPA to set standards based on generally available control technologies or
management practices (GACT standards) in lieu of MACT standards. For categories of major
sources and any area source categories subject to MACT standards, the second stage in standard-
setting focuses on identifying and addressing any remaining {i.e., "residual") risk pursuant to
CAA section 112(f) and concurrently conducting a technology review pursuant to CAA section
112(d)(6). MACT standards were finalized for the Gasoline Distribution source category in
1994. The residual risk and technology review was finalized in 2006. GACT standards were set
for the Gasoline Distribution area source category in 2008.
The sources affected by the current area source NESHAP for the Gasoline Distribution
source category subpart BBBBBB (GACT 6B) are bulk gasoline terminals, bulk gasoline plants,
and pipeline facilities. A bulk gasoline terminal is defined as "any gasoline storage and
distribution facility that receives gasoline by pipeline, ship or barge, or cargo tank and has a
gasoline throughput of 20,000 gallons per day or greater." A bulk gasoline plant is defined as
"any gasoline storage and distribution facility that receives gasoline by pipeline, ship or barge, or
cargo tank, and subsequently loads the gasoline into gasoline cargo tanks for transport to
gasoline dispensing facilities and has a gasoline throughput of less than 20,000 gallons per day."
A pipeline breakout station is defined as "a facility along a pipeline containing storage vessels
used to relieve surges or receive and store gasoline from the pipeline for re-injection and
continued transportation by pipeline or to other facilities." A pipeline pumping station is defined
as "a facility along a pipeline containing pumps to maintain the desired pressure and flow of
product through the pipeline, and not containing gasoline storage tanks other than surge control
tanks." Emissions from loading racks at large bulk gasoline terminals (those with gasoline
throughput of 250,000 gallons per day or greater) are controlled by vapor collection and
processing systems meeting 80 milligrams total organic carbon (TOC) per liter of gasoline
loaded (mg/L) and the cargo tanks being loaded must be certified to be vapor tight. Small bulk
gasoline terminals and bulk gasoline plants must use submerged filling when loading gasoline.
Emissions from storage vessels with a design capacity greater than or equal to 75 cubic meters
(m3) are controlled by equipment designed to capture and control emissions. Equipment leaks are
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repaired upon detection using audio, visual, and olfactory (AVO) methods. More information on
AVO detection methods can be found in the technical memo for equipment leak control options.1
The sources affected by the current major source NESHAP for the Gasoline Distribution
source category subpart R (MACT R) are bulk gasoline terminals and pipeline breakout stations.
A bulk gasoline terminal is defined as "any gasoline facility which receives gasoline by pipeline,
ship, or barge, and has a gasoline throughput greater than 75,700 liters per day."2 A pipeline
breakout station is defined as "a facility along a pipeline containing storage vessels used to
relieve surges or receive and store gasoline from the pipeline for reinjection and continued
transportation by pipeline or to other facilities." Emissions from loading racks are controlled by
vapor collection and processing systems meeting 10 mg/L and the cargo tanks being loaded must
be certified to be vapor tight. Emissions from storage vessels with a design capacity greater than
or equal to 75 m3 are controlled by equipment designed to capture and control emissions.
Equipment leaks are required to be repaired upon detection using AVO methods.
1.1,2 NSPS 40 CFR part 60, Subpart XX and XXa
The EPA's authority for the NSPS is CAA section 111, which governs the establishment
of standards of performance for stationary sources. CAA section 111(b)(1)(A) requires the EPA
Administrator to list categories of stationary sources that in the Administrator's judgement cause
or contribute significantly to air pollution that may reasonably be anticipated to endanger public
health or welfare. The EPA must then issue performance standards for new (and modified or
reconstructed) sources in each source category pursuant to CAA section 111(b)(1)(B). These
standards are referred to as new source performance standards, or NSPS. The EPA has the
authority under CAA section 111(b) to define the scope of the source categories, determine the
pollutants for which standards should be developed, set the emission level of the standards, and
distinguish among classes, type, and sizes within categories in establishing the standards.
Section 111(b)(1)(B) of the CAA requires the EPA to "at least every 8 years review and,
if appropriate, revise" new source performance standards. Section 111(a)(1) of the CAA provides
1 RTI, 2023. Delang, M., & Coburn, J. (2023). Memorandum to Brenda Shine, EPA/OAQPS. Updated
Control Options for Equipment Leaks at Gasoline Distribution Facilities. EPA-HQ-OAR-2020-0371.
275,700 liters per day is approximately equal to 20,000 gallons per day.
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that performance standards are to "reflect the degree of emission limitation achievable through
the application of the best system of emission reduction which (taking into account the cost of
achieving such reduction and any non-air quality health and environmental impact and energy
requirements) the Administrator determines has been adequately demonstrated." We refer to this
level of control as the best system of emission reduction or "BSER." The term "standard of
performance" in CAA 111(a)(1) makes clear that the EPA is to determine both the BSER for the
regulated sources in the source category and the degree of emission limitation achievable
through application of the BSER. The EPA must then, under CAA section 111(b)(1)(B),
promulgate standards of performance for new sources that reflect that level of stringency. The
NSPS for Bulk Gasoline Terminals was promulgated in 1983.
The sources affected by the current NSPS for the Bulk Gasoline Terminals source
category subpart XX are bulk gasoline terminals that commenced construction or modification
after December 17, 1980. NSPS subpart XX defines bulk gasoline terminals as "any gasoline
facility which receives gasoline by pipeline, ship or barge, and has a gasoline throughput greater
than 75,700 liters per day." Emissions from loading racks at bulk gasoline terminals are
controlled by vapor collection and processing systems meeting 35 mg/L and the cargo tanks
being loaded must be certified to be vapor tight.3 Equipment leaks are required to be repaired
upon detection using AVO methods. Emissions from storage vessels are regulated under a
separate NSPS (40 CFR part 60, subpart K, Ka, or Kb). In June 2022, EPA proposed a new
subpart at 40 CFR part 60: subpart XXa. The proposed standards reflect the best system of
emission reduction (BSER) for loading operations and equipment leaks at bulk gasoline
distribution facilities and apply to all such facilities that commence construction, modification, or
reconstruction after June 10, 2022. In this action, EPA is finalizing this new subpart XXa.
1.2 Market Failure
Many regulations are promulgated to correct market failures, which otherwise lead to a
sub-optimal allocation of resources within a market. Air quality and pollution control regulations
address "negative externalities" whereby the market does not internalize the full opportunity cost
of production borne by society as public goods such as air quality are unpriced.
3 Allowance is provided to meet 80 mg/L for affected facilities with an "existing vapor processing system."
1-5
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While recognizing that the socially optimal level of pollution may not be zero, HAP and
VOC emissions impose costs on society, such as negative health and welfare impacts, that are
not reflected in the market price of the goods produced through the polluting process. For this
regulatory action the good produced is gasoline. If the process of transporting gasoline from
refineries and distributing it to consumers pollutes the atmosphere, the social costs imposed by
the pollution will not be borne by the polluting firm but rather by society as a whole. Thus, the
producer is imposing a negative externality, or a social cost from these emissions, on society.
The equilibrium market price of gasoline may fail to incorporate the full opportunity cost to
society of consuming the gasoline. Consequently, absent a regulation or some other action to
limit emissions, producers will not internalize the negative externality of pollution due to
emissions and social costs will be higher as a result. This regulation will work towards
addressing this market failure by causing affected producers to begin internalizing the negative
externality associated with HAP and VOC emissions.
1.3 Results for the Final Action
1,3,1 Baseline for the Regulation
The impacts of regulatory actions are evaluated relative to a baseline that represents the
world without the regulatory action, which is consistent with the definition stated in the EPA's
Guidelines for Preparing Economic Analyses (U.S. EPA, 2016). In this RIA, the EPA presents
results for the final amendments to NESHAP GACT 6B and MACT R and final NSPS XXa.
Throughout this document, the EPA focuses the analysis on the requirements that result in
quantifiable compliance cost or emissions changes compared to the baseline. For each rule and
most emissions sources, EPA assumed each facility achieved emissions control meeting current
standards and estimated emissions and cost relative to this baseline. We calculate cost and
emissions reductions relative to the baseline for the period 2027-2041. This time frame was
selected because it spans the projected first full year of implementation of the final NESHAP
amendments through the lifetime of the longest-lived capital equipment expected to be installed
as a result of the amendments. NSPS XXa took effect upon proposal in June 2022. Given the
relatively small impacts of NSPS XXa compared to those from the final NESHAP amendments,
we analyze impacts over the period 2027-2041.
1-6
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1.3.2 Differences between the Final and Proposed Action
The amendments to GACT 6B, MACT R, and NSPS XXa are being finalized as
proposed. EPA updated costs and emissions impacts to incorporate changes to the economic
environment since the proposal. Specifically, the interest rate used to annualize capital costs rose
from 3.25% to 7.75% to reflect changes in the bank prime rate, the VOC recovery credit used to
value gasoline product recovery was updated to reflect the 2021 wholesale price of gasoline, and
the dollar-year was updated from 2019 to 2021 to reflect recent inflation. The VOC benefit-per-
ton (BPT) estimates used to monetize VOC emission reductions in Chapter 4 were updated to
reflect the most recent estimates published in January 2023 (U.S. EPA, 2023c). Finally, the
analysis period was adjusted from 2026-2040 to 2027-2041 to account for the final signature of
the action occuring later than originally anticipated.
1.3.3 GACT6B
1.3.3.1 Options Examined in this RIA
The technology review for NESHAP GACT 6B identified improvements in
environmental control technology and emissions performance of loading racks, storage tanks,
equipment leak detection and repair, and cargo tank vapor tightness. As a result, the EPA is
finalizing decisions concerning the technology review to revise requirements for storage tanks,
loading operations, and equipment leaks. The current and final standards for each emissions
source and facility covered by GACT 6B are listed in Table 1-1 below.
1-7
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Table 1-1: Current and Final Standards for NESHAP GACT 6B
Emissions Source
Facility
Current Standard
Final Standard
Loading Racks
Small Bulk Terminal
(<250,000 gallons per day
(gpd), >20,000 gpd)
Large Bulk Terminal
(>250,000 gpd)
Bulk Plant
(< 20,000 gpd)
Submerged fill
80 mg/L
Submerged fill
Submerged fill
35 mg/L
Require vapor
balancing system
Storage Tanks
Regular Tanks
Compliance with NSPS Kb
except for secondary seal
on internal floating roof
(IFR) tanks and some
fittings controls
Require NSPS Kb
fitting controls for
external floating roof
(EFR) Tanks and LEL
monitoring for IFR
Tanks
Surge Control Tanks
Require fixed roof tanks
Require fixed roof tanks
Equipment Leaks
Bulk Terminals, Bulk Plants,
Pipeline Breakout Stations,
Pipeline Pumping Stations
Monthly AVO inspections
Annual instrument
monitoring
Cargo Tank Vapor-
tightness
Bulk Terminals and Bulk
Plants
Maximum allowable
pressure loss during
certification of 3" water
column (WC) for large
bulk terminals only
Maximum allowable
pressure loss during
certification of 0.5" -
1.25" WC
1.3.3.2 Overview of Costs and Benefits for the Final Options
The final amendments to GACT 6B are projected to reduce VOC emissions by about
40,000 short tons per year. VOC emissions, in conjunction with NOx and in the presence of
sunlight, form ground-level ozone (O3). The EPA monetized the projected benefits of reducing
VOC emissions in terms of the value of avoided ozone-attributable deaths and illnesses. The
equivalent annualized value (EAV) of monetized ozone benefits related to VOC emissions
reductions is greater than $100 million per year, as seen in Table 1-2, based on avoided ozone-
attributable deaths and illnesses. The EAV represents a flow of constant annual values that
would yield a sum equivalent to the present value (PV). The maximum estimated undiscounted
benefits occur in 2041 ($170 million).
Table 1-2 also presents projected monetized health benefits, non-monetized benefits,
emissions reductions, climate disbenefits, compliance costs, and net benefits from the final
amendments to GACT 6B. Monetized values are calculated as present values of impacts from
1-8
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2027 through 2041, discounted to 2024 and measured in 2021 dollars. The projected climate
disbenefits are caused by increased electricity usage associated with emissions controls on
loading racks at bulk terminals, which are expected to cause secondary emissions increases of
CO2, NO2, SO2, and CO. Only the disbenefits associated with increased CO2 emissions have
been monetized for this RIA. Certain control options analyzed in this RIA lead to gasoline vapor
recovery, which has been monetized as product recovery credits. Net compliance costs are
calculated as total compliance costs minus product recovery credits. For a discussion of product
recovery, see Section 3.2.6. The net compliance costs of the final amendments to GACT 6B are
negative, meaning the value of projected product recovery exceeds the projected compliance
costs. Net benefits are projected to be positive using both estimates of ozone health benefits and
both 3 percent and 7 percent social discount rates. Further, while benefits from HAP reductions
and VOC reductions outside of the ozone season (May-September) have not been monetized for
this action, EPA expects these benefits are positive. The unmonetized effects also include
disbenefits from secondary emissions increases of NO2, SO2, and CO resulting from increased
electricity usage associated with emissions controls on loading racks at bulk gasoline terminals
and benefits from avoiding reduced growth and/or biomass production in sensitive trees, reduced
yield and quality of crops, visible foliar injury, changed to species composition, and other
changes in ecosystems and associated ecosystem services. As mentioned earlier, we calculate
cost and emissions reductions relative to the baseline for the period 2027-2041.
1-9
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Table 1-2: Monetized Benefits, Non-monetized Benefits, Compliance Costs, Emission
Changes and Net Benefits for Final Amendments to GACT 6B, 2027-2041 (million 2021$4)a
3 Percent Discount Rate 7 Percent Discount Rate
PV
EAV
PV
EAV
$200
$17
$120
$13
Health Benefits'3
and
and
and
and
$1,600
$140
$980
$110
Climate Disbenefits (3%)°
$30
$2.5
$30
$2.5
Net Compliance Costs'1
-$70
-$6.0
-$50
-$5.0
Compliance Costs
$230
$19
$160
$18
Value of Product Recovery
$300
$25
$210
$23
$240
$21
$140
$16
Net Benefits
and
and
and
and
$1,600
$140
$1,000
$110
Emissions Reductions
2027-2041 Total
(short tons)
VOC
605,000
HAP
31,000
Secondary Emissions Increases
(short tons)
2027-2041 Total
C02
490,000
N02
280
S02
0.67
CO
1,300
HAP benefits from reducing 31,000 short tons of HAP from 2027-2041
Climate and health disbenefits of reducing nitrogen oxides (NO2)
by 280 short tons, sulfur dioxide emissions (SO2) by 0.67 short tons,
Non-monetized Benefits and carbon monoxide by 1,300 short tons
from 2027-2041
Visibility effects
Reduced vegetation and ecosystem effects
a Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
b Monetized health benefits include ozone related health benefits associated with reductions in VOC emissions. The health
benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent. The two benefits
estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do not represent lower-
and upper-bound estimates. Disbenefits from additional C02 emissions resulting from application of control options are
monetized and included in the table as climate disbenefits. Benefits from HAP reductions and VOC reductions outside of the
ozone season remain unmonetized and are thus not reflected in the table. The unmonetized effects also include disbenefits
resulting from the secondary impact of an increase in NO2, SO2, and CO emissions. Please see Section 4.6 for more discussion of
the climate disbenefits.
c Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the
social cost of carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent
discount rate). For the presentational purposes of this table, we show the disbenefits associated with the average SC-CO2 at a 3
percent discount rate; please see Table 4-11 for the monetized disbenefits calculated using all four SC-CO2 estimates. Chapter 4
also includes a discussion of the climate disbenefits calculated using a new set of updated SC-CO2 estimates that were presented
in the RIA for EPA's December 2023 final rulemaking on oil and natural gas sector sources.
dNet compliance costs are the engineering control costs minus the value of recovered product. A negative net compliance cost
occurs when the value of the recovered product exceeds the compliance costs.
4 When necessary, dollar figures in this RIA have been converted to 2021$ using the annual GDP Implicit Price
Deflator values in the U.S. Bureau of Economic Analysis' (BEA) NIPA Table 1.1.9 found at found at
.
1-10
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1,3.4 MALT R
1.3.4.1 Options Examined in this RIA
The technology review for NESHAP MACT R identified improvements in environmental
control technology and emissions performance of storage tanks, equipment leak detection and
repair, and cargo tank vapor tightness. As a result, the EPA is finalizing decisions concerning the
technology review to revise requirements for storage tanks, equipment leak detection and repair,
and cargo tank vapor tightness. The current and final standards for each emissions source and
facility covered by MACT R are listed in Table 1-3 below.
Table 1-3: Current and Final Standards for MACT R
Emissions Source
Facility
Current Standard
Final Standard
Loading Racks
Bulk Terminal
10 mg/L
10 mg/L
Storage Tanks
Bulk Terminals and Pipeline
Breakout Stations
Compliance with NSPS
Kb except for some fitting
controls
Require NSPS Kb
fitting controls for
EFR Tanks and LEL
monitoring for IFR
Tanks
Equipment Leaks
Bulk Terminals and Pipeline
Breakout Stations
Monthly AVO
inspections
Semiannual instrument
monitoring
Cargo Tank Vapor-
tightness
Bulk Terminals
Maximum allowable
pressure loss during
certification of 1" - 2.5"
WC
Maximum allowable
pressure loss during
certification of 0.5" -
1.25" WC
1.3.4.2 Overview of Costs and Benefits for the Final Options
Table 1-4 presents projected monetized health benefits, non-monetized benefits,
compliance costs, and emissions reductions from the final amendments to MACT R. Monetized
values are calculated as present values from 2027 through 2041, discounted to 2024 and
measured in 2021 dollars. No secondary emissions impacts are expected from the final
amendments to MACT R because there are no final changes to standards for loading racks at
major source bulk gasoline terminals. Therefore, there are therefore no projected climate or other
disbenefits. Net benefits are projected to be negative using short-term ozone benefits and positive
based on long-term ozone benefits using both a 3 percent and a 7 percent social discount rate.
Also, while benefits from HAP reductions and VOC reductions outside of ozone season have not
been monetized for this action, EPA expects these benefits are positive. Non-monetized benefits
1-11
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also include benefits from avoiding reduced growth and/or biomass production in sensitive trees,
reduced yield and quality of crops, visible foliar injury, changed to species composition, and
other changes in ecosystems and associated ecosystem services. As mentioned earlier, we
calculate cost and emissions reductions relative to the baseline for the period 2027-2041.
Table 1-4: Monetized Benefits, Non-monetized Benefits, Compliance Costs, and Emissions
Reductions for Final Amendments to M AC ! R, 2027-2041 (million 2021$)a
3 Percent Discount Rate
7 Percent Discount Rate
PV
EAV
PV
EAV
$11
$0.89
$6.3
$0.70
Health Benefits'3
and
and
and
and
$87
$7.3
$52
$5.8
Net Compliance Costs0
$22
$1.9
$16
$1.6
Compliance Costs
$38
$3.2
$27
$2.9
Value of Product Recovery
$16
$1.3
$11
$1.3
-$11
-$1.0
-$9.7
-$0.91
Net Benefits
and
and
and
and
$65
$5.4
$36
$4.2
Emissions Reductions
(short tons)
2027-2041 Total
voc
HAP
32,000
2,000
Non-monetized Benefits
HAP benefits from reducing 2,000 short tons of HAP from 2027-2041
Visibility effects
Reduced vegetation and ecosystem effects
a Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
b Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are
associated with several point estimates and are presented at real discount rates of 3 and 7 percent. The two benefits estimates are
separated by the word "and" to signify that they are two separate estimates. The estimates do not represent lower- and upper-
bound estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are
thus not reflected in the table.
c Net compliance costs are the engineering control costs minus the value of recovered product. A negative net compliance cost
occurs when the value of the recovered product exceeds the compliance costs.
1.3.4.3 NSPS XX Options Examined in this RIA
The review of the Standards of Performance for Bulk Gasoline Terminals (NSPS XX)
identified improvements in environmental control technology and emissions performance of
loading racks, equipment leak detection and repair, and cargo tanks. As a result, the EPA is
finalizing NSPS XXa and requirements for loading operations, equipment leaks, and cargo tank
vapor tightness. The current and final standards for each emissions source and facility covered
by NSPS XX and final NSPS XXa are listed in Table 1-5 below.
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Table 1-5: Current and Final Standards for NSPS XX and NSPS XXa
Emissions Source
Facility
Current Standard
Final Standard
Bulk Terminal -
New
35 mg/L
1 mg/L
Loading Racks
Bulk Terminal -
Modified/Recons
tructed
35 mg/L
10 mg/L
Equipment Leaks
Bulk Terminal
Monthly AVO inspections
Quarterly
instrument
monitoring
Maximum
allowable
Cargo Tank Vapor-
tightness
Bulk Terminal
Maximum allowable pressure loss during
certification of 3" water column (WC)
pressure loss
during
certification of
0.5" -1.25" WC
1.3.4.4 Overview of Costs and Benefits for the Final Options
Table 1-6 presents projected monetized benefits, non-monetized benefits, climate
disbenefits, compliance costs, and emissions reductions from the final NSPS XXa. Monetized
values are calculated as present values from 2027 through 2041, discounted to 2024 and
measured in 2021 dollars. The projected climate disbenefits are caused by increased electricity
usage associated with emissions controls on loading racks at bulk terminals, which are expected
to cause secondary emissions increases of CO2, NO2, SO2, and CO. Only the disbenefits
associated with increased CO2 emissions have been monetized for this RIA. Net benefits are
projected to be positive based on both short-term and long-term ozone benefits using both a 3
percent and a 7 percent social discount rate. Also, while benefits from HAP reductions and VOC
reductions outside of ozone season have not been monetized for this action, EPA expects these
benefits are positive. The unmonetized effects also include disbenefits from secondary emissions
increases of NO2, SO2, and CO resulting from increased electricity usage associated with
emissions controls on loading racks at bulk terminal and benefits from avoiding reduced growth
and/or biomass production in sensitive trees, reduced yield and quality of crops, visible foliar
injury, changed to species composition, and other changes in ecosystems and associated
ecosystem services. We calculate cost and emissions changes relative to the baseline for the
period 2027-2041.
1-13
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Table 1-6: Monetized Benefits, Non-monetized Benefits, Compliance Costs, and Emissions
Changes for Final NSPS XXa, 2027-2041 (million 2021$)a
3 Percent Discount Rate
7 Percent Discount Rate
PV
EAV
PV
EAV
$34
$2.8
$19
$2.1
Health Benefits'3
and
and
and
and
$280
$24
$160
$17
Climate Disbenefits (3%)°
$4.9
$0.41
$4.9
$0.41
Net Compliance Costs'1
$2.0
$0.20
$1.0
$0.10
Compliance Costs
$52
$4.4
$34
$3.8
Value of Product Recovery
$50
$4.2
$33
$3.7
$27
$2.2
$13
$1.6
Net Benefits
and
and
and
and
$270
$23
$150
$16
Emissions Reductions
2027-2041 Total
(short tons)
VOC
110,000
HAP
4,400
Secondary Emissions Increases
(short tons)
2027-2041 Total
C02
77,000
N02
45
S02
48
CO
0
HAP benefits from reducing 4,400 short tons of HAP from 2027-2041
Climate and health disbenefits of reducing nitrogen oxides (NO2)
by 45 short tons and sulfur dioxide emissions (SO2) by 48 short tons
Non-monetized Benefits from 2027-2041
Visibility effects
Reduced vegetation and ecosystem effects
a Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
b Monetized health benefits include ozone related health benefits associated with reductions in VOC emissions. The health
benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent. The two benefits
estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do not represent lower-
and upper-bound estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized
and are thus not reflected in the table. The unmonetized effects also include disbenefits resulting from the secondary impact of an
increase in NO2, SO2, and CO emissions. Therefore, monetized climate disbenefits associated with the increased CO2 emissions
are not presented in the benefit-cost analysis of this final action conducted pursuant to E.O. 12866. Please see Section 4.6 for
more discussion of the climate disbenefits.
c Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the
social cost of carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent
discount rate). For the presentational purposes of this table, we show the disbenefits associated with the average SC-CO2 at a 3
percent discount rate; please see Table 4-12 for the monetized disbenefits calculated using all four SC-CO2 estimates. Chapter 4
also includes a discussion of the climate disbenefits calculated using a new set of updated SC-CO2 estimates that were presented
in the RIA for EPA's December 2023 final rulemaking on oil and natural gas sector sources.
dNet compliance costs are the engineering control costs minus the value of recovered product. A negative net compliance cost
occurs when the value of the recovered product exceeds the compliance costs.
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1,3.5 All Rules
Table 1-7 presents projected cumulative impacts for the final NSPS XXa and final
amendments to MACT R and GACT 6B. The cumulative net compliance costs of the final
amendments are negative, meaning the value of projected product recovery exceeds the projected
compliance costs. Net benefits are projected to be positive using both estimates of ozone health
benefits and both 3 percent and 7 percent social discount rates. Further, while benefits from HAP
reductions and VOC reductions outside of ozone season have not been monetized for this action,
EPA expects these benefits are positive. The unmonetized effects also include disbenefits from
secondary emissions increases of NO2, SO2, and CO resulting from increased electricity usage
associated with emissions controls on loading racks at bulk terminals and benefits from avoiding
reduced growth and/or biomass production in sensitive trees, reduced yield and quality of crops,
visible foliar injury, changed to species composition, and other changes in ecosystems and
associated ecosystem services. As mentioned earlier, we calculate cost and emissions changes
relative to the baseline for the period 2027-2041.
1-15
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Table 1-7: Monetized Benefits, Non-monetized Benefits, Compliance Costs, and Emissions
Changes for Final NSPS XXa and Final Amendments to MACT R and GACT 6B, 2027-
2041 (million 2021$)a
3 Percent Discount Rate
7 Percent Discount Rate
PV
EAV
PV
EAV
$240
$20
$140
$16
Health Benefits'3
and
and
and
and
$2,000
$170
$1,200
$130
Climate Disbenefits (3%)°
$35
$2.9
$35
$2.9
Net Compliance Costs'1
-$46
-$3.9
-$33
-$3.3
Compliance Costs
$320
$27
$220
$25
Value of Product Recovery
S3 70
$31
$250
$28
$250
$21
$140
$16
Net Benefits
and
and
and
and
$2,000
$170
$1,200
$130
Emissions Reductions
2027-2041 Total
(short tons)
VOC
740,000
HAP
38,000
Secondary Emissions Increases
(short tons)
2027-2041 Total
C02
570,000
N02
330
S02
49
CO
1,300
Non-monetized Benefits
HAP benefits from reducing 37,000 short tons of HAP from 2027-2041
Climate and health disbenefits of reducing nitrogen oxides (NO2)
by 320 short tons, sulfur dioxide emissions (SO2) by 41 short tons, and
carbon monoxide (CO) by 1,300 short tons from 2027-2041
Visibility effects
Reduced vegetation and ecosystem effects
a Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
b Monetized health benefits include ozone related health benefits associated with reductions in VOC emissions. The health
benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent. The two benefits
estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do not represent lower-
and upper-bound estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized
and are thus not reflected in the table. The unmonetized effects also include disbenefits resulting from the secondary impact of an
increase in NO2, SO2, and CO emissions. Please see Section 4.6 for more discussion of the climate disbenefits.
c Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the
social cost of carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent
discount rate). For the presentational purposes of this table, we show the disbenefits associated with the average SC-CO2 at a 3
percent discount rate; please see Table 4-13 for the monetized disbenefits calculated using all four SC-CO2 estimates. Chapter 4
also includes a discussion of the climate disbenefits calculated using a new set of updated SC-CO2 estimates that were presented
in the RIA for EPA's December 2023 final rulemaking on oil and natural gas sector sources.
dNet compliance costs are the engineering control costs minus the value of recovered product. A negative net compliance cost
occurs when the value of the recovered product exceeds the compliance costs.
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1.4 Organization of this Report
The remainder of this report details the methodology and the results of the RIA. Chapter
2 presents a profile of the gasoline distribution industry. Chapter 3 describes emissions,
emissions control options, and engineering costs. Chapter 4 presents the benefits analysis,
including a qualitative discussion of the unmonetized benefits associated with HAP emissions
reductions and monetization of the disbenefits associated with climate (CO2) emissions
increases. Chapter 5 presents analyses of economic impacts, including impacts on small
businesses. Chapter 6 presents a comparison of benefits and costs. Chapter 7 contains the
references for this RIA. Chapter 8 (Appendix A) presents detailed tables from the market impact
analysis found in Section 5.2.2.
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2 INDUSTRY PROFILE
2.1 Introduction
Gasoline plays an important role in the U.S. economy. According to the Energy
Information Administration (EIA)5, gasoline consumption accounted for 58 percent of
transportation sector energy consumption, 45 percent of petroleum consumption, and 16 percent
of energy consumption in the U.S. in 2021. Over 90 percent of U.S. gasoline consumption fuels
light-duty vehicles. The Gasoline Distribution sector delivers finished motor gasoline and
blending components from petroleum refineries to end-users. Most of the firms in the sector fall
under NAICS classification 424710 (Petroleum Bulk Stations and Terminals) and 486910
(Transportation of Refined Petroleum Products). This section provides an overview of the
gasoline distribution industry. Portions of this section are adapted from the Economic Impact
Analysis for the Gasoline Distribution Industry (Area Sources) (U.S. EPA, 2008).
2.2 Supply Side
Finished gasoline and blending components are shipped from petroleum refineries via
pipeline, tanker, or barge to bulk distribution facilities that store and dispense gasoline. A variety
of downstream marketing arrangements (i.e., wholesale and retail) deliver gasoline to the
consumer. This section contains three parts: an overview of the gasoline distribution network, a
description of the marketing arrangements which deliver gasoline from bulk distribution
facilities to consumers, and a brief examination of industry organization.
2,2.1 The Gasoline Distribution Network
The gasoline distribution network consists of storage and transfer facilities that move
gasoline from its production to its end consumption. Petroleum refineries produce finished motor
gasoline and gasoline blending components from crude oil, which are then shipped via pipeline,
barge, or tanker truck to bulk gasoline distribution terminals. Gasoline is the primary product
produced by petroleum refineries, with each barrel (42 gallons) of crude oil processed into about
5 Energy Information Administration. Gasoline explained: Use of Gasoline.
. accessed 3/7/2023.
2-1
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20 gallons of gasoline.6 The Gulf Coast region is the petroleum refinery center of the U.S., with
the 5 largest refineries operating in either Texas or Louisiana.7
Most gasoline is shipped from the refinery via pipeline (-72 percent in 20218'9), with the
largest flows moving from the Gulf Coast to the East Coast and Midwest and from the Midwest
to the East Coast (see Table 2-1). Figure 2-2 provides a map of the pipeline and water shipping
paths typically used for refined petroleum in the U.S. Along the pipeline, two main types of
facilities regulate the flow of gasoline: pumping stations, which contain pumps used to maintain
the desired pressure and flow of product through the pipeline, and breakout stations, which
contain storage tanks to relieve surges and store product for re-injection and continued
transportation to bulk distribution terminals.
Table 2-1: Pipeline Shipments PADD to PADD (Thousand Barrels)
From
To
2017
2018
2019
2020
2021
East Coast
Midwest
Midwest
East Coast
Gulf Coast
Rocky Mountain
Gulf Coast
East Coast
Midwest
Rocky Mountain
Midwest
West Coast
West Coast
N/A
1,200
4,000
1,400
1,900
36,000
7,600
4,200
3,900
1,000
4,300
1,500
2,600
35,000
7,000
3,700
5,700
990
5,000
1,600
2,500
21,000
7,800
4,200
5,100
1,100
8,100
1,900
2,800
19,000
5,500
5,000
5,000
1,200
9,800
240
1,600
18,000
10,000
4,500
1,600
Source: Energy Information Administration. Movements by Pipeline between Pad Districts.
.
Note: Rounded to two significant digits. Numbers may appear not to add up due to rounding.
6 Energy Information Administration.
. Accessed 1/24/2022.
7 Energy Information Administration. Table 5: Refiners' Total Operable Atmospheric Crude Oil Distillation
Capacity, . accessed 3/7/2023.
8 Energy Information Administration. Movements by Pipeline between PAD Districts.
. accessed 3/7/2023.
9 Energy Information Administration. Movements by Pipeline, Tanker, Barge, and Rail between PAD Districts.
. Accessed 3/7/2023.
2-2
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Once at a bulk distribution terminal, finished gasoline is transferred directly to a storage
tank, while blending components may first be mixed to produce fuel of a desired specification.
Due to its proximity to large population centers, the largest volume of bulk gasoline storage
capacity is in the East Coast Petroleum Administration Defense District (PADD)10 (see Table
2-2), followed by the Gulf Coast PADD. Gasoline is loaded via loading racks from storage tanks
into large tanker trucks or railcars cargo tanks (typically 8,000-10,000-gallon capacity), which
transport gasoline either to retail stations for final sale to consumer or intermediate storage
facilities called bulk plants. Bulk plants store gasoline and transfer it via loading rack to tanker
trucks for transport to retail gasoline stations or end consumers. They are similar in structure to
bulk distribution terminals but contain less storage capacity and handle less throughput. See
Figure 2-3 for a general depiction of the gasoline distribution network.
PADD 4: PADD 2: padd ia. ^
Z cky Midwest m.
England
'Mjm PADD IB^ Mr
MB S^-lr
Coast
padds ~ wL
West Coast ^^3 TX MjlHI BP Lower
PADD 3: m
^ Gulf Coast
- ^ eia^
PADD - Petroleum Administration for Defense Distncts
10 The Petroleum Administration for Defense Districts (PADDs) are geographic aggregations of the 50 States and
the District of Columbia into five districts: PADD 1 is the East Coast. PADD 2 the Midwest, PADD 3 the Gulf
Coast, PADD 4 the Rocky Mountain Region, and PADD 5 the West Coast. For a map of PADD districts, see
Figure 2-1.
2-3
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Figure 2-1: Petroleum Administration Defense Districts for Retail Gasoline
Source: U.S. Energy Information Administration
Table 2-2: Bulk Gasoline Terminal Working Capacity (Thousand Gallons)
Year
East Coast
Midwest
Gulf Coast
Rocky Mountain
West Coast
U.S.
Total
2011
71,000
51,000
50,000
3.900
25,000
200,000
2012
74,000
50,000
54,000
3,900
24,000
210,000
2013
77,000
51,000
56,000
3.900
24,000
210,000
2014
80,000
51,000
58,000
3,800
24,000
220,000
2015
82,000
50,000
59,000
3,800
24,000
220,000
2016
84,000
50,000
55,000
3,900
24,000
220,000
2017
84,000
51,000
60,000
4,100
25,000
220,000
2018
84,000
52,000
62,000
4,100
25,000
230,000
2019
87,000
52,000
66,000
4,100
26,000
240,000
2020
89,000
52,000
74,000
4,100
24,000
240,000
2021
91,000
54,000
73,000
4,100
26,000
250,000
2022
87,000
54,000
74,000
4,200
25,000
240,000
Source: Energy Information Administration, Form ElA-815 "Monthly Bulk Terminal and Blender Report",
2011-2020.
Note: Rounded to two significant digits. Numbers may appear not to add up due to rounding.
Petroleum products
(pipelines, ports, waterways)
«j> *
J ' —< ~r\ >
— v.
I %
I \ n ! V /A I a
i \ \ . \ / vN \ l /
u N1 KD) ¦ '
\ \ S T Af 1V S S> . L
•%' ' - — i ¦ a // , m -vTT -.. y x v * j
, > V ( f '/-> r+? T w
v" t * ^ s r 'y
» \\ ' / t -X- *•» S,V * *
\ , ¦ *1- »
\ r* *r-* ' <>A.r- ' Tr ^ -
¦ 7 ~
Figure 2-2: System of Pipelines, Ports, and Waterways for Petroleum Product
Transportation
Source: U.S. Energy Information Administration
2-4
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imported crude oil ^rage
tanker
or barge
£"1
\ __ » —ft.—
refinery A I tanker truck gas station
pipeline!
domestic pipeline
crude oil
JB bulk 1 _ _
~terminal J —, rffiPO
storage common storage 00 00
pipeline tanker truck 9 station
ifi&B/
refinery B "f,k"ru^
«0
or barge
refinery
storage
imported crude oil
Source: U.S. Energy Information Administration eia^
Figure 2-3: The Gasoline Distribution System
Source: U.S. Energy Information Administration11
2,2.2 Downstream Marketing Arrangements for Refined Petroleum Products
Once refined petroleum products leave the refinery, they reach consumers through one or
more marketing channels. This final step in the supply of refined petroleum products includes
two components: wholesale distribution (from product terminals to retail outlets) and retail
distribution (to final consumers). Truck transportation is the most common delivery method of
gasoline to retail outlets.
There are four primary gasoline marketing channels for wholesale distribution of
gasoline. Three of these constitute direct distribution of product:
• Refiner-operated retail outlet: Refiners directly distribute gasoline to their own retail outlets.
• Lessee dealer: Retail outlets are owned by the wholesale distributor but leased to a gasoline
dealer.
• Independent retailer: Retail outlets are owned and operated by independent "open" dealers.
The fourth channel comprises indirect distribution of product:
11 See .
2-5
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• Jobber: Distributors purchase directly from refiners and then sell products to retail outlets.
The variety of marketing channels illustrates that firms are not all vertically integrated;
that is, they are not involved in all stages of gasoline operations from gasoline production,
distribution, and ultimate sales to consumers (see Figure 2-4). Table 2-3 shows data for refiner
disposition of gasoline by volume to the bulk (sales by contract larger than a truckload), dealer
tankwagon (DTW) (price set by the refiner for a truckload of gasoline delivered to a retail
gasoline station), and rack (rack sales distributed to jobbers) levels. An increasing percentage of
gasoline is being though rack sales to jobbers, with -84 percent sold via that method in 2021.
Physical Structure
Pipeline
(Barge. Rail)
Marketing Channels
Refiner-
operated
Retail
Lessee
Dealer
Retail Price
Consumer
Consumer
Jobber
Jobber
Consumer
Independent
Retailer
Refinery
Port
Refiner
Refiner
Refiner
Refiner
Rack Price
Independent
Retailer
Dealer
Dealer
1
I
1
Retail Price
i
1
Retail Price
J
Consumer
Figure 2-4: Gasoline Distribution Physical Structure and Marketing Channels
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2003. "2003 California Gasoline
Price Study: Final Report." Washington, DC: U.S. Department of Energy, Energy Information
Administration.
2-6
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Table 2-3: Refiner Gasoline Volume by Sales Type (thousand gallons/day)
Year DTW Rack Bulk Total Wholesale
2011
30,000
230,000
33,000
290,000
2012
27,000
240,000
28,000
300,000
2013
28,000
240,000
25,000
290,000
2014
24,000
240,000
21,000
290,000
2015
23,000
250,000
22,000
300,000
2016
23,000
260,000
21,000
300,000
2017
22,000
260,000
18,000
300,000
2018
22,000
260,000
20,000
300,000
2019
21,000
270,000
15,000
310,000
2020
17,000
230,000
9,100
260,000
2021
20,000
260,000
8,500
310,000
Source: Energy Information Administration. U.S. Motor Gasoline Refiner Sales Volume.
. 3/7/2023.
Note: Rounded to two significant digits. Numbers may appear not to add up due to rounding.
2,2.3 Industry Organization
EPA constructed a facility list for the Gasoline Distribution source category based on the
2017 National Emissions Inventory (NEI), the Toxics Release Inventory, information from the
original Gasoline Distribution NESHAP, a bulk terminal list of petrochemical storage facilities
from the Internal Revenue Service, the Office of Enforcement and Compliance Assurance's
Enforcement and Compliance History Online (ECHO) tool (https://echo.epa.gov), and the
Energy Information Administration (EIA). This created an initial list of 1,838 facilities in the
Gasoline Distribution source category (hereafter referred to as the "facility list"). The
construction of the facility list is described in the preamble for the proposal of this action. EPA
ultimately identified the ultimate parent company along with revenue and employment
information for 1,705 facilities on the list.12 While this facility list does not cover all facilities in
the sector, it is useful to provide a broad overview. This section provides background on the
ultimate parent companies that own the facilities comprising EPA's list.
2.2.3.1 Concentration and Vertical Integration
Table 2-4 lists the revenue and employment information for the 15 companies in the
Gasoline Distribution sector that own the most facilities. Collectively, these firms own -52
percent of the facilities on the list and averaged $93 billion in revenue in 2020 (measured in
12 Revenue and employment information was collected through manual search of D&B Hoover's database in 2021.
For the purposes of the final rule, revenues were adjusted to dollar-year 2021.
2-7
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2021$). All these firms are multinational in operation and vertically integrated, operating in at
least two of the following sectors: petroleum extraction, petroleum refining, refined petroleum
product transportation, refined petroleum product storage and distribution, or refined petroleum
sales. The first two firms on the list provide good examples. Buckeye Partners is heavily active
in both transportation and storage of refined petroleum products, owning over 6,000 miles of
pipeline and over 100 petroleum product terminals.13 Marathon Petroleum Corporation is
vertically integrated along most of the gasoline supply chain, owning refineries, pipeline
facilities, bulk petroleum terminals, and retail gasoline stations.14 In addition to providing
transport and storage of gasoline, at least 8 of these companies also engage in major petroleum
refining or extraction operations (Marathon Petroleum Corporation, Phillips 66, Citgo, Royal
Dutch Shell, Koch Industries, Chevron, Saudi Aramco, and Exxon Mobil). The top 50 ultimate
parent companies on the Facility List own 79 percent of the facilities on the list and averaged
$46 billion in revenue in 2020, with a minimum company revenue of $47 million (in 2021$).
This shows that the Gasoline Distribution sector is characterized by a substantial degree of
vertical integration and is suggestive of a moderately concentrated industry (while there are
many active firms, a small minority of them control more than half the market).
13 , accessed 1/20/2022.
14 , accessed 1/20/2022.
2-8
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Table 2-4: 15 Largest Gasoline Distribution Parent Companies by Facilities Owned
Company
2020 Revenue
(million 2021$)
2020 Employment
Facilities Owned
Hercules Intermediate Holdings LLC
(Buckeye Partners LP)
$4,300
1,800
125
Marathon Petroleum Corporation
$130,000
60,000
117
Kinder Morgan Inc
$11,000
10,000
97
Magellan Midstream Partners
$2,500
1,800
91
Energy Transfer LP
$40,000
12,000
65
NGL Energy Partners LP
$7,800
1,400
65
Nustar Energy LP
$1,500
1,400
59
Phillips 66
$68,000
14,000
54
PDV America Inc
$27,000
4,100
48
(Citgo)
Royal Dutch Shell
$360,000
83,000
36
Koch Industries
$120,000
100,000
30
Chevron Corporation
$98,000
48,000
26
Apex Holding Company
$220
1,200
26
Saudi Aramco
$340,000
68,000
25
Exxon Mobil Corporation
$190,000
74,000
25
Source: EPA Gasoline Distribution Facility List, D&B Hoover's Database.
The National Renewable Energy Laboratory (NREL) (2016) used non-public data from the Oil
Price Information Service (OPIS) to characterize terminal ownership by five company types
(major examples of the company type described in parentheses):
• Oil: Vertically integrated companies that explore and drill for oil and refine it. These
companies may also own pipelines (Chevron).
• Pipeline: Companies that own pipelines and lease storage space to customers at terminals
(Buckeye Partners, Kinder Morgan, Magellan)
• Refinery: Companies that own refineries and terminals. These companies may also own
pipeline (Marathon Petroleum, Royal Dutch Shell, Saudi Aramco, Phillips 66).
• Terminal: Companies that own one or more terminals, but do not own pipelines or
refineries.
• Other
2-9
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NREL found that, while comprising only 55 companies, firms in the Oil, Pipeline, and Refinery
groups owned about 65 percent of terminals and about 70 percent of terminal capacity. Terminal
companies owned roughly 31 percent of terminals and 29 percent of capacity, with the remainder
of both owned by firms in the Other category.
2.2.3.2 Entry Barriers
Entry into the pipeline business requires significant capital investments. In addition, it
often takes years to acquire the necessary approvals and complete construction of a new pipeline.
An entrant into product terminals is faced with relatively high capital costs to acquire and install
storage tanks and to design, acquire, and install a loading rack. Once operating, however,
terminals exhibit scale economies, because as storage volume increases, the cost of operating
declines. Other entry barriers for terminals include zoning and environmental permit issues,
which can make the time span for opening a new terminal lengthy. One deterrent to entry into
product terminals is excess capacity. Existing capacity can meet periods of high terminal demand
without large price increases for terminal service; incentives to invest in new terminal capacity
tend to be reduced without these price signals.
2.2.3.3 Employment
The US Census Bureau collects data on NAICS classifications 424710 (Petroleum Bulk
Stations and Terminals) and 486910 by enterprise size (see Table 2-5 for NAICS 424710; data
on NAICS 486910 is very noisy due to the small number of firms, so we report aggregates
below). This information does not reflect ultimate ownership and does not provide complete
coverage of bulk gasoline storage and transportation facilities, but still provides a reasonable
guide to the number of facilities and the employment level in the sector. In 2017, approximately
66,000 people were employed in about 4,000 establishments classified as Petroleum Bulk
Stations and Terminals (NAICS 424710) by the US Census. This is down from 2012, when the
Census reported 74,600 people employed in about 4,500 establishments.15 In combination with
Table 2-2, which reports increasing terminal storage capacity per facility over time, this suggests
15 US Census Bureau. County Business Patterns 2012 and Economic Census 2012.
. Accessed 1/24/2022.
2-10
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consolidation in gasoline storage and transportation as facilities close and existing facilities
expand capacity (evidence of the economies of scale discussed in the previous section).
About 4,700 people were employed in 675 establishments classified as engaging in
Transportation of Refined Petroleum Products (NAICS 486910).16 This is roughly flat from 2012
(4,960 people employed in 560 establishments).17 Taken together approximately, about 71,000
people are employed in the Gasoline Distribution sector across NAICS 424710 and NAICS
486910, although this may miss employment at some smaller bulk plants that are not large
enough to be classified under NAICS 424710 or facilities which engage in bulk storage and
transportation of gasoline as a secondary business function.
16 US Census. County Business Patterns 2017 and Economic Census 2017.
. Accessed 1/24/2022.
17 US Census Bureau. County Business Patterns 2012 and Economic Census 2012.
. Accessed 1/24/2022.
2-11
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Table 2-5: NAICS 424710
- Enterprise Size by Employment (2017)
Enterprise Size
Firms
Establishments
Employment
Average
Receipts
(million
2021$)
<5 employees
508
511
1,099
$5.4
5-9 employees
415
425
2,731
$23
10-14 employees
267
292
2,922
$31
15-19 employees
144
170
2,126
$37
20-24 employees
121
139
2,233
$52
25-29 employees
83
102
1,708
$37
30-34 employees
65
76
1,546
$59
35-39 employees
60
79
1,788
$74
40-49 employees
92
123
2,766
$56
50-74 employees
115
176
4,552
$250
75-99 employees
76
145
3,834
$380
100-149 employees
83
159
4,344
$110
150-199 employees
57
136
3,819
$260
200-299 employees
69
169
4,267
$140
300-399 employees
27
77
3,719
$440
400-499 employees
15
65
2,131
$590
500-749 employees
36
96
3,422
$1,400
750-999 employees
16
85
1,511
$1,200
1,000-1,499 employees
22
157
2,449
$650
1,500-1,999 employees
7
232
1,800
$1,100
2,000-2,499 employees
6
35
1,092
$4,600
2,500-4,999 employees
20
206
4,212
$3,500
5,000+ employees
30
295
6,190
$10,000
Source: US Census. County Business Patterns 2017 and Economic Census 2017.
. Accessed 1/24/2022.
Note: Based on Census definitions, an establishment is a physical location at which business is conducted or
services/industrial operations are performed. A firm is a business organization consisting of one or more
domestic establishments in the same geographic area and industry that were specified under common
ownership or control. An enterprise may have establishments in many different industries, so employment for
an enterprise within NAICS 424710 may be lower than total employment at an enterprise.
2.3 Demand Side
Table 2-6 below shows U.S. gasoline consumption from 2011 to 2021. The U.S.
consumed about 135 billion gallons of gasoline in 2021. The Federal Highway Administration
(FWHA) distinguishes gasoline consumption by use: highway and nonhighway. In 2021, about
2-12
-------
92 percent was consumed for highway use. The remaining 8 percent is for nonhighway use (i.e.,
lawn and garden equipment and marine uses).18
Table 2-6: U.S. Gasoline Consumption, 2011-2021 (billion gallons)
Year
Quantity
2011
134.18
2012
133.10
2013
135.56
2014
136.76
2015
140.70
2016
142.82
2017
142.98
2018
143.01
2019
142.71
2020
123.39
2021
135.15
Source: Energy Information Administration,
https://www.eia.gov/dnav/pet/PET_SUM_SNDW_A_EPMOF_VPP_MBBLPD_W.htm, 3/7/2023.
The Energy Information Administration projects motor gasoline consumption by sector in
their "Annual Energy Outlook 2023" (AEO 2023). This structure is consistent with the National
Energy Modeling System (NEMS) used to generate forecasts for AEO 2023. Motor gasoline
consumption is classified by three end-use sectors:
• Commercial: Commercial-sector consumption encompasses business
establishments that are not engaged in industrial or transportation activities.
• Industrial: The industrial sector includes energy consumption for fuels and
feedstocks for 15 manufacturing industries and 6 nonmanufacturing industries.
This includes agriculture, mining, construction, and manufacturing industries.
• Transportation: The transportation sector includes consumption of transportation-
sector fuels by transportation mode (light-duty vehicle, air travel, freight transport).
18 Department of Transportation. Federal Highway Administration. Highway Statistics 2021. Available here:
2-13
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The NEMS Transportation Sector Demand Module models a variety of vehicle types,
sizes, fuels, and technology configurations for each class of transportation.
Transportation consumes the bulk of gasoline energy usage, and this is projected to continue
over the next two decades as shown below in Table 2-7. Demand from light-duty vehicles is
projected to fall by about 1 percent per year through 2050, as electric vehicles gain market share.
Table 2-7: Motor Gasoline Projected Consumption by Sector, Selected Years (quadrillion
BTUs)
Sector
2023
2028
2033
2038
2040
Commercial
0.39
0.39
0.39
0.39
0.39
Industrial
0.29
0.29
0.28
0.29
0.30
Transportation
15.81
14.69
13.58
12.86
12.61
Light-duty vehicles
14.44
13.42
12.23
11.42
11.11
Commercial light trucks
0.65
0.62
0.62
0.63
0.65
Recreation Boats
0.16
0.15
0.15
0.14
0.14
Freight Trucks
0.61
0.62
0.65
0.68
0.71
Transit and school buses
0.02
0.02
0.02
0.02
0.02
Source: Energy Information Administration. Annual Energy Outlook 2023. Table 2 and Table 36. March 16,2023.
. Accessed 3/17/2023.
Transportation choices are a function of tastes, income, gasoline prices, and prices of
related goods. Personal automobiles and trucks are the dominant mode of travel in U.S.,
accounting for about 87 percent of passenger miles traveled in 2019.19 According to the Bureau
of Labor Statistics' Consumer Expenditure Survey, the share of household expenditure was flat
from 2016 to 2019 at around 3.3 percent (see Table 2-8) but fell to 2.6 percent from 2019 to
2020 as people reduced travel during the COVID-19 pandemic.20 Consumer expenditure on
gasoline rebounded to very close to its previous level in 2021. The expenditure share is similar
across region (see Table 2-9), with consumers in the northeast spending a slightly smaller share
of income on gasoline in 2020-2021. There is also a seasonality to gasoline demand, with both
19 University of Michigan Center for Sustainable Systems. Personal Transportation Factsheet. 2021.
.
20 Bureau of Labor Statistics. Consumer Expenditure Survey. .
Accessed 1/21/2022.
2-14
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the quantity of gasoline consumed and the price of gasoline tending to rise through the spring
and peak at the end of summer.21
Table 2-8: Gasoline Expenditure as Share of Household Expenditure
Year
Expenditure Share
2017
3.3%
2018
3.4%
2019
3.3%
2020
2.6%
2021
3.2%
Source: U.S. Bureau of Labor Statistics. Consumer Expenditure Surveys
2017-2021. September 2020. . Accessed 3/10/2023.
Table 2-9: Gasoline Expenditure as a Share of Household Expenditure by Region (2020-
2021)
All Consumer Units, United States
2.9%
Northeast
2.3%
Midwest
2.9%
South
3.2%
West
2.9%
Source: U.S. Bureau of Labor Statistics. Consumer Expenditure Survey.
. September 2021. Accessed
1/24/2022.
Gasoline expenditure is largely driven by price changes. Table 2-10 shows the percentage
change in gasoline expenditure along with the percentage in a price index for gasoline (CPI-U
Gasoline). The table shows both the price of gasoline is relatively volatile year-to-year, and
gasoline expenditure changes roughly proportionally with price. This suggests that consumer
demand for gasoline is relatively inelastic (that is, the percent change in consumer demand is
somewhat less than the percent change in price). This is in line with the research on the price
elasticity of demand for gasoline (see Section 5.2.1.3).
21 Energy Information Administration. Gasoline explained: gasoline price fluctuations. 9/9/2021.
. Accessed 1/20/2022.
2-15
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Table 2-10: Percentage Change in Gasoline Spending and CPI-U
Year
Gasoline Expenditure
CPI-U
Gasoline
2008
14.6
16.1
2009
-26.8
-26.9
2010
7.1
18.3
2011
24.6
26
2012
3.9
3.3
2013
-5.0
-2.9
2014
-5.5
-4.0
2015
-15.9
-27.2
2016
-9.2
-11.3
2017
3.1
13.1
2018
8.1
13.4
2019
-1.2
-3.5
2020
-24.8
-16.3
2021
29.1
36
Source: U.S. Bureau of Labor Statistics. Consumer Expenditure Survey 2008-2019.
. Accessed 3/10/2023.
Consumers can respond to price changes in gasoline in two general ways. First, they may
reduce the number of vehicle miles traveled. If the relative price of gasoline remains higher for
long periods, consumers may also consider adjusting their vehicle choice or home location to
mitigate the effects of higher prices. For example, they may purchase vehicles with better fuel
economy or buy a home closer to work or shopping. It is also likely that current trends towards
increased remote work spurred by the COVID-19 pandemic allow greater flexibility with respect
to commuting, which could cause people to be more responsive to gasoline prices. They could
also switch from gasoline-power vehicles to alternative modes of transportation such as mass
transit and/or switch to vehicles that use alternative fuels, such as electric or hybrid-electric
vehicles. Electric and hybrid-electric vehicles, while currently owned by about 7 percent of U.S.
car owners, constitute a growing share of the U.S. market; registrations of such vehicles
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increased almost four-fold from 2016 to 2021.22 AEO 2023 projects electric vehicle market share
to rise to about 20 percent by 2050.23
2.4 Market Conditions
2,4,1 Consumption
American consumption of gasoline increased about 3.5 percent from 2009 to 2019 and
was roughly flat from 2016 to 2019. Gasoline consumption fell sharply from 2019 to 2020 but
largely rebounded in 2021 (see Table 2-6). Table 2-11 shows the geographic distribution of
consumption by PADD. This distribution was very stable over the period, with the largest share
occurring in the East Coast PADD (34 percent in 2021).
Table 2-11: Distribution of Gasoline Consumption by PADD, 2009-2019
Year
East Coast
Midwest
Gulf Coast
Rocky Mountain
West Coast
2009
36%
28%
15%
3%
17%
2010
36%
28%
15%
3%
17%
2011
34%
29%
15%
3%
17%
2012
34%
28%
15%
3%
17%
2013
34%
29%
17%
3%
17%
2014
33%
28%
16%
3%
17%
2015
35%
28%
16%
4%
17%
2016
35%
29%
16%
4%
17%
2017
35%
29%
15%
4%
18%
2018
35%
29%
15%
4%
18%
2019
35%
29%
15%
4%
17%
2020
34%
30%
15%
4%
17%
2021
34%
29%
14%
4%
17%
Source: Energy Information Administration. Supply and Disposition.
. 4/30/2021.
2.4,2 Prices
The price of gasoline includes the cost of crude oil, distribution and marketing, refining
costs and profits, and federal and state taxes (see Figure 2-5), with the cost of crude oil
22 Desilver, Drew. Today's electric vehicle market: Slow growth in U.S., faster in China, Europe. Pew Research
Center. 6/7/2021. . Accessed 1/24/2022.
23 Source: Energy Information Administration. Annual Energy Outlook 2023. AEO 2023 Release Presentation.
March 16, 2023. < https://www.eia.gov/outlooks/aeo/pdf/AEO2023_Release_Presentation.pdi>. Accessed
4/13/2023.
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accounting for the largest share (56 percent on average from 2011 to 2020). The other
components tend to make of roughly equal shares. The Energy Information Administration24
reports that as of January 2023 federal excise taxes on gasoline were 18.4 cents per gallon, with
state excise taxes averaging 31.6 cents per gallon. States taxes vary widely, from a low of 8 cents
per gallon in Alaska to a high of 58 cents per gallon in Pennsylvania in 2021.25 In total, taxes
account for about 17 percent of the price of gasoline, with the cost of crude oil (51 percent),
distribution and marketing (15 percent), refining costs and profits (15 percent) accounting for the
remainder.
2013-2022
average retail price
$2.83/gallon
2022
average retail price
$3.95/gallon
14.5%
14.6%
17.1%
53.9%
refining costs
and profits
distribution
and marketing
federal and
state taxes
crude oil
17.7%
12.4%
12.8%
57.1%
Figure 2-5: Price of Gasoline by Component
Source: Energy Information Administration. Gasoline and Diesel Fuel Update.
Gasoline prices also vary geographically (see Table 2-12). The main sources of variation
in price by region are state taxes and distance from Gulf Coast petroleum refineries. Gasoline is
24 Energy Information Administration.
. Accessed 3/10/2023.
25 Federal Highway Administration. Highway Statistics Series 2021. . Accessed 3/10/2023.
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cheapest in the Gulf Coast region and increases in price as it travels north and up the East Coast.
Prices are highest on the West Coast, where gasoline taxes are high and pipeline access to Gulf
Coast refineries is poor. Certain regions are also required to sell reformulated gasoline in the
ozone season due to elevated levels of smog (ozone) and HAP. Reformulated gasoline tends to
cost 30 to 35 cents more per gallon than conventional26, with reformulated gasoline sales
concentrated on the West Coast and in dense, urban areas.
Table 2-12: Gasoline Price by PADD ($2021/gallon)
Year
U.S.
East Coast
Midwest
Gulf
Coast
Rocky
Mountain
West
Coast
2009
$3.01
$3.00
$2.93
$2.85
$2.92
$3.86
2010
$3.51
$3.49
$3.44
$3.34
$3.48
$4.69
2011
$4.33
$4.34
$4.28
$4.15
$4.20
$4.83
2012
$4.38
$4.39
$4.29
$4.14
$4.22
$4.55
2013
$4.18
$4.21
$4.11
$3.94
$4.07
$4.33
2014
$3.94
$3.98
$3.85
$3.69
$3.89
$3.49
2015
$2.86
$2.82
$2.74
$2.56
$2.82
$3.00
2016
$2.53
$2.53
$2.41
$2.28
$2.49
$3.31
2017
$2.79
$2.80
$2.65
$2.53
$2.76
$3.73
2018
$3.03
$2.98
$2.87
$2.73
$3.09
$3.69
2019
$2.85
$2.74
$2.69
$2.49
$2.90
$3.09
2020
$2.36
$2.30
$2.18
$2.01
$2.45
$3.97
2021
$3.10
$3.01
$2.94
$2.76
$3.29
$5.07
Source: Energy Information Administration. Weekly Retail Gasoline and
Diesel Prices. 1/3/2022.
. Accessed 1/24/2022.
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disposition. DTW prices include transportation costs and are thus higher than bulk (sales on
contract larger than one truckload) and rack prices.
Table 2-13: Gasoline Price by Refiner Disposition, Average All Grades ($2021/gallon)
Year
DTW
Rack
Bulk
2009
$2.38
$2.20
$2.10
2010
$2.83
$2.67
$2.57
2011
$3.62
$3.47
$3.35
2012
$3.71
$3.47
$3.40
2013
$3.44
$3.27
$3.24
2014
$3.21
$2.99
$2.92
2015
$2.44
$1.93
$1.85
2016
$1.97
$1.61
$1.54
2017
$2.22
$1.84
$1.81
2018
$2.60
$2.10
$2.09
2019
$2.58
$1.92
$1.84
2020
$1.96
$1.35
$1.27
2021
$2.80
$2.15
$2.09
Source: Energy Information Administration. Refiner Gasoline Prices by Grade and Sales Type. 3/10/2023.
. Accessed 1/24/2022.
2.4,3 Trends and Projections
AEO 2023 estimates that the average annual growth rate for gasoline consumption will
be negative (-0.7 percent) from 2022-2050, driven by a fall in demand for gasoline from light-
duty vehicles. As shown in Table 2-14, increases in commercial and industrial gasoline usage is
projected to be swamped by a decrease in transportation usage, driven by a decrease in gasoline
consumption by light-duty vehicles. Table 2-15 contains gasoline price and quantity projections
from 2027-2041. These years, as discussed in chapter 3, comprise the baseline period of analysis
for this RIA. Gasoline prices rose by about a dollar per gallon on average from 2021 to 2022
($3.02 to $3.97) according to the Energy Information Administration's Short-Term Energy
Outlook (STEO).27 The STEO is currently projecting an average price per gallon of $3.36 in
2023 and $3.11 in 2024.
27 Energy Information Administration. Short Term Energy Outlook, .
1/11/2022.
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Table 2-14: AEO 2023 Motor Gasoline Growth Rates by Sector, 2022-2050
Sector
Average Annual Growth Rate
Commercial
0.0%
Industrial
0.3%
Transportation
-0.8%
Light-duty vehicles
-0.9%
Commercial light trucks
0.2%
Recreation Boats
-0.6%
Freight Trucks
0.9%
Transit and school buses
-0.3%
Total
-0.7%
Source: Energy Information Administration. Annual Energy Outlook 2023. Table 2 and Table 36. March 16, 2023.
. Accessed 3/17/2023.
Table 2-15: AEO 2023 Baseline Gasoline Projections, 2027-2041
Year
Price
($2022/gallon)
Quantity
(billion gallons)
2027
2.85
129.98
2028
2.85
128.32
2029
2.86
126.44
2030
2.87
124.42
2031
2.86
122.51
2032
2.88
120.68
2033
2.89
119.20
2034
2.90
117.92
2035
2.90
116.66
2036
2.93
115.37
2037
2.93
114.29
2038
2.94
113.36
2039
2.95
112.52
2040
2.96
111.91
2041
2.96
111.41
Source: Energy Information Administration. Annual Energy Outlook 2023. Table 12. March 16, 2023.
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3 EMISSIONS AND ENGINEERING COSTS ANALYSIS
3.1 Introduction
In this chapter, we present estimates of the projected emissions changes (reductions and
increases) and engineering compliance costs associated with the final action for the 2027 to 2041
period. There are two main components to the analysis of HAP and VOC emission reductions
and associated engineering compliance costs. The first component is a set of model plants for
each rule, regulated facility, and control option. Model plants are the basis for this analysis due
to the large number of affected facilities and the difficulties in conducting an analysis for each
affected facility. Characteristics of the model plants include typical equipment, operating
characteristics, and representative factors including baseline emissions and costs, emissions
reductions, and product recovery resulting from each control option. The second component is a
set of projections of activity data for affected facilities. Cost and emissions impacts are
calculated by setting parameters on how and when affected facilities are assumed to respond to a
particular regulatory regime, multiplying activity data by model plant cost and emissions
estimates, differencing from the baseline scenario, and then summing to the desired level of
aggregation. In addition to emissions reductions, some control options result in gasoline product
recovery, which can then be sold. Estimates of annualized cost include the value of the product
recovery where applicable.
3.2 Emissions Points, Controls, and Model Plants
NSPS XX, MACT R, and GACT 6B collectively regulate 4 types of facilities:
1. Bulk Gasoline Terminals
2. Bulk Gasoline Plants
3. Pipeline Breakout Stations
4. Pipeline Pumping Stations
Table 3-1 summarizes the facilities covered by each rule. Each type of facility is discussed
briefly below.
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Table 3-1: Regulated Facilities by Rule
Facility
NSPS XX
MACT R
GACT 6B
Bulk Gasoline Terminals
X
X
X
Bulk Gasoline Plants
X
Pipeline Breakout Stations
X
X
Pipeline Pumping Stations
X
Note: NSPS XX does not cover gasoline storage at bulk gasoline terminals
3.2.1.1 Bulk Gasoline Terminals
A bulk gasoline terminal is a gasoline storage and distribution facility that receives
gasoline by pipeline, ship, barge, or cargo tank and has a throughput of greater than 75,700 liters
per day (approximately 20,000 gallons per day). Once received at a terminal, gasoline is stored in
large storage tanks and transferred to cargo tanks via a system of equipment called a loading
rack. Once offloaded into cargo tanks, gasoline is transported from the terminal to retail gasoline
stations or intermediate storage facilities called bulk plants (discussed in the next section). Bulk
gasoline terminals are regulated by NSPS XX, MACT R, and GACT B.
3.2.1.2 Bulk Gasoline Plants
Bulk gasoline plants are like bulk gasoline terminals. They receive gasoline by pipeline,
ship, barge, or cargo tank, store the gasoline received in storage tanks, and transfer it to tanker
trucks via a loading rack. However, bulk gasoline plants handle throughput less than 20,000
gallons per day. They therefore have fewer and smaller storage tanks and smaller loading racks
than bulk gasoline terminals. Due to their smaller scale, bulk gasoline plants are area sources of
HAP and are regulated under GACT 6B.
3.2.1.3 Pipeline Breakout Stations
Pipeline breakout stations are facilities along a refined petroleum pipeline which contain
storage vessels used to relieve surges or receive and store gasoline from the pipeline for re-
injection and continued transportation by pipeline or to other facilities. Pipeline breakout stations
vary in size and emissions and are regulated by both MACT R and GACT 6B.
3.2.1.4 Pipeline Pumping Stations
Pipeline pumping stations are facilities along a pipeline containing pumps to maintain the
desired pressure and flow of product through the pipeline. They do not contain gasoline storage
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tanks other than surge control tanks. Pipeline pumping stations are area sources of HAP and
regulated under GACT 6B.
3.2,2 Emission Points at Regulated Facilities
This section characterizes emission points at regulated facilities and the emissions
controls evaluated by the NESHAP technology reviews and NSPS review.
3.2.2.1 Loading Racks
Gasoline stored at bulk terminals and bulk plants is pumped through metered loading
areas, or loading racks, into tanker trucks. A loading rack consists of a platform, loading arms
(which connect to the tank truck for fuel transfer), pumps, meters, valves, and piping to transfer
gasoline from the storage tank to the receiving cargo tank. The process of loading gasoline
causes displacement of gasoline vapors, which lead to VOC and HAP emissions.
The gasoline loading arm can connect to the tanker cargo tank at the top of the tank (top
loading) or the bottom of the tank (bottom loading). Top loading may occur directly through a
top loading fill pipe (splash loading) or through a connected downspout that places the entry
flow near the bottom of the tank (submerged fill). Splash loading creates turbulence that leads to
increased emissions. Bottom loading leads to submerged fill and reduced turbulence. One
method of controlling VOC emissions relative to splash loading is to use submerged fill top
loading or bottom loading.
In addition to submerged loading, emissions from loading operations can be controlled
through conveying displaced vapor through a closed vent system to a control device or fuel gas
system, and vapor balancing. The closed vent system uses piping to capture displaced vapor from
the cargo tank and route it either to a control device or to a fuel system for combustion. Vapor
balancing systems capture displaced vapor and route it through piping back to the storage tank.
Vapor balancing can only be used with fixed roof storage tanks, and thus vapor balancing is not
an option at most gasoline distribution facilities other than bulk gasoline plants (see the next
section).
This technology review MACT R and GACT 6B and the review of NSPS XX evaluated
thermal/vapor combustion units (VCUs), carbon adsorption vapor recovery units (VRUs), flares,
and refrigerated condensers based on both splash loading and submerged loading. While
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submerged loading is not required explicitly by current NESHAP (except for certain area source
facilities) and NSPS, it is consistent with management best-practices and is thought to be the
predominant method of loading. For this reason, it is assumed that facilities already practice
submerged loading in the baseline and all costs and emissions impacts are incremental to
submerged loading. Emissions limits at gasoline loading racks are specified in terms of allowable
emissions in milligrams of TOC per liter of gasoline loaded (mg/L).
3.2.2.2 Storage Tanks
Gasoline is stored at bulk gasoline terminals, bulk gasoline plants, and pipeline breakout
stations in large storage tanks. These storage tanks have either fixed or floating roofs. A fixed
roof tank uses a cone or dome shaped roof that is permanently affixed to the tank shell. Floating
roof tanks have a roof that sits on top of the stored gasoline and rises or falls throughout the day
based on the varying amount of gasoline stored in the tank. The floating roof of the tank may be
either external (EFR) or internal (IFR). An EFR consists of a cylindrical steel shell with a deck
that floats on the gasoline and rises and falls with the liquid level. An IFR has both a permanent
roof and a deck that floats either on the gasoline's surface or several inches above.
Most emissions from fixed roof tanks are breathing losses and emptying losses. Breathing
loss is the expulsion of vapor from a tank's vapor space that has expanded or contracted due to
changes in temperature or pressure. These losses occur without any change to the gasoline level
of the tank. Emptying loss occurs when air drawn into the tank during gasoline removal saturates
with hydrocarbon vapor and expands past the fixed capacity of the tank, overflowing through a
pressure valve. Collectively, breathing and emptying losses are called "working" losses. Fixed
roof tanks may use vents to control breathing losses and vapor balancing systems to control
emptying losses.
Gasoline storage facilities use floating-roof tanks to control working losses. A typical
EFR consists of a cylindrical steel shell with a deck that floats on the surface of the gasoline,
completely covering it except for a small gap. A seal attached to the roof slides along the shell
wall as the roof is raised and lowered. An IFR is similar but also contains a permanently affixed
roof at the top of the tank and may have a noncontact roof that floats inches above the surface of
the gasoline on pontoons. The largest source of emissions from floating roof tanks is standing-
storage loss, often caused by an improper fit between the seal and the tank shell or roof fittings.
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Emissions from floating roof tanks are controlled by mandating a certain type of seal and/or roof
fittings. As part of the technology review for major sources (RTI, 2021) and area sources (RTI,
2021), EPA identified a new practice for monitoring internal floating roof storage vessels using a
lower explosive limit (LEL) monitor to identify floating roofs with poor seals or fitting controls.
IFR tanks are much more common than EFR tanks. EPA estimates that approximately 95 percent
of the storage tanks in gasoline distribution are IFR tanks. Storage tanks are the largest source of
VOC emissions at gasoline distribution facilities.
Storage vessels at bulk gasoline terminals subject to NSPS XX are regulated by NSPS
subpart K, Ka, or Kb. MACT R covers all storage tanks with a capacity greater than 20,000
gallons, while NESHAP subpart 6B has primary requirements for tanks with capacity greater
than 20,000 gallons and throughput greater than 480 gallons per day or capacity greater than
40,000 gallons irrespective of throughput for bulk terminals and pipeline breakout stations. There
are no size specifications for bulk plants, but tanks smaller than 20,000 gallons are required to
have a fixed roof. For this reason, storage tanks at bulk gasoline plants have fixed roofs while
most other tanks in service in gasoline distribution have floating roofs. The technology review
and NSPS review considered a range of options for both IFR and EFR tanks, from maintaining
the minimum MACT R/GACT 6B requirements (i.e., baseline requirements) up to requiring
control beyond NSPS Kb requirements. NSPS Kb, which was promulgated in 1987, requires a
vapor-mounted primary seal, a rim-mounted secondary seal, and fitting controls for IFR tanks.
For EFR tanks, NSPS Kb requires a mechanical shoe seal with a rim-mounted secondary seal
and fitting controls.28
3.2.2.3 Equipment Leaks
Equipment leaks are fugitive emissions occurring though malfunctioning valves, pumps,
hatches, or seals. Loading racks, storage vessels, and other equipment in use at bulk gasoline
terminals, bulk plants, pipeline breakout stations, and pipeline pumping stations are all potential
sources of fugitive emissions. Fugitive emissions at potential sources are controlled by leak
detection and repair (LDAR) programs. Examples of LDAR programs include audio, visual, and
olfactory (AVO) monitoring or monitoring at differing frequencies (annual or quarterly, for
example) using Method 21 or an optical gas imaging (OGI) device (instrument monitoring).
28 NSPS Subpart Kb is currently under review.
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Under an LDAR regime, all components in gasoline service at a facility are inspected using the
prescribed method. Under either type of regime, if leaks are detected in the normal course of
operations, they are required to be repaired. LDAR programs can vary in their emissions control
based on their frequency of monitoring (how often is equipment inspected) and efficacy of
monitoring (how likely is inspection to detect an occurring leak). Instrument monitoring will
detect leaks that cannot be detected by AVO methods.
NSPS XX equipment leak provisions apply only to vapor collection systems, vapor
processing systems, and gasoline loading racks at bulk gasoline terminals. NESHAP subpart R
and NESHAP 6B apply to all equipment in gasoline service at bulk terminals and pipeline
breakout stations and bulk terminals, bulk plants, pipeline pumping stations, and pipeline
breakout stations respectively. The technology review and NSPS review evaluated LDAR
programs ranging from the current AVO monitoring regime to periodic monitoring with Method
21 or an OGI device with monitoring frequency ranging from annual to bimonthly.
3.2.2.4 Cargo Tanks
Bulk terminals and bulk plants contain loading racks that transfer gasoline from storage
tanks into the cargo tanks of tanker trucks or railcars. Gasoline is a Class 3 flammable liquid and
may be transported using "non-pressure" cargo tanks (DOT 406) or "low-pressure" cargo tanks
(DOT 407), the requirements for which are expressed in terms of maximum allowable working
pressure (MAWP) and pressure-relief valve settings. Given the MAWP requirements for DOT
406 and DOT 407 tanks, gasoline will trigger the pressure-relief valve on DOT 406 tanks under
certain circumstances but will never trigger the pressure-relief valve on DOT 407 tanks. There
are additional legal restrictions on the transport of Class 3 flammable liquids by railcar (RTI,
2021), and railcar gasoline loading operations are not expressly included in NSPS XX. EPA
estimates less than 10 percent of gasoline is transported by railcar.
Tanks are divided into compartments with a hatchway at the top of each. Cargo tanks can
be top loaded at a loading rack by opening the hatch cover and dispensing product directly
through it. A top-loading vapor head compatible with the hatch allows vapor collection during
loading, and a better vapor-tight seal is created when top loading is performed through a top-tight
loading adapter mounted in each compartment.
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During bottom loading, an internal valve is opened to allow product flow, and vents
permit the exit of displaced vapor. Vapor collection systems with bottom loading equipment
collect vapors from the vents through a common manifold. The tank truck vapor-recovery line
terminates at a connector on the side or rear of the truck.
Emissions occur from cargo tanks due to vapor loss from leaking tank hatches and
pressure-relief valve venting. Controlling emissions from cargo tanks typically involves
certifying through a pressure-vacuum test that cargo tanks in use at a loading rack have a
specified degree of vapor-tightness. There is a trade-off between pressure-release emissions and
cargo tank leakage emissions as vapor-tightness requirements are tightened. For example, a tank
with a slowly leaking hatch will be less likely to trigger the pressure-relief valve. Tighter vapor
tightness standards will therefore lead to more pressure-relief events, and there is a point at
which reducing the allowed pressure drop during certification will simply shift emissions from
small leaks to emissions from increased pressure-relief valve release events; see the Technical
Memo on Loading Racks (RTI, 2023).29
Given the allowed vapor-tightness standard, cargo tanks are tested and leaks are repaired
when necessary. The NESHAP technology review and NSPS review evaluated standards ranging
from maintaining the minimum vapor-tightness requirements of NSPS XX and GACT 6B to
requiring vapor-tightness to be certified to a stricter level than final by this action. The allowed
pressure changes by tank size examined in this RIA are in Table 3-2.
Table 3-2: Cargo Tank Vapor-Tightness Certification Standards Examined in this RIA
(inches WC)
Cargo Tank of
Compartment Capacity
(gallons)
Current
NSPS/GACT
Standard
Current MACT
Standard
Final
Standard30
More Stringent
Alternative Standard3
2,500 or more
3.00
1.00
0.50
0.20
2,499 to 1,500
3.00
1.50
0.75
0.20
1,499 to 1,000
3.00
2.00
1.00
0.50
999 or less
3.00
2.50
1.25
1.00
29 The technical analyses consist of a set of 7 memos, referred to hereafter as the Technical Memos. The Technical
Memos are included in the docket for this final action and are listed in the References (Chapter 0). In the
remainder of the RIA, when referring to a specific technical memo, we will refer to it as the Technical Memo on
X.
30 The final standards unify the NSPS/GACT and MACT cargo tank vapor-tightness standards. The final standard
matches cargo tank vapor-tightness instituted by the California Air Resource Board (Title 17 CCR § 94014).
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a This more stringent standard requires allowable pressure drop limits that are less than the allowable precision of EPA Method
27. Further reductions of the vapor tightness requirements beyond those identified in the final standard may not be feasible in
practice.
3.2.3 Model Plants
As discussed in the introduction to this section, the emissions reductions and engineering
cost analyses presented in this section rely on a set of model plants. The model plant
configurations, including cost and emissions characteristics used to estimate impacts of the final
action, are derived from the technical analyses supporting the review of NSPS XX and the
technology review of MACT R and GACT 6B. The technical analyses consist of a set of 7
memos, referred to hereafter as the Technical Memos .
The high-level model plants used in the analysis are bulk gasoline terminals, bulk
gasoline plants, pipeline breakout stations, and pipeline pumping stations. These high-level
model plants have a variety of configurations, which include specifications of model storage
tanks and loading racks present at the facility. Each type of model plant used in the analysis is
discussed below, beginning with the lower-level model plants.
3.2.3.1 Loading Racks
Gasoline transfer operations occur at bulk gasoline terminals and bulk gasoline plants.
The engineering cost analyses for NSPS XXa, MACT R, and GACT 6B each use a variety of
model bulk gasoline terminals, and the analysis for NESHAP 6B uses model bulk gasoline
plants. Each of these model plants is assigned a model loading rack, which is used to establish
baseline cost and emissions parameters and estimate how a model plant will respond to different
emissions controls for gasoline loading operations. Model loading racks are assigned to facilities
based on facility throughput. Larger loading racks have more loading arms, greater throughput
per arm, operate more days per year, and operate longer in a given day.
Model loading racks are also distinguished by their baseline emissions levels and the
control method used to achieve it. The current emissions limits vary by rule, and this is reflected
in the assignment of model loading racks to bulk plants and terminals. For example, loading
racks at major source model bulk terminals are assumed to be controlled to 10 mg/L, while
loading racks at area source model large bulk terminals are assumed to be controlled to at least
80 mg/L. It is also assumed some model bulk plants and terminals are equipped with loading
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racks that control emissions beyond the minimum level. Some model bulk plants are assumed to
already be using vapor balancing systems to control loading emissions, whereas some area
source model bulk terminals are assumed to exceed 80 mg/L of control by using a vapor
recovery or vapor combustion system. Further, a portion of the facilities to undergo modification
or reconstruction are assumed to be meeting either 10 mg/L, 35 mg/L, or 80 mg/L prior to
modification/reconstruction. The current standards and the regulatory options analyzed in this
RIA are discussed in Section 3.3 below. The pre-existing method and level of emissions control
at a loading rack determines the baseline cost and emissions due to loading operations at a
facility and the cost and emissions impacts of more stringent control relative to baseline. For
details on the type and distribution of model loading racks at model bulk terminals and plants,
see the Technical Memo on Loading Racks.
3.2.3.2 Storage Tanks
Gasoline storage occurs at bulk gasoline terminals, bulk gasoline plants, and pipeline
breakout stations. However, storage tanks at bulk gasoline terminals are not covered by NSPS
XX, so model storage tanks do not directly affect cost and emissions at NSPS XXa model bulk
terminals. Also, no changes to storage tank controls at bulk plants were considered in either the
final standards or the less and more stringent alternative standards (apart from the vapor
balancing requirement for gasoline loading operations and the filling of storage vessels).
Therefore, this discussion is only relevant to model storage tanks with floating roofs at major and
area source model bulk terminals and pipeline breakout stations.
Given the variety of tank sizes and configurations (fixed vs floating roof, internal vs
external floating roof) and current storage tank control standards, it was necessary to make
assumptions about the type and quantity of tanks present at each model bulk terminal and bulk
plant. First, bulk plants are required to used fixed roof tanks, while larger tanks at bulk terminals
and pipeline breakout stations are required to have floating roofs. Model storage tanks used in
the engineering cost analysis differ along 3 dimensions:
1. Size - 9 levels (ranging from 12,000 to 4,200,000 gallons) for IFR tanks, 7 levels
(ranging from 80,000 to 4,200,000 gallons) EFR tanks
2. Internal vs external floating roof (2 levels)
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3. Kb fitting controls included vs non-Kb compliant (2 levels)
There are 32 main model storage tank configurations, and these are distributed to model
bulk terminals and model pipeline breakout stations based on model terminal throughput and
assumptions about the underlying population of storage tanks in gasoline service. For further
details, see the Technical Memo on Storage Tanks (RTI, 2023).
3.2.3.3 Cargo Tanks
The final action proposes new standards for vapor-tightness of cargo trucks servicing
bulk gasoline terminals and bulk gasoline plants. To estimate the costs and emissions impacts of
these final standards and assign them to specific rules, there are two steps:
1. Estimate the nationwide impacts of final standards based on an assumed
distribution of model cargo tanks.
2. Assign these impacts to NSPS XXa, MACT R, and GACT 6B facilities based on
the fractional distribution of total throughput serviced by bulk terminals and
plants covered by each rule.
For example, suppose one third of gasoline throughput is assumed to occur at NSPS XXa
affected model terminals, one third is assumed to occur at MACT R affected model terminals,
and one third is assumed to occur at GACT 6B model bulk terminals and model bulk plants. In
this scenario, one third of the cost and emissions impact of each cargo tank option would be
assigned to each rule. Throughput at model bulk terminals and plants is discussed below.
For step 1, 5 model cargo tanks were used, ranging in size from 600 to 8,500-gallon tank
capacity. Each tank size had an assumed nationwide distribution, and each tank was assumed to
undergo 10 pressure-relief device releases per day. For discussion of cargo tank controls and the
assumed distribution of tanker trucks, see the Technical Memo on Loading Racks (RTI, 2023).
3.2.3.4 Pipeline Pumping Stations
There are no major source pipeline pumping stations, so all pipeline pumping stations are
covered under GACT 6B. There is only one model pipeline pumping station, so all area source
pipeline pumping stations are treated equivalently in the engineering cost analysis. For the
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purposes of assessing equipment leaks, each model pumping station was assumed to have 59
valves, 260 flanges and connectors, and 6 pumps.
3.2.3.5 Pipeline Breakout Stations
Pipeline breakout stations are covered by MACT R and GACT 6B. Model pipeline
breakout stations are distinguished by:
1. Area source vs maj or source of HAP
2. Throughput level (2 levels - 600,000 and 750,000 gpd)
3. The number of model storage tanks (2 levels - 4 or 5). It assumed that the
600,000 gpd model breakout station uses 4 tanks, while the 750,000 gpd breakout
station uses 5 tanks.
4. The distribution of model storage tanks between Kb and non-Kb compliant. 3
different splits between IFRT/EFRT Kb/non-Kb model storage tanks are assumed
for each rule/size combination.
This leads to 12 total configurations of model pipeline breakout stations (2 rules x 2 sizes x 3
tank configurations). For the purposes of assessing equipment leaks, each model breakout station
was assumed to have 2,980 valves, 5,230 flanges and connectors, and 75 pumps.
3.2.3.6 Bulk Gasoline Plants
Bulk gasoline plants are all area sources of HAP, so all model plants are covered by
GACT 6B for the purposes of the engineering cost analysis. Model bulk plants are all assumed to
have throughput of 15,000 gallons of gasoline per day and house two small, fixed roof storage
tanks. Model bulk plants are only distinguished by their model loading rack. A model bulk plant
may be assigned one of three possible model loading racks:
1. A loading rack with a vapor balancing system (for both deliveries and loading)
2. A loading rack with vapor balancing system for either deliveries or loading (but
not both)
3. A loading rack without a vapor balancing system
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Model bulk plants were placed into the above three categories based on an assumed distribution
of bulk plants within states. In developing the original standards for GACT 6B (Hester and
Stephenson, 2006), EPA reviewed state rules to determine what states had regulations controlling
emissions at bulk plants. Certain states had rules controlling VOC emissions from loading racks
or explicitly requiring vapor-balancing systems. Based on this review, EPA estimated the
proportion of bulk plants which already had a vapor-balancing system in place due to existing
state requirements. EPA also estimated the proportion of bulk plants that would be exempt from
the requirement due to not meeting a throughput threshold of 4,000 gpd as part of this review.
The engineering cost analysis contained in this chapter thus assumes that, in the baseline, some
bulk plants already have a vapor-balancing system for either deliveries or loading (or both) and
that some bulk plants would not meet the throughput threshold required to install a vapor-
balancing system. For the distribution of bulk plants, see Table 3-5 in Section 3.2.4. For a
discussion of vapor balancing systems and the assumed distribution of loading racks at bulk
plants, see the Technical Memo on Loading Racks (RTI, 2023) and supporting documentation.
For the purposes of assessing equipment leaks, each model bulk plant was assumed to have 50
valves, 216 flanges and connectors, and 4 pumps.
3.2.3.7 Bulk Gasoline Terminals
Each rule covers operations of bulk gasoline terminals, so there are different model bulk
gasoline terminals associated with each rule. In addition to differing by rule, model bulk
terminals differ along five dimensions:
1. Size, determined by gasoline throughput per day and operating days per year
2. Type of model loading rack in the baseline, based on type of control (VCU, VRU,
flare, no control) and estimated level of control (no control, 80 mg/L, 35 mg/L, 10
mg/L).
3. Number of tanks
4. Distribution of tanks between IFRT/EFRT and Kb/non-Kb compliant.
5. NSPS XXa only - model plants can be new or modified/reconstructed
Between the five dimensions, there are 15 model bulk terminals used for the NSPS XXa
analysis, 9 used for the MACT R analysis, and 61 used for the GACT 6B analysis. For the
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purposes of assessing equipment leaks, each model bulk terminal was assumed to have 385
valves, 2,625 flanges and connectors, and 15 pumps.
3.2,4 Activity Data
The emissions reduction and engineering cost analysis presented in this chapter relies on
counts of affected facilities to support the review of NSPS XX and the technology review of
MACT R and GACT 6B. Details on these counts are contained in the underlying Technical
Memos used to support the reviews.
For NSPS XXa, 5 new and 15 modified or reconstructed bulk terminals are projected
over the first 5 years of the action. Given the lack of historical data on facility construction or
projection of future facility construction, EPA assumed the projected new and
modified/reconstructed facilities will be created uniformly over time and extrapolated the 5-year
projection through 2041 (See Table 3-3 below). The next section includes a discussion of the
analysis timeframe.
Table 3-3: NSPS XXa Projected Affected Facilities, 2027-2041
Year
New
Modified/Reconstructed
2027
5
15
2028
6
18
2029
7
21
2030
8
24
2031
9
27
2032
10
30
2033
11
33
2034
12
36
2035
13
39
2036
14
42
2037
15
45
2038
16
48
2039
17
51
2040
18
54
2041
19
57
Note: of the 15 modified/reconstructed facilities assumed by 2027,2 are assumed to be meeting an 80 mg/L loading rack
emissions limit, 5 are assumed to be meeting 35 mg/L, and 8 are assumed to be meeting 10 mg/L.
For MACT R and GACT 6B, EPA assumes the count of each affected facilities is constant
from 2027-2041. In absence of reliable data on facility closure over time, EPA considered this to
be a reasonable assumption given that gasoline consumption is projected to be roughly flat over
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the projected time horizon, (EIA's AEO 2023 projects gasoline consumption will fall by 0.6
percent per year from 2027 to 2041). For the distribution of high-level model plants across rules,
see Table 3-4 below.
Table 3-4: Model Plant Distribution and Configurations
Facility Type
NSPS XXa
MACT R
GACT 6B
Count31
Configurations
Count
Configurations
Count
Configurations
Bulk Terminal
20
15
195
9
1,090
61
Bulk Plant
-
-
-
-
5,913
3
Pumping Station
-
-
-
-
1,800
1
Breakout Station
-
-
15
6
460
6
Throughout this chapter, various results will be presented by year for NSPS XXa but not MACT
R or GACT 6B; this is because the projection of affected facilities is only changing for NSPS
XXa since this is a new source standard.
As discussed in Section 3.2.3.6, a portion of bulk plants are assumed to either already use
a vapor balancing system of some kind or to be exempt from any vapor balancing requirement
due to not meeting a throughput threshold of 4,000 gallons per day. The distribution of model
bulk plants used for the cost and emissions analysis in this RIA is contained in Table 3-5.
Table 3-5: Assumed Distribution of Controls at Bulk Plants
Current Control
Number of Facilities
Vapor Balancing for Deliveries and Loading
1,715
Vapor Balancing for Deliveries or Loading
270
Requires Vapor Balancing
2,095
Exempt Based on Low Throughput
1,833
3,2,5 Baseline
As mentioned in Chapter 1, the impacts of regulatory actions are evaluated relative to a
baseline that represents the world without the regulatory action. In this RIA, we present results
for the final amendments to NESHAP GACT 6B and MACT R and final NSPS XXa.
Throughout this document, we focus the analysis on the requirements that result in quantifiable
compliance cost or emissions changes compared to the baseline. For each rule and most
31 This count reflects 5 new and 15 modified/reconstructed terminals 5 years following promulgation.
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emissions sources, EPA assumed each facility achieved emissions control meeting current
standards, and estimated emissions and cost relative to this baseline. An exception is that loading
racks are assumed to use submerged fill methods in the baseline even when not explicitly
required under current NESHAP or NSPS standards. This is discussed in Section 3.2.2.1.
Further, as discussed in Section 3.2.3.6, requirements in some states control emissions from
loading racks at bulk plants. Based on a review of state requirements applying to bulk plants,
EPA estimated the proportion of these facilities that already employ vapor-balancing systems
either for dispensing gasoline, receiving gasoline, or both. Table 3-5 in Section 3.2.4 shows the
distribution of vapor-balancing systems at bulk plants used in the analysis. Finally, with respect
to cargo tank vapor-tightness standards, the California Air Resource Board (CARB) currently
requires cargo tanks be certified to the vapor-tightness standard finalized by this action. Due to
data limitations, EPA was not able to account for the impact of the CARB cargo tank
requirements in the baseline. EPA is not aware of any other state standards that are more strict
than current federal standards.
For the analysis, we calculate the cost and emissions impacts of the NSPS and NESHAP
amendments from 2027 to 2041. The initial analysis year is 2027 as we assume the final action
may be signed in late 2023 or early 2024. We assume full compliance with the amendments to
MACT R and GACT 6B will take effect three years later in 2027, which is consistent with the
requirements in Section 112 of the Clean Air Act for HAP standards. One exception to this is
that the requirements for EFR tanks under MACT R and GACT 6B require fitting controls,
which will require degassing of the storage vessel. These controls must be installed at the first
degassing of the storage vessel after three years from the promulgation date of the final action,
but in case more than 10 years from the promulgation date of the final action. Facilities will have
3 years to identify storage vessels that need to be upgraded and identify appropriate fitting
control systems that need to be installed. Facilities are allowed up to 10 years in order to align
the installation of the controls with a planned degassing event, to the extent practicable, to
minimize the offsetting emissions that occur due to a degassing event solely to install the fitting
controls. To the extent that that not all storage vessels have fitting controls installed in the first
10 years of the analysis period, cost and emissions impacts will be overestimated during that
span. The final analysis year is 2041, which allows us to provide fifteen years of impacts after
the amendments are assumed to fully take effect. A fifteen-year timespan was selected to cover
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the lifetime of the longest-lived capital equipment (upgraded storage tanks and VRU/VCU for
loading racks) expected to be installed as a result of the amendments. We assume the NSPS XXa
amendments take effect immediately upon proposal (2022), which is consistent with compliance
requirements for NSPS under Section 111 of the Clean Air Act. It is appropriate to set the initial
analysis year as 2027 rather than 2022 given that the impacts of NSPS XXa are much smaller
than those for GACT 6B and MACT R.
3,2,6 Product Recovery
Engineering cost estimates in this chapter include projections of revenue from product
recovery. This is because control options analyzed in this RIA lead to the recovery of gasoline
vapor. Recovered gasoline vapor is monetized as product recovery credits by multiplying VOC
emissions reductions by a VOC credit of 662$/ton. The VOC recovery credit was calculated
based on the average refiner's wholesale spot price for all gasoline types in 2021
($2.07/gallon).32 Using a density of gasoline of 6.25 lb/gallon yields the assumed VOC credit
((2.07 ($/gallon) / 6.25 (lb/gallon)) x 2000 (lb/ton) = 662 ($/ton)) (See the Technical Memo on
Equipment Leaks (RTI, 2023), footnote 3). The estimated value of gasoline recovered is similar
to the average bulk price of gasoline in 2021 of $2.09. (See Table 2-13). Throughout this
document, we treat the revenues associated with gasoline vapor recovery as an offset to projected
compliance cost. We consider this the appropriate choice because the product recovery accrues
directly to firms rather than society. These revenues may also be considered as a benefit of the
regulatory action. However, regardless of whether this revenue is considered a compliance cost
offset or benefit, the associated net benefits are equivalent.
Because the controls considered lead to product recovery, it is possible for the cost of a
control option to be negative once the value of product recovery is considered (the potential
annualized costs may be outweighed by the revenue from product recovery). This observation
may typically support an assumption that owners of gasoline distribution facilities would
continue to perform the emissions abatement activity regardless of whether a requirement is in
place, because it is in their private self-interest. However, there may be an opportunity cost
associated with the installation of environmental controls or implementation of compliance
32 EIA, 2023.
.
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activities (for purposes of mitigating the emission of pollutants) that is not reflected in the
control costs. If environmental investment displaces investment in productive capital, the
difference between the rate of return on the marginal investment displaced by the mandatory
environmental investment is a measure of the opportunity cost of the environmental requirement
to the regulated entity. To the extent that any opportunity costs are not added to the control costs,
the compliance costs presented above may be underestimated. In addition, the hurdle rate is
defined as the minimum rate of return on an investment that a firm would deem acceptable under
typical business practices. Thus, if the hurdle rate is higher on average for firms in this industry
than the interest rate used in estimating the compliance costs (7.75% at the time of this analysis),
then these investments in environmental controls may potentially not necessarily be undertaken
on average.
From a social perspective, however, the increased financial returns from gasoline
recovery accrue to entities somewhere along the gasoline distribution supply chain and should be
accounted for in a national-level analysis. An economic argument can be made that, in the long
run, no single entity bears the entire burden of compliance costs or fully appropriates the
financial gain of the additional revenues associated with gasoline recovery. The change in
economic surplus resulting from gasoline recovery is likely to be spread across different market
participants. The simplest and most transparent approach for allocating these revenues would be
to assign the compliance costs and revenues to a model plant and not make assumptions
regarding the allocation of costs and revenues across agents. We follow this approach for
allocating these revenues in the cost analysis for this final action.
3.3 Description of Regulatory Options
This RIA analyzes less and more stringent alternative regulatory options in addition to
the analyzing the amendments finalized for GACT 6B, MACT R, and NSPS XXa. This section
details the regulatory options examined for each rule. In addition to the control options discussed
in each section, EPA is also finalizing revisions related to emissions during periods of startup,
shutdown, and malfunction (SSM); additional requirements for electronic reporting of
performance test results, performance evaluation reports, and compliance reports; monitoring
and operating requirements for control devices; and other minor technical improvements.
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3,3.1 GACT6B
GACT 6B regulates emissions from loading racks at bulk terminals and bulk plants,
storage tanks at bulk terminals, bulk plants, and pipeline breakout stations, cargo tank vapor-
tightness, and equipment leaks at bulk terminals, bulk plants, pipeline breakout stations, and
pipeline pumping stations. Under the current standards, emissions from loading racks at large
bulk gasoline terminals (those with gasoline throughput of 250,000 gallons per day or greater)
are controlled by vapor collection and processing systems meeting 80 mg/L and the cargo tanks
being loaded must be certified to be vapor tight. Small bulk gasoline terminals and bulk gasoline
plants must use submerged filling when loading gasoline. Emissions from storage vessels with a
design capacity greater than or equal to 75 m3 are controlled by equipment requirements.
Equipment leaks are repaired upon detection using AVO methods.
Based on the technology review, EPA is revising requirements for the following:
• Loading operations: large bulk terminals must control emissions using a vapor
collection and processing system meeting 35 mg/L. Bulk plants must install
vapor-balancing systems. Cargo tanks must be certified to be vapor-tight to a
standard of 0.5" - 1.25" water pressure loss (see Table 3-2).
• Storage Tanks: EFR tanks must have fitting controls compliant with NSPS Kb
and LEL monitoring must be conducted for IFR tanks.33
• Equipment Leaks: equipment leaks on all equipment in gasoline service at bulk
terminals, bulk plants, pipeline breakout stations, and pipeline pumping stations
must be monitored annually using EPA Method 21 or OGI.
Bulk plants that do not meet a minimum throughput threshold of 4,000 gallons per day
are exempt from the vapor balancing requirement. The current and final standards for GACT 6B
are summarized in Table 3-6 below.
33 For a description of the compliance timeline for fitting controls on EFR tanks, see Section 3.2.5.
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Table 3-6: Current and Final Standards for NESHAP GACT 6B
Emissions Source
Facility
Current Standard
Final Standard
Loading Racks
Small Bulk Terminal
(<250,000 gpd, >20,000 gpd)
Large Bulk Terminal
(>250,000 gpd)
Bulk Plant
(< 20,000 gpd)
Submerged fill
80 mg/L
Submerged fill
Submerged fill
35 mg/L
Require vapor
balancing system
Storage Tanks
Regular Tanks
Compliance with NSPS Kb
except for secondary seal
on IFR tanks and some
fittings controls
Require NSPS Kb
fitting controls for EFR
Tanks and LEL
monitoring for IFR
Tanks
Surge Control Tanks
Require fixed roof tanks
Require fixed roof tanks
Equipment Leaks
Bulk Terminals, Bulk Plants,
Pipeline Breakout Stations,
Pipeline Pumping Stations
Monthly AVO inspections
Annual instrument
monitoring
Cargo Tank Vapor-
tightness
Bulk Terminals and Bulk
Plants
Maximum allowable
pressure loss during
certification of 3" water
column (WC)
Maximum allowable
pressure loss during
certification of 0.5" -
1.25" WC
We also analyze less and more stringent alternative regulatory options as compared to our
final option with all options being more stringent than the current GACT 6B, for this rule in
adherence to OMB Circular A-4. For GACT 6B, less stringent regulatory options include
maintaining control requirements for large storage tanks at their current level, increasing vapor-
tightness standards on cargo tanks to 1" - 2.5" water pressure loss (the current MACT
standards), and not requiring vapor-balancing systems on loading racks at bulk plants. More
stringent regulatory options include increasing equipment leak monitoring frequency from
annual to quarterly, requiring IFR tanks to meet NSPS Kb standards, and strengthening the
vapor-tightness requirement for cargo tanks. The final, less stringent, and more stringent
regulatory options for GACT 6B are summarized in Table 3-7 below.
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Table 3-7: Regulatory Options Examined in this RIA - GACT 6B
Regulatory Option
Less
More
Facility
Emissions Source
Requirement
Stringent
Final
Stringent
Annual Instrument
X
X
Bulk Terminals,
Pipeline Breakout
Equipment Leaks
Monitoring
Quarterly
Instrument
Monitoring
Stations, Bulk Plants,
and Pipeline Pumping
Stations
X
Misc.
MRR
X
X
X
No change
X
EFR tank to Kb
Bulk Terminals,
Pipeline Breakout
Stations, and Bulk
Plants
Large Storage Tanks
and LEL
Monitoring for IFR
tank
EFR tank/IFR tank
X
to Kb and LEL
X
Monitoring for
IFRT
MACT34
X
Bulk Terminals and
Bulk Plants
Cargo Tank Vapor-tightness
State Requirement
Beyond State
Requirement
X
X
Small Bulk Terminals
Loading Racks
No change
X
X
X
Large Bulk Terminals
Loading Racks
35 mg/L
10 mg/L
X
X
X
Bulk Plants
Loading Racks
No change
Vapor-balancing
X
X
X
3.3.2 MALT R
MACT R regulates emissions from loading racks and cargo tank vapor-tightness at bulk
gasoline terminals, and storage tanks and equipment leaks at bulk terminals and pipeline
34 With respect to cargo-tank vapor-tightness requirements, "NSPS/GACT" refers to a maximum allowable pressure
loss during certification based on current NSPS XX/GACT 6B, "MACT" refers to a maximum allowable pressure
loss during certification based on MACT R limits, "State Requirement" refers to a maximum allowable pressure
loss during certification based on the California Air Resource Board (CARB) standard, and "Beyond State
Requirement" refers to a stricter standard beyond the CARB standard. For more details, refer to the Technical
Memo on Loading Rack Control Options.
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breakout stations. Under the current standards, emissions from loading racks at bulk gasoline
terminals are controlled by vapor collection and processing systems meeting 10 mg/L and the
cargo tanks being loaded must be certified to be vapor tight. Emissions from storage vessels with
a design capacity greater than or equal to 75 m3 at bulk gasoline terminals and pipeline breakout
stations are controlled by equipment requirements. Equipment leaks at bulk gasoline terminals
and pipeline breakout stations are repaired upon detection using AVO methods.
Based on the technology review, EPA is revising requirements for the following:
• Storage Tanks: EFR tanks must have fitting controls compliant with NSPS Kb
and LEL monitoring must be conducted for IFR tanks.35
• Equipment Leaks: equipment leaks on all equipment in gasoline service at bulk
gasoline terminals and pipeline breakout stations must be monitored semiannually
using EPA Method 21 or OGI.
• Cargo tanks must be certified to be vapor-tight to a standard of 0.5" - 1.25" water
pressure loss (see Table 3-2).
EPA is also finalizing that MACT R explicitly require the use of submerged fill during loading
operations. Because submerged loading is assumed to take place in the baseline (see Section
3.2.2.1), this requirement is not expected to have direct cost or emissions implications. The
current and final standards for MACT R are summarized in Table 3-8 below.
Table 3-8: Current and Final Standards for MACT R
Emissions Source
Facility
Current Standard
Final Standard
Loading Racks
Bulk Terminal
10 mg/L
No change (10 mg/L)
Storage Tanks
Bulk Terminals
and Pipeline
Breakout Stations
Compliance with NSPS Kb except
for some fitting controls
Require NSPS Kb fitting
controls for EFR Tanks
and LEL monitoring for
IFR Tanks
Equipment Leaks
Bulk Terminals
and Pipeline
Breakout Stations
Monthly AVO inspections
Semiannual instrument
monitoring
Cargo Tank Vapor-
tightness
Bulk Terminals
Maximum allowable pressure loss
during certification of 1" - 2.5"
WC
Maximum allowable
pressure loss during
certification of 0.5" - 1.25"
WC
35 For a description of the compliance timeline for fitting controls on EFR tanks, see Section 3.2.5.
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We also analyze less and more stringent alternative regulatory options as compared to our
final option with all options being more stringent that the current MACT R, for this rule in
adherence to the current guidance in OMB Circular A-4. For MACT R, less stringent regulatory
options include maintaining control requirements for storage tanks at their current level,
maintaining vapor-tightness standards on cargo tanks to 1" - 2.5" water pressure loss, and
implementing equipment leak monitoring annually rather than semiannually. More stringent
regulatory options include requiring IFR tanks to meet NSPS Kb standards and strengthening the
vapor-tightness requirement for cargo tanks. The final, less stringent than final, and more
stringent regulatory options for MACT R are summarized in Table 3-9 below.
Table 3-9: Regulatory Options Examined in this RIA - MACT R
Regulatory Option
Facility
Emissions
Source
Requirement
Less
Stringent
Final
More
Stringent
Equipment Leaks
Bulk Terminals and
Pipeline Breakout
Stations
Annual Instrument
Monitoring
Semiannual
Instrument
Monitoring
Quarterly Instrument
Monitoring
X
Storage Tanks
No change
EFR tank to Kb and
LEL Monitoring for
IFR tank
EFR tank/IFR tank to
Kb and LEL
Monitoring for IFRT
X
Misc.
MRR
X
X
X
X
X
X
X
Loading Racks
10 mg/L
X
Bulk Terminals
Cargo Tank
Vapor-tightness
MACT
State Requirement
Beyond State
Requirement
X
X
X
X
X
3.3.3 NSPSXXa
NSPS XXa would regulate emissions from loading racks at bulk gasoline distribution
terminals constructed or modified after date of publication of the proposal of this action (June 10,
2022). Emissions from loading racks at bulk gasoline terminals are currently controlled by vapor
collection and processing systems meeting 35 mg/L and the cargo tanks being loaded must be
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certified to be vapor tight.36 Equipment leaks are repaired upon detection using AVO methods.
Based on the NSPS review, EPA is finalizing requirements for the following:
• Loading operations: new bulk terminals must control emissions using a vapor collection
and processing system meeting 1 mg/L. Reconstructed/modified bulk terminals must
control emissions using a vapor collection and processing system meeting 10 mg/L.
Cargo tanks must be certified to be vapor-tight to a standard of 0.5" - 1.25" water
pressure loss (see Table 3-2).
• Equipment Leaks: equipment leaks on all equipment in gasoline service at bulk gasoline
terminals must be monitored quarterly using EPA Method 21 or OGI.
The current and final standards for NSPS XX and NSPS XXa, respectively, are summarized in
Table 3-10 below.
Table 3-10: Current and Final Standards for NSPS XX and NSPS XXa
Emissions Source
Facility
Current Standard
Final Standard
Bulk Terminal -
New
35 mg/L
1 mg/L
Loading Racks
Bulk Terminal -
Modified/Recons
tructed
35 mg/L
10 mg/L
Equipment Leaks
Bulk Terminal
Monthly AVO inspections
Quarterly
instrument
monitoring
Maximum
allowable
Cargo Tank Vapor-
tightness
Bulk Terminal
Maximum allowable pressure loss during
certification of 3" water column (WC)
pressure loss
during
certification of
0.5"-1.25" WC
We analyze less and more stringent alternative regulatory options as compared to our
final option, but all options being more stringent that the current standard, for this rule in
adherence to the guidance in the current OMB Circular A-4. For NSPS XXa, less stringent
regulatory options increasing vapor-tightness standards on cargo tanks to 1" - 2.5" water
pressure loss (the current MACT standards) and implementing equipment leak monitoring
annually rather than quarterly. The more stringent regulatory option includes strengthening the
36 Allowance is provided to meet 80 mg/L for affected facilities with an "existing vapor processing system."
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vapor-tightness requirement for cargo tanks. The final, less stringent than final, and more
stringent than final regulatory options for NSPS XXa are summarized in Table 3-11 below.
Table 3-11: Regulatory Options Examined in this RIA - NSPS XXa
Regulatory Option
Facility
Emissions
Source
Requirement
Less
Stringent
Final
More
Stringent
Equipment Leaks
Annual Instrument
Monitoring
Quarterly Instrument
Monitoring
X
X
X
Bulk Terminal
Loading Racks
New - 35 mg/L,
modified - 35 mg/L
New - 1 mg/L,
modified - 10 mg/L
X
X
X
MACT
X
Cargo Tank
Vapor-tightness
State Requirement
Beyond State
Requirement
X
X
Misc.
MRR
X
X
X
3.4 Emissions Reduction Analysis
3,4,1 Baseline VOC/HAPEmissions Estimates
The baseline emissions for VOC and HAP (tons per year) are contained in Table 3-12
below. Recall from Section 3.2.4 that the projected count of affected facilities for MACT R and
GACT 6B is constant from 2027-2041, while projected facility counts for NSPS XXa are
projected to vary over time. Baseline emissions are thus constant for MACT R and GACT 6B
but variable for NSPS XXa. The figures for NSPS XXa in Table 3-12 reflect baseline emissions
in 2027, 5 years following the promulgation of the rule. This caveat applies to all per-year
figures presented for NSPS XXa for the remainder of the chapter. Baseline emissions for NSPS
XXa from 2027-2041 are in Table 3-13.
Table 3-12: Baseline Emissions in 2027 (Short Tons)
Rule
VOC Baseline Emissions
HAP Baseline Emissions
NSPS XXa
3,900
160
MACTR
18,000
850
GACT 6B
99,000
5,300
All
120,000
6,300
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Note: Numbers rounded to two significant digits unless otherwise noted.
Table 3-13: NSPS XXa Baseline Emissions (Tons), 2027-2041
Year VOC Baseline Emissions HAP Baseline Emissions
2027
3,900
160
2028
4,700
190
2029
5,400
220
2030
6,200
250
2031
7,000
280
2032
7,800
310
2033
8,600
340
2034
9,300
370
2035
10,000
400
2036
11,000
440
2037
12,000
470
2038
12,000
500
2039
13,000
530
2040
14,000
560
2041
15,000
590
Note: Numbers rounded to two significant digits unless otherwise noted.
3,4,2 Projected VOC/HAPEmissions Reduction
Projected emissions reductions for each rule and option package are presented in Table
3-14 below. Reductions for every year from 2027-2041 are presented for NSPS XXa in Table
3-15. Roughly 89 percent of the VOC emissions reductions and 91 percent of the HAP emissions
reductions projected under the final options are due to the revisions affecting GACT 6B. The
same is broadly true for the less stringent (92 percent and 94 percent) and more stringent (89
percent and 90 percent) alternative regulatory options. Further, the bulk of the VOC/HAP
emissions reductions projected under GACT 6B are coming from the requirement that bulk
plants install a vapor-balancing system to control emissions from loading operations (24,000 tons
of projected VOC reductions per year, 950 tons of projected HAP reductions per year). For a
discussion of emissions reduction by emissions point for each rule and option package, see
Section 3.5.1 below.
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Table 3-14: Emissions Reductions for Regulatory Options, Tons per Yeara'b'c
Rule
Option Package
VOC
HAP
Less Stringent
240
12
NSPS XXa
Final
2,900
120
More Stringent
3,000
120
Less Stringent
0
0
MACTR
Final
2,200
130
More Stringent
2,700
170
Less Stringent
11,000
890
GACT 6B
Final
40,000
2,100
More Stringent
50,000
2,700
Less Stringent
12,000
950
All Rules
Final
45,000
2,300
More Stringent
56,000
3,000
a Numbers rounded to two significant digits unless otherwise noted.
b NSPS XXa reductions reflect those occurring in 2027. For each year 2027-2041, see Table 3-15 below.
c The options whose emission reductions are included in this table for each rule are those described in Tables 3-7, 3-9, and 3-11.
Table 3-15: Emissions Reductions for Regulatory Options (Tons), NSPS XXa, 2027-2041
Less Stringent
Final
More Stringent
Year
voc
HAP
VOC HAP
VOC
HAP
2027
240
12
2,900 120
3,000
120
2028
290
14
3,500 150
3,600
150
2029
340
17
4,100 170
4,100
170
2030
390
19
4,700 190
4,700
200
2031
440
22
5,300 220
5,300
220
2032
490
24
5,900 240
5,900
240
2033
540
26
6,500 270
6,500
270
2034
590
29
7,100 290
7,100
290
2035
640
31
7,700 320
7,700
320
2036
680
34
8,200 340
8,300
340
2037
730
36
8,800 370
8,900
370
2038
780
38
9,400 390
9,500
390
2039
830
41
10,000 410
10,000
420
2040
880
43
11,000 440
11,000
440
2041
930
46
11,000 460
11,000
470
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
3.4.3 Projected Secondary Emissions Increases
With the additional operation of control devices associated with the final action, CO2,
NOx, SO2, and CO emissions will be generated as a result of the additional electricity and natural
gas usage required to operate them. All secondary emissions impacts are associated with the
usage of vapor combustion and recovery units on loading racks at bulk gasoline terminals.
3-26
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Because no amendments are being finalized for loading racks at major source bulk terminals in
either the final, less stringent, or more stringent alternative options, no secondary emissions
increases are projected for MACT R. This section characterizes the projected increases of CO2,
NOx, SO2, and CO caused by the action.
Table 3-16 and Table 3-17 contain the projected secondary emissions increases
associated with the final, less stringent, and more stringent options for GACT 6B and NSPS XXa
across the analytical timeframe for the final action. The more stringent alternative options for
GACT 6B contain stricter emissions limits for loading racks at large bulk terminals, causing
slight increases in projected secondary impacts. The final, less stringent, and more stringent
alternative options for NSPS contain the same standards for loading racks, so secondary impacts
are the same across the three option packages.
Table 3-16: GACT 6B Secondary Emissions Increases (short tons)
Final/Less Stringent Options
More Stringent Options
C02
N02
S02
CO
C02
N02
S02
CO
Per-Year
32,000
19
0.05
86
32,000
19
0.10
86
2027-2041
490,000
280
0.67
1,300
490,000
280
1.5
1,300
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Table 3-17: NSPS XXa Secondary Emissions Increases, Final/Less Stringent/More
Stringent Options (Tons)
Year
C02
N02
S02
CO
2027
2,100
1.3
1.3
0
2028
2,600
1.5
1.6
0
2029
3,000
1.8
1.9
0
2030
3,400
2.0
2.1
0
2031
3,800
2.3
2.4
0
2032
4,300
2.5
2.7
0
2033
4,700
2.8
2.9
0
2034
5,100
3.0
3.2
0
2035
5,600
3.3
3.5
0
2036
6,000
3.5
3.7
0
2037
6,400
3.8
4.0
0
2038
6,800
4.0
4.3
0
2039
7,300
4.3
4.5
0
2040
7,700
4.5
4.8
0
2041
8,100
4.8
5.1
0
Total
77,000
45
48
0
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
3-27
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3.5 Engineering Cost Analysis
3,5,1 Detailed Impacts Tables
This section presents detailed impacts tables by rule and option package. All tables
contain per-year figures other than tables representing NSPS XXa, which contains figures for the
representative year 2027 (four years following expected rule promulgation). Total annualized
costs include capital cost annualized using the bank prime rate in accord with the guidance of the
EPA Air Pollution Control Cost Manual (U.S. EPA, 2017a), operating and maintenance costs,
and product recovery (recovered gasoline). To estimate these annualized costs, the EPA uses a
conventional and widely accepted approach, called equivalent uniform annual cost (EUAC) that
applies a capital recovery factor (CRF) multiplier to capital investments and adds that to the
annual incremental operating expenses to estimate annual costs. This cost estimation approach is
described in the EPA Air Pollution Control Cost Manual (U.S. EPA, 2017a). These annualized
costs are the costs to directly affected firms and facilities (or "private investment"), and thus are
not true social costs. Detailed discussion of these costs can be found in the technical memos
produced for each rule that can be found in the docket. Gasoline product recovery estimates by
emissions point are shown below, and the concept of product recovery is discussed earlier in
Section 3.2.6. The bank prime rate was 7.75 percent at the time of the cost analysis. All cost
estimates are in 2021$.
3.5.1.1 GACT6B
Table 3-18 contains per-year impacts by emissions point for the final amendments to
GACT 6B.
3-28
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Table 3-18: Final Options, Detailed Impacts by Emissions Point (per year), GACT 6B
Emissions Point
Total Annualized
Cost without
Product
Recovery
Product Recovery
Total
Annualized
Cost with
Product
Recovery
VOC
Reductions
HAP
Reductions
Loading Racks
$10,000,000
$16,000,000
-$5,600,000
25,000
980
Storage Tanks
$1,700,000
$2,500,000
-$840,000
3,800
190
Equipment Leaks
$1,300,000
$4,800,000
-$3,500,000
7,300
730
Cargo Tanks
$1,100,000
$3,100,000
-$2,100,000
4,700
190
MRR
$6,300,000
$0
$6,300,000
0
0
Total
$20,000,000
$26,000,000
-$5,700,000
40,000
2,100
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Negative signs denote cost savings (product recovery exceeding compliance costs).
The driver of impacts from these amendments is the vapor balancing requirement for loading
racks at bulk plants, which accounts for about 96 percent of the annualized costs associated with
loading racks and about 97 percent of the emissions reductions. Loading racks in total account
for about 62 percent of the VOC reductions from the final amendments to GACT 6B, with the
remainder coming from storage tanks, equipment leaks, and cargo tanks in roughly equal
measure. The second largest component of annualized cost is those resulting from the updates to
Monitoring, Reporting, and Recordkeeping (MRR). These MRR updates include additional
monitoring of flares and thermal combustion units at loading racks, periodic testing of thermal
combustion units at loading racks, and annual LEL (lower explosive level) monitoring at storage
vessels as described in the monitoring options and costs memo prepared for this final action
(RTI, 2023).
Note that annual instrument monitoring for equipment leaks is cost-saving relative to the
current requirement of monthly AVO monitoring. This is due to the cost savings realized by
reducing monitoring frequency from monthly to annual. This occurs despite instrument
monitoring (by either OGI or Method 21) being more costly per monitoring event (and in the
case of OGI requiring capital usage). As monitoring frequency increases, instrument monitoring
is less likely to be cost-saving relative to current AVO. See the Technical Memo on Equipment
Leaks (RTI, 2023) for details of the analysis.
3-29
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Table 3-19: Less Stringent Options, Detailed Impacts by Emissions Point (per year), GACT
6B
Total Annualized
Total Annualized
voc
HAP
Emissions Point
Cost without Product
Product Recovery
Cost with Product
Reductions
Reductions
Recovery
Recovery
(tpy)
(tpy)
Loading Racks
$440,000
$90,000
$350,000
820
33
Storage Tanks
$0
$0
$0
0
0
Equipment Leaks
$1,300,000
$4,800,000
-$3,500,000
7,300
730
Cargo Tanks
$600,000
$2,200,000
-$1,600,000
3,300
130
MRR
$4,800,000
$0
$4,800,000
0
0
Total
$7,100,000
$7,100,000
$20,000
11,000
890
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Negative signs denote cost savings (product recovery exceeding compliance costs, or savings without product recovery). Options
described in Table 3-7.
Table 3-19 contains per-year impacts by emissions point for the less stringent alternative
options for GACT 6B. The main difference from the final options is removal of the requirement
for vapor-balancing systems at bulk plants, which substantially reduces annualized cost and
emissions reductions. MRR is by far the largest component of cost for the less stringent
alternative option package.
Table 3-20: More Stringent Options, Detailed Impacts by Emissions Point (per year),
GACT 6B
Emissions Point
Total
Annualized
Cost without
Product
Recovery
Product Recovery
Total
Annualized
Cost with
Product
Recovery
VOC
Reductions
(tpy)
HAP
Reductions
(tpy)
Loading Racks
$13,000,000
$16,000,000
-$2,900,000
27,000
1,100
Storage Tanks
$31,000,000
$5,100,000
$26,000,000
7,700
380
Equipment Leaks
$15,000,000
$7,200,000
$7,300,000
11,000
1,100
Cargo Tanks
$1,500,000
$3,300,000
-$1,800,000
5,000
200
MRR
$6,300,000
$0
$6,300,000
0
0
Total
$67,000,000
$32,000,000
$35,000,000
50,000
2,700
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Negative signs denote cost savings (product recovery exceeding compliance costs). Options are summarized in Table 3-11.
Table 3-20 contains per-year impacts by emissions point for the more stringent
alternative options for GACT 6B. The more stringent alternative options tighten requirements at
every emissions point (excluding MRR). The main driver of emissions reductions continues to be
the loading rack requirement, which accounts for more than half of emissions reductions. The
requirement for IFR tanks to meet NSPS Kb standards results in a major increase in annualized
costs with a comparatively small increase in emissions reductions. Tightening standards for IFR
tanks is substantially more costly than for EFR tanks because most of the tanks at gasoline
3-30
-------
distribution facilities are IFR tanks. Further, per-tank emissions reductions are much lower when
upgrading an IFR tank to Kb relative to an EFR tank. One result of having IFR tanks meet NSPS
Kb standards is that the costs of equipment leak controls exceeds that of the product recovery
that would occur as a result of these controls, hence yielding a positive annualized cost as a
whole.
3.5.1.2 MACTR
Table 3-21 contains per-year impacts by emissions point for the final amendments to
MACT R, which tighten requirements for storage tanks, equipment leak monitoring, cargo tank
vapor-tightness, and MRR.
Table 3-21: Final Options, Detailed Impacts by Emissions Point (per year), MACT R
Total
Total Annualized Annualized VOC HAP
Emissions Point Cost without Product Product Recovery Cost with Reductions Reductions
Recovery
Product
Recovery
(tpy)
(tpy)
Loading Racks
$0
$0
$0
0
0
Storage Tanks
$310,000
$420,000
-$100,000
630
31
Equipment Leaks
$150,000
$450,000
-$300,000
690
69
Cargo Tanks
$640,000
$560,000
$82,000
850
34
MRR
$2,200,000
$0
$2,200,000
0
0
Total
$3,300,000
$1,400,000
$1,900,000
2,200
130
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Negative signs denote cost savings (product recovery exceeding compliance costs, or savings in costs without product recovery).
The majority of the annualized costs come from increased MRR requirements, and emissions
reductions are small compared to those for GACT 6B due to the smaller number of major source
facilities. Note that, as with GACT 6B, OGI monitoring for equipment leaks is projected to be
cost-saving relative to the current monthly AVO inspection requirement due to cost savings from
reduced monitoring frequency (semiannual vs monthly).
3-31
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Table 3-22: Less Stringent Options, Detailed Impacts by Emissions Point (per year),
MACTR
Emissions Point
Total Annualized
Cost without Product
Recovery
Product Recovery
Total
Annualized
Cost with
Product
Recovery
voc
Reductions
(tpy)
HAP
Reductions
(tpy)
Loading Racks
$0
$0
$0
0
0
Storage Tanks
$0
$0
$0
0
0
Equipment Leaks
-$150,000
$300,000
-$450,000
460
46
Cargo Tanks
$360,000
$0
$360,000
0
0
MRR
$2,200,000
$0
$2,200,000
0
0
Total
$2,500,000
$300,000
$2,100,000
460
46
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Negative signs denote cost savings (product recovery exceeding compliance costs, or savings in costs without product recovery).
Table 3-22 contains per-year impacts by emissions point for the less stringent alternative
options for MACT R. The less stringent set of alternative options maintains storage tank and
cargo tank vapor tightness requirements at their current level and reduces the frequency of
equipment leak monitoring from semiannual to annual. All emissions reductions come from
LDAR, and the bulk of the costs once again come from increased MRR.
Table 3-23: More Stringent Options, Detailed Impacts by Emissions Point (per year),
MACTR
Emissions Point
Total Annualized
Cost without
Product Recovery
Product Recovery
Total
Annualized
Cost with
Product
Recovery
VOC
Reductions
(tpy)
HAP
Reductions
(tpy)
Loading Racks
$0
$0
$0
0
0
Storage Tanks
$6,700,000
$560,000
$6,100,000
850
42
Equipment Leaks
$690,000
$540,000
$150,000
820
82
Cargo Tanks
$940,000
$680,000
$270,000
1,000
41
MRR
$2,200,000
$0
$2,200,000
0
0
Total
$11,000,000
$1,800,000
$8,700,000
2,700
170
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Table 3-23 contains per-year impacts by emissions point for the more stringent
alternative options for MACT R. As with the more stringent alternative options for GACT 6B,
the requirement for IFR tanks to meet NSPS Kb standards increases costs dramatically while
only marginally reducing emissions. Increased equipment leak monitoring frequency and stricter
vapor-tightness requirements for cargo tanks lead to small increases in cost and emission
reductions.
3-32
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3.5.1.3 NSPSXXa
Table 3-24 contains impacts by emissions point for the final NSPS XXa in 2027,
assuming 5 new and 15 modified/reconstructed facilities 5 years following promulgation.
Table 3-24: Final Options, Detailed Impacts by Emissions Point (2027), NSPS XXa
Emissions Point
Total
Annualized Cost
without Product
Recovery
Product Recovery
Total
Annualized
Cost with
Product
Recovery
voc
Reductions
(tpy)
HAP
Reductions
(tpy)
Loading Racks
$1,700,000
$1,700,000
-$48,000
2,600
100
Equipment Leaks
$58,000
$43,000
$15,000
65
7
Cargo Tanks
$66,000
$200,000
-$130,000
290
12
MRR
$230,000
$0
$230,000
0
0
Total
$2,000,000
$1,900,000
$66,000
2,900
120
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Negative signs denote cost savings (product recovery exceeding compliance costs, or savings in costs without product recovery).
The majority of annualized cost and emissions reductions result from tight emissions limits on
loading racks. Both costs and emissions overall are relatively small for the final NSPS XXa.
Table 3-25: Less Stringent Options, Detailed Impacts by Emissions Point (2027), NSPS
XXa
Emissions Point
Total
Annualized Cost
without Product
Recovery
Product Recovery
Total
Annualized
Cost with
Product
Recovery
VOC
Reductions
(tpy)
HAP
Reductions
(tpy)
Loading Racks
$0
$0
$0
0
0
Equipment Leaks
-$15,000
$24,000
-$39,000
37
4
Cargo Tanks
$37,000
$140,000
-$100,000
210
8
MRR
$230,000
$0
$230,000
0
0
Total
$250,000
$160,000
$89,000
240
12
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Negative signs denote cost savings (product recovery exceeding compliance costs, or savings in costs without product recovery).
Table 3-25 contains impacts by emissions point for the less stringent alternative options
for NSPS XXa in 2027, assuming 5 new and 15 modified/reconstructed facilities 5 years
following promulgation. The less stringent alternative options for NSPS XXa maintain loading
emissions at their current level, and thus eliminated most of the cost and emissions reductions.
Equipment leak monitoring frequency is reduced, and cargo tank vapor-tightness requirements
are also loosened relative to the final options, marginally impacting cost and emissions
reductions.
3-33
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Table 3-26: More Stringent Options, Detailed Impacts by Emissions Point (2027), NSPS
XXa
Emissions Point
Total
Annualized Cost
without Product
Recovery
Product Recovery
Total
Annualized
Cost with
Product
Recovery
voc
Reductions
HAP
Reductions
Loading Racks
$1,700,000
$1,700,000
-$48,000
2,600
100
Equipment Leaks
$58,000
$43,000
$15,000
65
7
Cargo Tanks
$97,000
$210,000
-$110,000
310
13
MRR
$230,000
$0
$230,000
0
0
Total
$2,000,000
$2,000,000
$85,000
3,000
120
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
Negative signs denote cost savings (product recovery exceeding compliance costs, or savings in costs without product recovery).
Table 3-26 contains impacts by emissions point for the more stringent alternative options
for NSPS XXa in 2027, assuming 5 new and 15 modified/reconstructed facilities 5 years
following promulgation. The more stringent alternative differs from the final options only by
adopting a stricter cargo tank vapor-tightness requirement, and cost and emissions are virtually
identical under the two options.
3.5.2 Summary Cost Tables
Estimates of costs per year for each rule and regulatory option are presented below in
Table 3-27. The "Capital Cost" column reflects the per-year capital cost for a rule/regulatory
option assuming that the cost for each piece of capital is distributed evenly over the life of the
equipment applied in the cost estimate for that option. The even distribution of capital cost is an
outcome of the Equivalent Uniform Annual Cost (EUAC) method that, as mentioned earlier in
this RIA, is a cost methodology employed to estimate the compliance costs for this final
rulemaking. The "Total Capital Investment" column assumes that all capital required for
compliance with a rule/regulatory option is purchased in a single year. Total annualized costs are
reported both with and without revenue from product recovery included. See Section 3.2.6 for a
discussion of product recovery.
3-34
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Table 3-27: Estimated Annual Costs for Regulatory Options ($2021)
Rule
Option Package
Total Capital
Investment
Annualized
Capital Cost
Operation and
Maintenance
Total
Annualized Cost
w/o Revenue
Revenue from
Product
Recovery
Total
Annualized Cost
w/ Revenue
Less Stringent
$20,000
$4,000
$250,000
$250,000
$160,000
$89,000
NSPS XXa
Final
$7,200,000
$480,000
$1,200,000
$2,000,000
$1,900,000
$66,000
More Stringent
$7,200,000
$480,000
$1,200,000
$2,000,000
$2,000,000
$85,000
Less Stringent
$220,000
$44,000
$2,400,000
$2,500,000
$300,000
$2,100,000
MACTR
Final
$2,400,000
$190,000
$3,000,000
$3,300,000
$1,400,000
$1,900,000
More Stringent
$53,000,000
$3,600,000
$3,900,000
$11,000,000
$1,800,000
$8,700,000
Less Stringent
$5,800,000
$1,200,000
$5,700,000
$7,100,000
$7,100,000
$20,000
GACT 6B
Final
$66,000,000
$6,800,000
$10,000,000
$20,000,000
$26,000,000
-$5,700,000
More Stringent
$310,000,000
$23,000,000
$27,000,000
$67,000,000
$32,000,000
$35,000,000
Less Stringent
$6,000,000
$1,200,000
$8,300,000
$9,800,000
$7,600,000
$2,300,000
Total
Final
$76,000,000
$7,500,000
$15,000,000
$26,000,000
$30,000,000
-$3,800,000
More Stringent
$370,000,000
$27,000,000
$32,000,000
$79,000,000
$35,000,000
$44,000,000
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted. Negative signs denote cost savings (product recovery
exceeding compliance costs, or savings in costs without product recovery). Annual capital cost is the capital recovery costs for each option.
3-35
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Table 3-28: Present and Equivalent Annual Values of Compliance Costs of Regulatory Options, 2027-2041 (million 2021$,
discounted to 2024)
3 Percent
7 Percent
Rule
Option Package
Compliance Cost
Product Recovery
Compliance Cost
Product Recovery
PV
EAV
PV
EAV
PV
EAV
PV
EAV
Less Stringent
$6.5
$0.5
$4.2
$0.4
$4.3
$0.5
$2.8
$0.3
NSPS XXa
Final
$52
$4.4
$50
$4.2
$34
$3.8
$33
$3.7
More Stringent
$53
$4.4
$51
$4.2
$35
$3.8
$34
$3.7
Less Stringent
$28
$2.3
$3.4
$0.3
$19
$2.1
$2.4
$0.3
MACTR
Final
$38
$3.2
$16
$1.3
$27
$2.9
$11.0
$1.3
More Stringent
$120
$9.9
$20
$1.7
$84
$9.2
$14.0
$1.6
Less Stringent
$80
$6.7
$80
$6.7
$57
$6.2
$57
$6.2
GACT 6B
Final
$230
$19
$300
$25
$160
$18
$210
$23
More Stringent
$750
$63
$360
$30
$530
$58
$250
$28
Less Stringent
$110
$9.6
$88
$7.3
$80
$8.8
$62
$6.8
Total
Final
$320
$27
$360
$30
$220
$25
$250
$28
More Stringent
$920
$77
$430
$36
$650
$71
$300
$33
Note: Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted.
3-36
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As shown in Table 3-27, most of the projected cost of the final action comes from the
amendments to GACT 6B. This includes 91 percent of the annual capital cost, 71 percent of the
operation and maintenance cost, 87 percent of the total capital investment, and 79 percent of the
total annualized cost without including revenue from product recovery. GACT 6B also accounts
for the bulk of estimated revenue from product recovery (90 percent).
Table 3-28 includes the present value and equivalent annualized value of compliance cost
and revenue for the period 2027 to 2041, discounted to 2024 using social discount rates of 3
percent and 7 percent to adhere to OMB guidance in Circular A-4 for regulatory analysis. The
present value of the projected compliance cost associated with the final action is $220 million
using a 7 percent social discount rate ($320 million using a 3 percent discount rate). Of these
totals, roughly 2/3 can be attributed to GACT 6B and 1/6 to each of MACT R and NSPS XXa.
The value of product recovery is projected to be substantial, outweighing the projecting
compliance costs of the action across the three rules. About 85 percent of this value comes from
the amendments to GACT 6B, approximately in line with its share of VOC emissions reductions.
Discounted costs and revenue from product recovery for the final options presented cumulatively
for the three rules from 2027 to 2041 are contained in Table 3-29 and Table 3-30.
3-37
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Table 3-29: Discounted Capital and O&M Costs, Final Options, for NSPS XXa, MACT R, and GACT 6B, 2027-2041 (million
2021$, discounted to 2024)
3 percent 7 percent
Year
Capital Cost
Operating and
Maintenance
Cost
Revenue from
Product
Recovery
Total
Annualized
Cost with
Revenue from
Product
Recovery
Capital Cost
Operating and
Maintenance
Cost
Revenue from
Product
Recovery
Total
Annualized
Cost with
Revenue from
Product
Recovery
2027
$6.9
$13
$27
-$6.9
$6.1
$12
$24
-$6.1
2028
$6.7
$13
$27
-$6.7
$5.8
$11
$23
-$5.8
2029
$6.6
$13
$26
-$6.6
$5.5
$11
$22
-$5.4
2030
$6.5
$13
$26
-$6.4
$5.2
$10
$21
-$5.1
2031
$6.4
$13
$25
-$6.3
$4.9
$10
$19
-$4.8
2032
$6.3
$12
$25
-$6.2
$4.6
$9
$18
-$4.5
2033
$6.2
$12
$24
-$6.0
$4.4
$8.7
$17
-$4.3
2034
$6.1
$12
$24
-$5.9
$4.2
$8.3
$16
-$4.0
2035
$6.0
$12
$24
-$5.8
$3.9
$7.8
$16
-$3.8
2036
$5.9
$12
$23
-$5.6
$3.7
$7.4
$15
-$3.6
2037
$5.8
$12
$23
-$5.5
$3.5
$7.0
$14
-$3.4
2038
$5.7
$11
$22
-$5.4
$3.3
$6.7
$13
-$3.2
2039
$5.6
$11
$22
-$5.3
$3.1
$6.3
$12
-$3.0
2040
$5.5
$11
$22
-$5.1
$3.0
$6.0
$12
-$2.8
2041
$5.4
$11
$21
-$5.0
$2.8
$5.7
$11
-$2.6
Note: Discounted to 2024. Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted. Negative signs denote cost savings
(product recovery exceeding compliance costs).
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Table 3-30: Discounted Costs, Final Options, for NSPS XXa, MACT R, and GACT 6B, 2027-2041 (million 2021$, discounted
to 2024)
3 percent
7 percent
Annualized Costs
Revenue from Product
Annualized Costs (with
Annualized Costs
Revenue from
Annualized Costs
Year
(w/o Revenue)
Recovery
Revenue)
(w/o Revenue)
Product Recovery
(with Revenue)
2027
$24
$27
-$3.4
$21
$24
-$3.1
2028
$23
$27
-$3.3
$20
$23
-$2.9
2029
$23
$26
-$3.2
$19
$22
-$2.7
2030
$23
$26
-$3.1
$18
$21
-$2.5
2031
$22
$25
-$3.0
$17
$19
-$2.3
2032
$22
$25
-$2.9
$16
$18
-$2.2
2033
$22
$24
-$2.8
$15
$17
-$2.0
2034
$21
$24
-$2.7
$15
$16
-$1.9
2035
$21
$24
-$2.6
$14
$16
-$1.7
2036
$21
$23
-$2.6
$13
$15
-$1.6
2037
$20
$23
-$2.5
$12
$14
-$1.5
2038
$20
$22
-$2.4
$12
$13
-$1.4
2039
$20
$22
-$2.3
$11
$12
-$1.3
2040
$19
$22
-$2.2
$11
$12
-$1.2
2041
$19
$21
-$2.2
$10
$11
-$1.1
Note: Discounted to 2024. Totals may not sum due to independent rounding. Numbers rounded to two significant digits unless otherwise noted. Negative signs denote cost savings
(product recovery exceeding compliance costs, or savings in costs without product recovery).
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4 HUMAN HEALTH BENEFITS OF EMISSIONS REDUCTIONS
4.1 Introduction
The emission controls installed to comply with this final action are expected to reduce
emissions of volatile organic compounds (VOC) which, in conjunction with NOx and in the
presence of sunlight, form ground-level ozone (O3). This chapter reports the estimated ozone-
related benefits of reducing VOC emissions in terms of the number and value of avoided ozone-
attributable deaths and illnesses. The potential benefits from reduced ecosystem effects from the
reduction in O3 concentrations are not quantified or monetized here. Time and data limitations
for quantifying the effect of this action on biomass loss and foliar injury and the ensuing loss of
ecosystem services prevent an assessment of the benefits to ecosystems. The EPA provides a
qualitative discussion of the benefits of reducing HAP emissions later in this chapter. This
discussion can also be found in section 4.7 of the promulgated Affordable Clean Energy (ACE)
rule (U.S. EPA, 2019). Finally, we include an analysis of the climate disbenefits for this final
action.
The PV of the cumulative monetized health benefits for the final options for all 3 rules is
$240 million for short-term exposure at a 3 percent discount rate and $140 million at a 7 percent
discount rate with an EAV of $20 million and $16 million, respectively. The PV of the
cumulative monetized health benefits for the final options for all 3 rules are $2,000 million for
long-term exposure at a 3 percent discount rate and $1,200 million at a 7 percent discount rate
with an EAV of $170 million and $130 million, respectively. Specific estimates of monetized
health estimates for each final rule can be found later in this chapter in section 4.7. All estimates
are reported in 2021 dollars. The monetized climate disbenefits resulting from increasing
emissions of CO2 as presented in Chapter 3 are included in this chapter in Section 4.6. The
monetized climate disbenefits, based on interim benefit per ton estimates as explained later in
this RIA chapter, are estimated at $35 million PV at a 3 percent discount rate ($2.9 million
EAV).
4.2 Health Effects from Exposure to Hazardous Air Pollutants (HAP)
In the subsequent sections, we describe the health effects associated with the main HAP
of concern from the gasoline distribution sector: benzene (Section 4.2.1), hexane (Section 4.2.2),
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toluene (Section 4.2.3), 2,2,4-Trimethylpentane (Section 4.2.4), naphthalene (Section 4.2.5),
ethylbenzene (Section 4.2.6), xylenes (Section 4.2.7), and cumene (Section 4.2.8). This action is
projected to reduce 38,000 tons of HAP emissions over the 2027 through 2041 period, with
31,000 tons of the projected reductions coming from the final amendments to GACT 6B. With
the data available, it was not possible to estimate the change in emissions of each individual
HAP.
Monetization of the benefits of reductions in cancer incidences requires several important
inputs, including central estimates of cancer risks, estimates of exposure to carcinogenic HAP,
and estimates of the value of an avoided case of cancer (fatal and non-fatal). Due to methodology
and data limitations, we did not attempt to monetize the health benefits of reductions in HAP in
this analysis. Instead, we are providing a qualitative discussion of the health effects associated
with HAP emitted from sources subject to control under the final action. The EPA remains
committed to improving methods for estimating HAP benefits by continuing to explore
additional aspects of HAP-related risk from the gasoline distribution sector, including the
distribution of that risk.
4.2.1 Benzene
Benzene is used as a constituent in motor fuels and is found in gasoline service station
and motor vehicle exhaust emissions into air. Acute effects of benzene inhalation exposure in
humans include neurological symptoms such as drowsiness, dizziness, headaches, and
unconsciousness. Exposure to benzene vapor can cause eye, skin, and upper respiratory tract
irritation. Chronic exposure to benzene is associated with blood disorders, such as preleukemia
and aplastic anemia (ATSDR, 2007). The EPA's IRIS database lists benzene as a known human
carcinogen (causing leukemia) by all routes of exposure. IRIS found a causal relationship
between benzene exposure and acute lymphocytic leukemia and a suggestive relationship
between benzene exposure and chronic non-lymphocytic leukemia and chronic lymphocytic
leukemia (U.S. EPA, 2000). IARC has also determined that benzene is a human carcinogen
(IARC, 2018).
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4.2.2 Hexane
Hexane is used to extract edible oils from seeds and vegetables, as a special-use solvent,
and as a cleaning agent (ATSDR, 1997). Acute (short-term) inhalation exposure of humans to
high levels of hexane causes mild central nervous system (CNS) effects, including dizziness,
giddiness, slight nausea, and headache. Exposure to hexane vapors can cause dermatitis and
irritation of the eyes and throat. Chronic (long-term) exposure to hexane in air is associated with
polyneuropathy in humans, with numbness in the extremities, muscular weakness, blurred vision,
headache, and fatigue observed (Sittig, 1985). In animal studies, neurotoxic effects as well as
pulmonary and nasal lesions have been observed (ATSDR, 1997). EPA determined that hexane
was not classifiable as to human carcinogenicity (U.S. EPA, 2005a).
4.2.3 Toluene
Toluene is added to gasoline, used to produce benzene, and used as a
solvent. Automobile emissions are the principal source of toluene to the ambient air. Toluene
exposure causes toxicity to the central nervous system (CNS) in both humans and animals for
acute (short-term) and chronic (long-term) exposures (ATSDR, 2000). CNS dysfunction and
narcosis have been frequently observed in humans acutely exposed to elevated airborne levels of
toluene; symptoms include fatigue, sleepiness, headaches, and nausea. CNS depression has been
reported to occur in chronic abusers exposed to high levels of toluene. Chronic inhalation
exposure of humans to toluene also causes irritation of the upper respiratory tract and eyes, sore
throat, dizziness, and headache. Human studies have reported developmental effects, such as
CNS dysfunction, attention deficits, and minor craniofacial and limb anomalies, in the children
of pregnant women exposed to high levels of toluene or mixed solvents by inhalation (ATSDR,
2000). EPA has concluded that that there is inadequate information to assess the carcinogenic
potential of toluene (U.S. EPA, 2005b).
4.2.4 2,2,4-Trimethylpentane
2,2,4-Trimethylpentane is released to the environment through the manufacture, use, and
disposal of products associated with the petroleum and gasoline industry. In an isolated acute
exposure incident, 2,2,4-trimethylpentane penetrated the skin of a human which led to skin
necrosis and required surgery. In animals acutely exposed via inhalation or injection irritation of
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the lungs, edema, CNS depression, and hemorrhage have been observed. In rats chronically
exposed kidney and liver effects have been observed in rats exposed orally or by inhalation
(HSDB, 1993). EPA has not classified 2,2,4-trimethylpentane with respect to potential
carcinogenicity (U.S. EPA, 2007).
4.2.5 Napthalene
Naphthalene is used in the production of phthalic anhydride; it is also used in
mothballs. Acute exposure of humans to naphthalene by inhalation, ingestion, and dermal
contact is associated with hemolytic anemia and neurological damage. Cataracts have also been
reported in workers acutely exposed to naphthalene by inhalation and ingestion. Chronic (long-
term) exposure of workers and rodents to naphthalene has been reported to cause cataracts and
damage to the retina. Hemolytic anemia has been reported in infants born to mothers who
"sniffed" and ingested naphthalene (as mothballs) during pregnancy. Inflammation, hyperplasia,
and lesions have been reported in the nose of rats exposed chronically to naphthalene (ATSDR
2005; EPA, 1998). Based on the 1996 Final Guidelines for Carcinogen Risk Assessment, EPA
determined there was insufficient information to assess the carcinogenic potential of naphthalene
(U.S EPA, 1998). IARC classified naphthalene as possibly carcinogenic to humans, Group 2B
(IARC, 2002).
4.2.6 Ethylbenzene
Acute (short-term) exposure to ethylbenzene in humans results in respiratory effects, such
as throat irritation and chest constriction, irritation of the eyes, and neurological effects such as
dizziness. Chronic (long-term) exposure to ethylbenzene by inhalation in humans has shown
conflicting results regarding its effects on the blood. Animal studies have reported effects on the
blood, liver, and kidneys from chronic inhalation exposure to ethylbenzene (ATSDR,
2010). Limited information is available on the carcinogenic effects of ethylbenzene in humans.
In a study by the National Toxicology Program (NTP), exposure to ethylbenzene by inhalation
resulted in an increased incidence of kidney and testicular tumors in rats, and lung and liver
tumors in mice (NTP, 1999). EPA has classified ethylbenzene as a Group D, not classifiable as
to human carcinogenicity (U.S. EPA, 1988). IARC classified ethylbenzene as a Group 2B
carcinogen, possibly carcinogenic to humans (IARC, 2000).
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4.2.7 Xylenes
Xylenes are released into the atmosphere as fugitive emissions from industrial sources,
from auto exhaust, and through volatilization from their use as solvents. Acute (short-term)
inhalation exposure to mixed xylenes in humans results in irritation of the eyes, nose, and throat,
gastrointestinal effects, eye irritation, and neurological effects. Chronic (long-term) inhalation
exposure of humans to mixed xylenes results primarily in CNS effects, such as headache,
dizziness, fatigue, tremors, and incoordination; respiratory, cardiovascular, and kidney effects
have also been reported (ATSDR, 2007; U.S EPA, 2003). EPA determined that mixed xylenes
are not classifiable as to human carcinogenicity (U.S EPA, 2003).
4.2.8 Cumene
Cumene is used in petroleum products. Acute (short-term) inhalation exposure to
cumene may cause headaches, dizziness, drowsiness, slight incoordination, and unconsciousness
in humans. Cumene is a potent central nervous system (CNS) depressant and a skin and eye
irritant (U.S. Department of Health and Human Services, 1993). No information is available on
the chronic (long-term) effects of cumene in humans. Animal studies have reported increased
liver, kidney, and adrenal weights from inhalation exposure to cumene. EPA has classified
cumene as a Group D, not classifiable as to human carcinogenicity (U.S. EPA, 1997). IARC has
classified cumene as possibly carcinogenic to humans (Group 2B) based on sufficient evidence
of carcinogenicity in animals. Exposure to cumene by whole-body inhalation caused increased
incidence of tumors in the respiratory tract, kidney, spleen, and liver in animal studies (IARC,
2013).
4.2.9 Other Air Toxics
In addition to the compounds described above, other toxic compounds might be affected
by this action. Information regarding the health effects of those compounds can be found in the
EPA's IRIS database37.
37 U.S. EPA Integrated Risk Information System (IRIS) database is available at www.epa.gov/iris. Accessed March
30, 2022.
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4.3 VOC-related Human Health Benefits
This section summarizes the EPA's approach to estimating the incidence and economic
value of the ozone-related benefits estimated for this action. The 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. EPA, 2023a) and its corresponding Technical Support Document (TSD) EstimatingPM2.5-
and Ozone - Attributable Health Benefits (TSD) (U.S. EPA, 2023b) provide a full discussion of
the EPA's approach for quantifying the incidence and value of estimated air pollution-related
health impacts. In these documents, the reader can find the rationale for selecting the health
endpoints quantified; the demographic, health and economic data applied in the environmental
Benefits Mapping and Analysis Program—Community Edition (BenMAP-CE); modeling
assumptions; and the EPA's techniques for quantifying uncertainty.
Implementing this action will affect the distribution of ozone concentrations throughout
the U.S.; this includes locations both meeting and exceeding the NAAQS for O3. This RIA
estimates avoided Cb-related health impacts that are distinct from those reported in the RIAs for
the O3 NAAQS (U.S. EPA, 2015a). The O3 NAAQS RIAs hypothesize, but do not predict, the
benefits and costs of strategies that States may choose to enact when implementing a revised
NAAQS; these costs and benefits are illustrative and cannot be added to the costs and benefits of
policies that prescribe specific emission control measures.
4,3,1 Estimating Ozone Related Health Impacts
We estimate the quantity and economic value of air pollution-related effects by
estimating counts of air pollution-attributable cases of adverse health outcomes, assigning dollar
values to these counts, and assuming that each outcome is independent of one another. We
construct these estimates by adapting primary research—specifically, air pollution epidemiology
studies and economic value studies—from similar contexts. This approach is sometimes referred
to as "benefits transfer." Below we describe the procedure we follow for: (1) selecting air
pollution health endpoints to quantify; (2) calculating counts of air pollution effects using a
health impact function; (3) specifying the health impact function with concentration-response
parameters drawn from the epidemiological literature.
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4.3.1.1 Selecting air pollution health endpoints to quantify
As a first step in quantifying Cb-related human health impacts, the EPA consults the
Integrated Science Assessment for Ozone (Ozone ISA) (U.S. EPA, 2020) as summarized in the
TSD for The Regulatory Impact Analysis for the Proposed National Emission Standards for
Hazardous Air Pollutants: Coal- and Oil-FiredElectric Utility Steam Generating Units Review
of the Residual Risk and Technology Review (U.S. EPA, 2023b). This document synthesizes the
toxicological, clinical, and epidemiological evidence to determine whether each pollutant is
causally related to an array of adverse human health outcomes associated with either acute (i.e.,
hours or days-long) or chronic (i.e., years-long) exposure. For each outcome, the ISA reports this
relationship to be causal, likely to be causal, suggestive of a causal relationship, inadequate to
infer a causal relationship, or not likely to be a causal relationship.
In brief, the ISA for ozone found short-term (less than one month) exposures to ozone to
be causally related to respiratory effects, a "likely to be causal" relationship with metabolic
effects and a "suggestive of, but not sufficient to infer, a causal relationship" for central nervous
system effects, cardiovascular effects, and total mortality. The ISA reported that long-term
exposures (one month or longer) to ozone are "likely to be causal" for respiratory effects
including respiratory mortality, and a "suggestive of, but not sufficient to infer, a causal
relationship" for cardiovascular effects, reproductive effects, central nervous system effects,
metabolic effects, and total mortality.
The EPA estimates the incidence of air pollution effects for those health endpoints listed
above where the ISA classified the impact as either causal or likely-to-be-causal. Table 4-1
reports the effects we quantified and those we did not quantify in this RIA. The list of benefit
categories not quantified shown in that table is not exhaustive. And, among the effects we
quantified, we might not have been able to completely quantify either all human health impacts
or economic values. The table below omits any welfare effects such as biomass loss and foliar
injury. These effects are described in Chapter 7 of the Ozone NAAQS RIA (2015).
4-7
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Table 4-1: Human Health Effects of Ambient Ozone
Category
Effect
Effect
Quantified
Effect
Monetized
More
Information
Mortality from
Premature respiratory mortality from
short-term exposure (0-99)
V
V
Ozone ISA1
exposure to ozone
Premature respiratory mortality from
long-term exposure (age 30-99)
V
V
Ozone ISA
Hospital admissions—respiratory (ages
65-99)
V
V
Ozone ISA
Emergency department visits—
respiratory (ages 0-99)
V
V
Ozone ISA
Asthma onset (0-17)
V
V
Ozone ISA
Asthma symptoms/exacerbation
(asthmatics age 5-17)
V
V
Ozone ISA
Nonfatal morbidity
from exposure to
Allergic rhinitis (hay fever) symptoms
(ages 3-17)
V
V
Ozone ISA
Minor restricted-activity days (age 18-
65)
V
V
Ozone ISA
ozone
School absence days (age 5-17)
V
V
Ozone ISA
Decreased outdoor worker productivity
(age 18-65)
—
—
Ozone ISA2
Metabolic effects (e.g., diabetes)
—
—
Ozone ISA2
Other respiratory effects (e.g., premature
aging of lungs)
—
—
Ozone ISA2
Cardiovascular and nervous system
effects
—
—
Ozone ISA2
Reproductive and developmental effects
—
—
Ozone ISA2
1 We assess these benefits qualitatively due to data and resource limitations for this analysis. In other analyses we
quantified these effects as a sensitivity analysis.
2 We assess these benefits qualitatively because we do not have sufficient confidence in available data or methods.
4.3.1.2 Quantifying Cases of Ozone-A ttributable Premature Mortality
Mortality risk reductions account for the majority of monetized ozone-related benefits.
For this reason, this subsection and the following provide a brief background of the scientific
assessments that underly the quantification of these mortality risks and identifies the risk studies
used to quantify them in this RIA for ozone. As noted above, the Estimating PM2.5- and Ozone-
Attributable Health Benefits TSD describes fully the Agency's approach for quantifying the
number and value of ozone air pollution-related impacts, including additional discussion of how
the Agency selected the risk studies used to quantify them in this RIA. The TSD also includes
additional discussion of the assessments that support quantification of these mortality risk than
provide here.
In 2008, the National Academies of Science (NRC 2008) issued a series of
recommendations to EPA regarding the procedure for quantifying and valuing ozone-related
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mortality due to short-term exposures. Chief among these was that"... short-term exposure to
ambient ozone is likely to contribute to premature deaths" and the committee recommended that
"ozone-related mortality be included in future estimates of the health benefits of reducing ozone
exposures..." The NAS also recommended that".. .the greatest emphasis be placed on the
multicity and [National Mortality and Morbidity Air Pollution Studies (NMMAPS)] ... studies
without exclusion of the meta-analyses" (NRC 2008). Prior to the 2015 Ozone NAAQS RIA, the
Agency estimated ozone-attributable premature deaths using an NMMAPS-based analysis of
total mortality (Bell et al. 2004), two multi-city studies of cardiopulmonary and total mortality
(Huang et al. 2004; Schwartz 2005) and effect estimates from three meta-analyses of non-
accidental mortality (Bell et al. 2005; Ito et al. 2005; Levy et al. 2005). Beginning with the 2015
Ozone NAAQS RIA, the Agency began quantifying ozone-attributable premature deaths using
two newer multi-city studies of non-accidental mortality (Smith et al. 2009; Zanobetti and
Schwartz 2008) and one long-term cohort study of respiratory mortality (Jerrett et al. 2009). The
2020 Ozone ISA included changes to the causality relationship determinations between short-
term exposures and total mortality, as well as including more recent epidemiologic analyses of
long-term exposure effects on respiratory mortality (U.S. EPA, 2020). In this RIA, as described
in the corresponding TSD, two estimates of ozone-attributable respiratory deaths from short-term
exposures are estimated using the risk estimate parameters from Zanobetti et al. (2008) and
Katsouyanni et al. (2009). Ozone-attributable respiratory deaths from long-term exposures are
estimated using Turner et al. (2016). Due to time and resource limitations, we were unable to
reflect the warm season defined by Zanobetti et al. (2008) as June-August. Instead, we apply this
risk estimate to our standard warm season of May-September.
4.3.1.3 Economic Valuation
After quantifying the change in adverse health impacts, we estimate the economic value
of these avoided impacts. Reductions in ambient concentrations of air pollution generally lower
the risk of future adverse health effects by a small amount for a large population. Therefore, the
appropriate economic measure is willingness to pay (WTP) for changes in risk of a health effect.
For some health effects, such as hospital admissions, WTP estimates are generally not available,
so we use the cost of treating or mitigating the effect. These cost-of-illness (COI) estimates
generally (although not necessarily in every case) understate the true value of reductions in risk
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of a health effect. They tend to reflect the direct expenditures related to treatment but not the
value of avoided pain and suffering from the health effect. The unit values applied in this
analysis are provided in Section 5.1 of the TSD for the Revised Cross State Update rule (U.S.
EPA, 2021).
Avoided premature deaths account for 95 percent of monetized Ozone-related benefits.
The economics literature concerning the appropriate method for valuing reductions in premature
mortality risk is still developing. The value for the projected reduction in the risk of premature
mortality is the subject of continuing discussion within the economics and public policy analysis
community. Following the advice of the SAB's Environmental Economics Advisory Committee
(SAB-EEAC), the EPA currently uses the value of statistical life (VSL) approach in calculating
estimates of mortality benefits, because we believe this calculation provides the most reasonable
single estimate of an individual's WTP for reductions in mortality risk (U.S. EPA-SAB, 2000).
The VSL approach is a summary measure for the value of small changes in mortality risk
experienced by a large number of people.
The EPA continues work to update its guidance on valuing mortality risk reductions and
consulted several times with the SAB-EEAC on the issue. Until updated guidance is available,
the EPA determined that a single, peer-reviewed estimate applied consistently best reflects the
SAB-EEAC advice it has received. Therefore, the EPA applies the VSL that was vetted and
endorsed by the SAB in the Guidelines for Preparing Economic Analyses while the EPA
continues its efforts to update its guidance on this issue (U.S. EPA, 2016). This approach
calculates a mean value across VSL estimates derived from 26 labor market and contingent
valuation studies published between 1974 and 1991. The mean VSL across these studies is $10.7
million (2016$).38
The EPA is committed to using scientifically sound, appropriately reviewed evidence in
valuing changes in the risk of premature death and continues to engage with the SAB to identify
scientifically sound approaches to update its mortality risk valuation estimates. Most recently,
the Agency final new meta-analytic approaches for updating its estimates which were
subsequently reviewed by the SAB-EEAC. The EPA is taking the SAB's formal
recommendations under advisement (U.S. EPA, 2017b).
38 In 1990$, this base VSL is $4.8 million. In 2016$, this base VSL is $10.7 million.
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Because short-term ozone-related premature mortality occurs within the analysis year, the
estimated ozone-related benefits are identical for all discount rates. When valuing changes in
ozone-attributable deaths using the Turner et al. (2016) study, we follow advice provided by the
Health Effects Subcommittee of the SAB, which found that. .there is no evidence in the
literature to support a different cessation lag between ozone and particulate matter. The HES
therefore recommends using the same cessation lag structure and assumptions as for particulate
matter when utilizing cohort mortality evidence for ozone" (U.S. EPA-SAB 2010).
These estimated health benefits do not account for the influence of future changes in the
climate on ambient concentrations of pollutants (USGCRP 2016). For example, recent research
suggests that future changes to climate may create conditions more conducive to forming ozone.
The estimated health benefits also do not consider the potential for climate-induced changes in
temperature to modify the relationship between ozone and the risk of premature mortality (Jhun
et al. 2014; Ren et al. 2008a, 2008b).
4.3.1.4 Benefit-per-Ton Estimates
Because the estimated emissions reductions due to this rule are small and because we
cannot be confident of the location of new facilities under the NSPS, EPA elected to use the
benefit per-ton (BPT) approach. BPT estimates provide the total monetized human health
benefits (the sum of premature mortality and premature morbidity) of reducing one ton of the
VOC precursor for ozone from a specified source. Specifically, in this analysis, we multiplied
the estimates from the "Gasoline Distribution" sector by the corresponding emission reductions.
The method used to derive these estimates is described in the BPT Technical Support Document
(BPT TSD) on Estimating the Benefit per Ton of Reducing Directly-Emitted PM2.5, PM2.5
Precursors and Ozone Precursors from 21 Sectors (U.S. EPA, 2023c). One limitation of using
the BPT approach is an inability to provide estimates of the health benefits associated with
exposure to HAP, CO, and NO2.
As noted below in the characterization of uncertainty, all BPT estimates have inherent
limitations. Specifically, all national-average BPT estimates reflect the geographic distribution of
the modeled emissions, which may not exactly match the emission reductions that would occur
due to the action, and they may not reflect local variability in population density, meteorology,
exposure, baseline health incidence rates, or other local factors for any specific location. Given
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sector specific air quality modeling and the small changes in emissions considered in this action,
the difference in the quantified health benefits that result from the BPT approach compared with
if EPA had used a full-form air quality model should be minimal.
The EPA systematically compared the changes in benefits, and concentrations where
available, from its BPT technique and other reduced-form techniques to the changes in benefits
and concentrations derived from full-form photochemical model representation of a few different
specific emissions scenarios. Reduced form tools are less complex than the full air quality
modeling, requiring less agency resources and time. That work, in which we also explore other
reduced form models is referred to as the "Reduced Form Tool Evaluation Project" (Project),
began in 2017, and the initial results were available at the end of 2018. The Agency's goal was to
create a methodology by which investigators could better understand the suitability of alternative
reduced-form air quality modeling techniques for estimating the health impacts of criteria
pollutant emissions changes in the EPA's benefit-cost analysis, including the extent to which
reduced form models may over- or under-estimate benefits (compared to full-scale modeling)
under different scenarios and air quality concentrations. The EPA Science Advisory Board
(SAB) recently convened a panel to review this report.39 In particular, the SAB will assess the
techniques the Agency used to appraise these tools; the Agency's approach for depicting the
results of reduced-form tools; and steps the Agency might take for improving the reliability of
reduced-form techniques for use in future Regulatory Impact Analyses (RIAs).
The scenario-specific emission inputs developed for this project are currently available
online. The study design and methodology are described in the final report summarizing the
results of the project (IEc, 2019. Evaluating Reduced-Form Tools for Estimating Air Quality
Benefits. Final Report). Results of this project found that total PM2.5 BPT values were within
approximately 10 percent of the health benefits calculated from full-form air quality modeling
when analyzing the Pulp and Paper sector, a sector used as an example for evaluating the
application of the new methodology in the final report. The ratios for individual species varied,
and the report found that the ratio for the directly emitted PM2.5 for the pulp and paper sector was
0.7 for the BPT approach compared to 1.0 for full air quality modeling combined with BenMAP.
39 85 FR 23823. April 29, 2020.
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This provides some initial understanding of the uncertainty which is associated with using the
BPT approach instead of full air quality modeling.
4.3.2 Ozone Vegetation Effects
Exposure to ozone has been found to be associated with a wide array of vegetation and
ecosystem effects in the published literature (U.S. EPA, 2020). Sensitivity to ozone is highly
variable across species, with over 66 vegetation species identified as "ozone-sensitive," many of
which occur in state and national parks and forests. These effects include those that cause
damage to, or impairment of, the intended use of the plant or ecosystem. Such effects are
considered adverse to public welfare and can include reduced growth and/or biomass production
in sensitive trees, reduced yield and quality of crops, visible foliar injury, changed to species
composition, and changes in ecosystems and associated ecosystem services.
4.3.3 Ozone Climate Effects
Ozone is a well-known short-lived climate forcing GHG (U.S. EPA, 2013). Stratospheric
ozone (the upper ozone layer) is beneficial because it protects life on Earth from the sun's
harmful ultraviolet (UV) radiation. In contrast, tropospheric ozone (ozone in the lower
atmosphere) is a harmful air pollutant that adversely affects human health and the environment
and contributes significantly to regional and global climate change. Due to its short atmospheric
lifetime, tropospheric ozone concentrations exhibit large spatial and temporal variability (U.S.
EPA, 2009b). The IPCC AR5 estimated that the contribution to current warming levels of
increased tropospheric ozone concentrations resulting from human methane, NOx, and VOC
emissions was 0.5 W/m2, or about 30 percent as large a warming influence as elevated CO2
concentrations. This quantifiable influence of ground level ozone on climate leads to increases in
global surface temperature and changes in hydrological cycles.
4.4 VOC-Related Ozone Benefits Results
Table 4-2 lists the estimated ozone-related benefits per ton applied in this national level
analysis. Benefits are discounted at 3 and 7 percent for a 2021 currency year. Table 4-3 presents
the estimated ozone benefits from emission reductions for the GACT 6B (area source) portion of
this action. Table 4-4 presents the estimated ozone benefits from emission reductions for the
MACT R (major source) portion of this action. Table 4-5 shows the estimated ozone-related
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benefits per ton applied in this analysis for affected the NSPS XXa (new units) portion of this
action, respectively. Finally, Table 4-6 presents the total health related benefits of reducing
emissions of ozone for all three rules. For all estimates, we summarize the monetized ozone-
related health benefits using discount rates of 3 percent and 7 percent for both short-term and
long-term effects for the 15-year analysis period of these rules discounted back to 2024 and
rounded to 2 significant figures. The PV of the cumulative monetized health benefits for the final
options for all 3 rules are $240 million for short-term exposure at a 3 percent discount rate and
$140 million at a 7 percent discount rate with an EAV of $20 million and $16 million,
respectively. The PV of the cumulative monetized health benefits for the final options for all 3
rules are $2,000 million for long-term exposure at a 3 percent discount rate and $1,200 million at
a 7 percent discount rate with an EAV of $170 million and $130 million, respectively. For the
full set of underlying calculations see the "Gasoline Distribution Benefits workbook", available
in the docket for the final rule (docket number EPA-HQ-OAR-2020-0371). Undiscounted
benefits for final, less stringent, and more stringent alternative options for all rules cumulatively
are in Table 4-7, Table 4-8, and Table 4-9 below.
The tables below do not include non-monetized benefits associated with the rule,
including any benefits associated with HAP emission reductions (including reductions of
benzene, hexane, toluene, 2,2,4-trimethylpentane, napthalene, ethylbenzene, xylenes, and
cumene). For the estimated HAP emissions reduction, see Section 3.4. For a discussion of the
health effects of these HAP, see Section 4.2. These non-monetized benefits also include ozone
climate impacts and benefits to ecosystem services associated with improvements in biomass
loss and foliar injury.
Table 4-2: Gasoline Distribution: Benefit per Ton Estimates of Ozone-Attributable
Premature Mortality and Illness, 2027-2041 (2021$)
Discount Rate
Year
3 Percent
7 Percent
2025
$934
and
$7,198
$831
and
$6,436
2030
$1,001
and
$8,003
$896
and
$7,166
2035
$1,069
and
$8,892
$955
and
$7,960
2040
$1,122
and
$9,675
$1,009
and
$8,670
Note: The standard reporting convention for EPA benefits is to round all results to two significant figures. Here, we report all
significant figures so that readers may reproduce the results reported below.
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Table 4-3: Gasoline Distribution GACT 6B: Monetized Benefits Estimates of Ozone-Attributable Premature Mortality and
Illness (million 2021$)a'b
GACT 6B
Less Stringent Regulatory Option Final Regulatory Option More Stringent Regulatory Option
Discount Rate Discount Rate Discount Rate
3 Percent 7 Percent 3 Percent 7 Percent 3 Percent 7 Percent
PV 58 and 460 34 and 280 200 and 1,600 120 and 980 250 and 2,000 150 and 1,200
EAV 4.9 and 39 3.7 and 30 17 and 140 13 and 110 21 and 170 16 and 130
discounted to 2024. Calculations of PV and EAV reflect benefits estimates for the 2027-2041 analysis timeframe described in Chapter 1 of this RIA.
bRounded to 2 significant figures.
Table 4-4: Gasoline Distribution MACT R: Monetized Benefits Estimates of Ozone-Attributable Premature Mortality and
Illness (million 2021$)a'b
MACT R
Less Stringent Regulatory Option Final Regulatory Option More Stringent Regulatory Option
Discount Rate Discount Rate Discount Rate
3 Percent 7 Percent 3 Percent 7 Percent 3 Percent 7 Percent
PV 23 and 19 L4 and II II and 87 63 and 52 13 and 110 8~0 and 65
EAV 0.19 and 1.6 0.15 and 1.2 0.89 and 7.3 0.70 and 5.8 1.1 and 9.0 0.87 and 7.1
discounted to 2024. Calculations of PV and EAV reflect benefits estimates for the 2027-2041 analysis timeframe described in Chapter 1 of this RIA.
bRounded to 2 significant figures.
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Table 4-5: Gasoline Distribution NSPS XXa: Monetized Benefits Estimates of Ozone-Attributable Premature Mortality and
Illness (million 2021$)a'b
NSPS XXa
Less Stringent Regulatory Option Final Regulatory Option More Stringent Regulatory Option
Discount Rate Discount Rate Discount Rate
3 Percent 7 Percent 3 Percent 7 Percent 3 Percent 7 Percent
PV 23 and 23 L6 and 13 34 and 280 19 and 160 34 and 280 19 and 160
EAV 0.24 and 2.0 0.17 and 1.4 2.8 and 24 2.1 and 17 2.9 and 24 2.1 and 18
^Discounted to 2024. Calculations of PV and EAV reflect benefits estimates for the 2027-2041 analysis timeframe described in Chapter 1 of this RIA.
bRounded to 2 significant figures.
Table 4-6: Gasoline Distribution All Rules: Monetized Benefits Estimates of Ozone-Attributable Premature Mortality and
Illness (million 2021$)a'b
All Rules
Less Stringent Regulatory Option Final Regulatory Option More Stringent Regulatory Option
Discount Rate Discount Rate Discount Rate
3 Percent 7 Percent 3 Percent 7 Percent 3 Percent 7 Percent
PV 63 and 500 37 and 300 240 and 2,000 140 and 1,200 290 and 2,400 180 and 1,400
EAV 5.3 and 42 4.0 and 33 20 and 170 16 and 130 25 and 200 19 and 160
discounted to 2024. Calculations of PV and EAV reflect benefits estimates for the 2027-2041 analysis timeframe described in Chapter 1 of this RIA.
bRounded to 2 significant figures.
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Table 4-7: Gasoline Distribution All Rules, Final Regulatory Options: Undiscounted
Monetized Benefits Estimates of Ozone-Attributable Premature Mortality and Illness
(million 2021$)
3% 7%
Year
2026
$18
$140
$16
$130
2027
$20
$160
$18
$140
2028
$20
$160
$18
$140
2029
$20
$160
$18
$150
2030
$21
$160
$18
$150
2031
$21
$170
$19
$150
2032
$22
$190
$20
$170
2033
$23
$190
$20
$170
2034
$23
$190
$21
$170
2035
$23
$190
$21
$170
2036
$24
$200
$21
$180
2037
$25
$220
$22
$190
2038
$25
$220
$23
$200
2039
$26
$220
$23
$200
2040
$26
$220
$23
$200
Note: Rounded to 2 significant figures.
Table 4-8: Gasoline Distribution All Rules, Less Stringent Regulatory Options:
Undiscounted Monetized Benefits Estimates of Ozone-Attributable Premature Mortality
and Illness (million 2021$)
3% 7%
Year
2026
$4.9
$37
$4.3
$34
2027
$5.2
$42
$4.7
$37
2028
$5.3
$42
$4.7
$38
2029
$5.3
$42
$4.7
$38
2030
$5.3
$42
$4.7
$38
2031
$5.3
$43
$4.8
$38
2032
$5.7
$47
$5.1
$42
2033
$5.7
$48
$5.1
$43
2034
$5.7
$48
$5.1
$43
2035
$5.8
$48
$5.2
$43
2036
$5.8
$48
$5.2
$43
2037
$6.1
$53
$5.5
$47
2038
$6.1
$53
$5.5
$47
2039
$6.1
$53
$5.5
$48
2040
$6.2
$53
$5.5
$48
Note: Rounded to 2 significant figures.
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Table 4-9: Gasoline Distribution All Rules, More Stringent Regulatory Options:
Undiscounted Monetized Benefits Estimates of Ozone-Attributable Premature Mortality
and Illness (million 2021$)
3% 7%
Year
2026
$22
$170
$20
$150
2027
$24
$190
$22
$170
2028
$24
$200
$22
$180
2029
$25
$200
$22
$180
2030
$25
$200
$22
$180
2031
$25
$200
$23
$180
2032
$27
$230
$24
$200
2033
$28
$230
$25
$200
2034
$28
$230
$25
$210
2035
$28
$230
$25
$210
2036
$28
$240
$25
$210
2037
$30
$260
$27
$230
2038
$30
$260
$27
$230
2039
$31
$260
$27
$240
2040
$31
$270
$28
$240
Note: Rounded to 2 significant figures.
4.5 Characterization of Uncertainty in the Monetized VOC Benefits
In any complex analysis using estimated parameters and inputs from a variety of models,
there are likely to be many sources of uncertainty. This analysis is no exception. This analysis
includes many data sources as inputs, including emission inventories, air quality data from
models (with their associated parameters and inputs), population data, population estimates,
health effect estimates from epidemiology studies, economic data for monetizing benefits, and
assumptions regarding the future state of the world (i.e., regulations, technology, and human
behavior). Each of these inputs are uncertain and generate uncertainty in the benefits estimate.
When the uncertainties from each stage of the analysis are compounded, even small uncertainties
can have large effects on the total quantified benefits. Therefore, the estimates of annual benefits
should be viewed as representative of the magnitude of benefits expected, rather than the actual
benefits that would occur every year.
This RIA does not include the type of detailed uncertainty assessment found in the TSD
for the 2022 PM NAAQS Reconsideration Proposal RIA Estimating PM2.5- and Ozone-
Attributable Health Benefits (U.S. EPA, 2023d) because we lack the necessary air quality input
and monitoring data. Criteria pollutant emissions changes were relatively small on a percentage
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basis, which made air quality modeling impractical. However, the results of the uncertainty
analyses presented in the 2021 Revised Cross State Update RIA can provide some information
regarding the uncertainty inherent in the benefits results presented in this analysis.
4.6 Climate Impacts
With the additional operation of control devices associated with the final action, CO2
emissions will be generated as a result of the additional electricity required to operate them. The
estimate of additional CO2 emissions is presented in Chapter 3. There will be climate disbenefits
associated with these additional CO2 emissions that we calculate using an interim measure of the
social cost of carbon (SC-CO2).
Elevated concentrations of CO2 and other greenhouse gases (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.
Extensive information on climate change is available in the scientific assessments and
EPA documents that are briefly described in this section, as well as in the technical and scientific
information supporting them. One of those documents is EPA's 2009 Endangerment and Cause
or Contribute Findings for Greenhouse Gases Under section 202(a) of the CAA (74 FR 66496,
December 15, 2009). In the 2009 Endangerment Finding, the Administrator found under section
202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs - CO2,
methane (CH4), nitrous oxide (N2O), HFCs, perfluorocarbons (PFCs), and sulfur hexafluoride
(SF6) - "may reasonably be anticipated to endanger the public health and welfare of current and
future generations" (74 FR 66523). The 2009 Endangerment Finding, together with the extensive
scientific and technical evidence in the supporting record, documented that climate change
caused by human emissions of GHGs threatens the public health of the U.S. population. It
explained that by raising average temperatures, climate change increases the likelihood of heat
waves, which are associated with increased deaths and illnesses (74 FR 66497). While climate
change also increases the likelihood of reductions in cold-related mortality, evidence indicates
that the increases in heat mortality will be larger than the decreases in cold mortality in the U.S.
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(74 FR 66525). The 2009 Endangerment Finding further explained that compared with a future
without climate change, climate change is expected to increase tropospheric ozone pollution over
broad areas of the U.S., including in the largest metropolitan areas with the worst tropospheric
ozone problems, and thereby increase the risk of adverse effects on public health (74 FR 66525).
Climate change is also expected to cause more intense hurricanes and more frequent and intense
storms of other types and heavy precipitation, with impacts on other areas of public health, such
as the potential for increased deaths, injuries, infectious and waterborne diseases, and stress-
related disorders (74 FR 66525). Children, the elderly, and the poor are among the most
vulnerable to these climate-related health effects (74 FR 66498).
The 2009 Endangerment Finding also documented, together with the extensive scientific
and technical evidence in the supporting record, that 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). These
impacts are also global and the effects of climate change occurring outside the U.S. are
reasonably expected to impact the U.S. population. (74 FR 66530).
In 2016, the Administrator issued a similar finding for GHG emissions from aircraft
under section 231(a)(2)(A) of the CAA. In the 2016 Endangerment Finding, the Administrator
found that the body of scientific evidence amassed in the record for the 2009 Endangerment
Finding compellingly supported a similar endangerment finding under CAA section
231(a)(2)(A), and also found that the science assessments released between the 2009 and the
2016 Findings "strengthen and further support the judgment that GHGs in the atmosphere may
reasonably be anticipated to endanger the public health and welfare of current and future
generations" (81 FR 54424).
Since the 2016 Endangerment Finding, the climate change impacts have continued to
intensify, with new observational records being set for several climate indicators such as global
average surface temperatures, GHG concentrations, and sea level rise. Moreover, heavy
precipitation events have increased in the eastern United States while agricultural and ecological
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drought has increased in the western United States along with more intense and larger wildfires.40
Recent assessment reports discuss how these observed trends are increasingly attributed to
human-induced climate change41 and are expected to continue and worsen over the coming
century, with stronger trends under higher warming scenarios (see e.g., USGCRP (2018) 42, IPCC
(2022a, 2022b)). Climate impacts that occur outside U.S. borders also increasingly impact the
welfare of individuals and firms that reside in the United States because of their connection to
the global economy. This will occur through the effect of climate change on international
markets, trade, tourism, and other activities. For example, supply chain disruptions are a
prominent pathway through which U.S. business and consumers are, and will continue to be,
affected by climate change impacts abroad (USGCRP 2018, U.S. DOD 2021). Additional
climate change induced international spillovers can occur through pathways such as damages
across transboundary resources, economic and political destabilization, and global migration that
can lead to adverse impacts on U.S. national security, public health, and humanitarian concerns
(U.S. DOD 2014, CCS 2018). These and other trends highlight the increased risk already being
experienced due to climate change as detailed in the 2009 and 2016 Endangerment Findings.
Additionally, new major scientific assessments continue to advance our understanding of the
climate system and the impacts that GHGs have on public health and welfare both for current
and future generations. These assessments include:
• U.S. Global Change Research Program's (USGCRP) 2016 Climate and Health
Assessment and 2017-2018 Fourth National Climate Assessment (NCA4) (USGCRP
2016, 2017, 2018).
• IPCC's 2018 Global Warming of 1.5 °C, 2019 Climate Change and Land, and the 2019
Ocean and Cryosphere in a Changing Climate assessments, as well as the 2021 IPCC
Sixth Assessment Report (AR6) (IPCC 2018, 2019a, 2019b, 2021).
40 See EPA's November 2021 Proposed Standards of Performance for New, Reconstructed, and Modified
Sourcesand Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review
(https://www.govinfo.gov/content/pkg/FR-2021-ll-15/pdf/2021-24202.pdf) for more discussion of specific
examples. An additional resource for indicators can be found at https://www.epa.gov/climate-indicators.
41 For example, "[fjield evidence shows that anthropogenic climate change has increased the area burned by wildfire
above natural levels in western North America from 1984-2017 by double for the Western USA.. .{high
confidence)" (IPCC (2022a), p. 2-5).
42 U.S. Global Change Research Program (USGCRP). 2018. Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E.
Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program,
Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
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• The National Academies of Sciences, Engineering, and Medicine's 2016 Attribution of
Extreme Weather Events in the Context of Climate Change, 2017 Valuing Climate
Damages: Updating Estimation of the Social Cost of Carbon Dioxide, and 2019 Climate
Change and Ecosystems assessments (NAS 2016, 2017, 2019).
• National Oceanic and Atmospheric Administration's (NOAA) annual State of the
Climate reports published by the Bulletin of the American Meteorological Society, most
recently in August of 2020 (Blunden and Arndt 2020).
• EPA Climate Change and Social Vulnerability in the United States: A Focus on Six
Impacts (2021) (U.S. EPA, 2021).
Net climate benefits (disbenefits) from reducing (increasing) emissions of CO2 can be
monetized using estimates of 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, environmental migration, and the
value of ecosystem services. The SC-CO2, therefore, should reflect the societal value of reducing
(or increasing) emissions of the gas in question by one metric ton. The SC-CO2 is an estimate of
the marginal benefit of CO2 abatement along the baseline and 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 of 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.
EPA and other federal agencies began regularly incorporating SC-CO2 estimates in
benefit-cost analyses conducted under Executive Order (E.O.) 1286643 in 2008, following a court
ruling in which an agency was ordered to consider the value of reducing CO2 emissions in a
rulemaking process. Specifically, the U.S. Ninth Circuit Court of Appeals remanded a fuel
economy rule to DOT for failing to monetize CO2 emission reductions, stating that "while the
43 Under E.O. 12866, agencies are required, to the extent permitted by law and where applicable, "to assess both the
costs and the benefits of the intended regulation and, recognizing that some costs and benefits are difficult to
quantify, propose or adopt a regulation only upon a reasoned determination that the benefits of the intended
regulation justify its costs." Some statutes also require agencies to conduct at least some of the same analyses
required under E.O. 12866, such as the Energy Policy and Conservation Act, which mandates the setting of fuel
economy regulations.
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record shows that there is a range of values, the value of carbon emissions reduction is certainly
not zero."44
The SC-GHG estimates presented in the February 2021 SC-GHG TSD and used in this
RIA were developed over many years, using a transparent process, peer-reviewed
methodologies, the best science available at the time of that process, and with input from the
public. Specifically, in 2009, an interagency working group (IWG) that included the EPA and
other executive branch agencies and offices was established to develop estimates relying on the
best available science for agencies to use. The IWG published SC-CO2 estimates in 2010 that
were developed from an ensemble of three widely cited integrated assessment models (IAMs)
that estimate global climate damages using highly aggregated representations of climate
processes and the global economy combined into a single modeling framework. The three IAMs
were run using a common set of input assumptions in each model for future population,
economic, and CO2 emissions growth, as well as equilibrium climate sensitivity (ECS) - a
measure of the globally averaged temperature response to increased atmospheric CO2
concentrations. These estimates were updated in 2013 based on new versions of each IAM.45 In
August 2016 the IWG published estimates of the social cost of methane (SC-CH4) and nitrous
oxide (SC-N2O) using methodologies that are consistent with the methodology underlying the
SC-CO2 estimates. The modeling approach that extends the IWG SC-CO2 methodology to non-
CO2 GHGs has undergone multiple stages of peer review. The SC-CH4 and SC-N2O estimates
were developed by Marten et al. (2015) and underwent a standard double-blind peer review
process prior to journal publication. These estimates were applied in RIAs of EPA proposed
rulemakings with CH4 and N2O emissions impacts.46 The EPA also sought additional external
peer review of technical issues associated with its application to regulatory analysis. Following
the completion of the independent external peer review of the application of the Marten et al.
(2015) estimates, the EPA began using the estimates in the primary benefit-cost analysis
calculations and tables for a number of proposed rulemakings (U.S. EPA, 2015c, 2015d). The
44 Ctr. for Biological Diversity v. Nat'l Highway Traffic Safety Admin., 538 F.3d 1172, 1200 (9th Cir. 2008).
45 Dynamic Integrated Climate and Economy (DICE) 2010 (Nordhaus, 2010), Climate Framework for Uncertainty,
Negotiation, and Distribution (FUND) 3.8 (Anthoff and Tol, 2013a, 2013b), and Policy Analysis of the
Greenhouse Gas Effect (PAGE) 2009 (Hope, 2013).
46 The SC-CH4 and SC-N20 estimates were first used in sensitivity analysis for the Proposed Rulemaking for
Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles-
Phase 2 (U.S. EPA,).
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EPA considered and responded to public comments received for the proposed rulemakings
before using the estimates in final regulatory analyses in 2016.47 In 2015, as part of the response
to public comments received to a 2013 solicitation for comments on the SC-CO2 estimates, the
IWG announced a National Academies of Sciences, Engineering, and Medicine review of the
SC-CO2 estimates to offer advice on how to approach future updates to ensure that the estimates
continue to reflect the best available science and methodologies. In January 2017, the National
Academies released their final report, Valuing Climate Damages: Updating Estimation of the
Social Cost of Carbon Dioxide (National Academies, 2017), and recommended specific criteria
for future updates to the SC-CO2 estimates, a modeling framework to satisfy the specified
criteria, and both near-term updates and longer-term research needs pertaining to various
components of the estimation process (National Academies 2017). Shortly thereafter, in March
2017, President Trump issued E.O. 13783, which disbanded the IWG, withdrew the previous SC-
GHG TSDs, and directed agencies to ensure SC-GHG estimates used in regulatory analyses are
consistent with the guidance contained in OMB's Circular A-4, "including with respect to the
consideration of domestic versus international impacts and the consideration of appropriate
discount rates" (E.O. 13783, Section 5(c)). Benefit-cost analyses following E.O. 13783 used SC-
CO2 estimates that attempted to focus on the specific share of climate change damages in the
U.S. as captured by the models (which did not reflect many pathways by which climate impacts
affect the welfare of U.S. citizens and residents) and were calculated using two default discount
rates recommended by Circular A-4, 3 percent and 7 percent.48 All other methodological
decisions and model versions used in SC-CO2 calculations remained the same as those used by
the IWG in 2010 and 2013, respectively.
On January 20, 2021, President Biden issued E.O. 13990, which re-established an IWG
and directed it to develop an update of the SC-CO2 estimates that reflect the best available
47 See IWG (2016b) for more discussion of the SC-CH4 and SC-N20 and the peer review and public comment
processes accompanying their development.
48 The EPA regulatory analyses under E.O. 13783 included sensitivity analyses based on global SC-GHG values and
using a lower discount rate of 2.5 percent. OMB Circular A-4 (OMB, 2003) recognizes that special
considerations arise when applying discount rates if intergenerational effects are important. In the IWG's 2015
Response to Comments, OMB—as a co-chair of the IWG—made clear that "Circular A-4 is a living document,"
that "the use of 7 percent is not considered appropriate for intergenerational discounting," and that "[t]here is
wide support for this view in the academic literature, and it is recognized in Circular A-4 itself." OMB, as part of
the IWG, similarly repeatedly confirmed that "a focus on global SCC estimates in [regulatory impact analyses] is
appropriate" (IWG 2015).
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science and the recommendations of the National Academies. In February 2021, the IWG
recommended the interim use of the most recent SC- CO2 estimates developed by the IWG prior
to the group being disbanded in 2017, adjusted for inflation (IWG, 2021). As discussed in the
February 2021 SC-GHG TSD, the IWG's selection of these interim estimates reflected the
immediate need to have SC-CO2 estimates available for agencies to use in regulatory benefit-cost
analyses and other applications that were developed using a transparent process, peer reviewed
methodologies, and the science available at the time of that process.
As noted above, the EPA participated in the IWG but has also independently evaluated
the interim SC-CO2 estimates published in the February 2021 SC-GHG TSD and determined
they are appropriate to use to estimate climate benefits for this action. The EPA and other
agencies intend to undertake a fuller update of the SC-CO2 estimates that takes into consideration
the advice of the National Academies (2017) and other recent scientific literature. The EPA has
also evaluated the supporting rationale of the February 2021 SC-GHG TSD, including the studies
and methodological issues discussed therein, and concludes that it agrees with the rationale for
these estimates presented in the SC-GHG TSD and summarized below.
In particular, the IWG found that the SC-CO2 estimates used under E.O. 13783 fail to
reflect the full impact of GHG emissions in multiple ways. First, the IWG concluded that those
estimates fail to capture many climate impacts that can affect the welfare of U.S. citizens and
residents. Examples of affected interests include direct effects on U.S. citizens and assets located
abroad, international trade, and tourism, and spillover pathways such as economic and political
destabilization and global migration that can lead to adverse impacts on U.S. national security,
public health, and humanitarian concerns. Those impacts are better captured within global
measures of the SC-GHGs.
In addition, assessing the benefits of U.S. GHG mitigation activities requires
consideration of how those actions may affect mitigation activities by other countries, as those
international mitigation actions will provide a benefit to U.S. citizens and residents by mitigating
climate impacts that affect U.S. citizens and residents. A wide range of scientific and economic
experts have emphasized the issue of reciprocity as support for considering global damages of
GHG emissions. Using a global estimate of damages in U.S. analyses of regulatory actions
allows the U.S. to continue to actively encourage other nations, including emerging major
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economies, to take significant steps to reduce emissions. The only way to achieve an efficient
allocation of resources for emissions reduction on a global basis—and so benefit the U.S. and its
citizens—is for all countries to base their policies on global estimates of damages.
As a member of the IWG involved in the development of the February 2021 SC-GHG
TSD, the EPA agrees with this assessment and, therefore, in this proposed rule the EPA centers
attention on a global measure of SC-CO2. This approach is the same as that taken in EPA
regulatory analyses over 2009 through 2016. A robust estimate of climate damages only to U.S.
citizens and residents that accounts for the myriad of ways that global climate change reduces the
net welfare of U.S. populations does not currently exist in the literature. As explained in the
February 2021 SC-GHG TSD, existing estimates are both incomplete and an underestimate of
total damages that accrue to the citizens and residents of the U.S. because they do not fully
capture the regional interactions and spillovers discussed above, nor do they include all of the
important physical, ecological, and economic impacts of climate change recognized in the
climate change literature, as discussed further below. The EPA, as a member of the IWG, will
continue to review developments in the literature, including more robust methodologies for
estimating the magnitude of the various damages to U.S. populations from climate impacts and
reciprocal international mitigation activities, and explore ways to better inform the public of the
full range of carbon impacts.
Second, the IWG concluded that the use of the social rate of return on capital (7 percent
under current OMB Circular A-4 guidance) to discount the future benefits of reducing GHG
emissions inappropriately underestimates the impacts of climate change for the purposes of
estimating the SC-CO2. Consistent with the findings of the National Academies (2017) and the
economic literature, the IWG continued to conclude that the consumption rate of interest is the
theoretically appropriate discount rate in an intergenerational context (IWG, 2016b) (IWG, 2010,
2013, 2016a) and recommended that discount rate uncertainty and relevant aspects of
intergenerational ethical considerations be accounted for in selecting future discount rates.49
49 GHG emissions are stock pollutants, where damages are associated with what has accumulated in the atmosphere
over time, and they are long lived such that subsequent damages resulting from emissions today occur over many
decades or centuries depending on the specific GHG under consideration. In calculating the SC-GHG, the stream
of future damages to agriculture, human health, and other market and non-market sectors from an additional unit
of emissions are estimated in terms of reduced consumption (or consumption equivalents). Then that stream of
future damages is discounted to its present value in the year when the additional unit of emissions was released.
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Furthermore, the damage estimates developed for use in the SC-GHG are estimated in
consumption-equivalent terms, and so an application of OMB Circular A-4's guidance for
regulatory analysis would then use the consumption discount rate to calculate the SC-GHG. The
EPA agrees with this assessment and will continue to follow developments in the literature
pertaining to this issue. The EPA also notes that while OMB Circular A-4, as published in 2003,
recommends using 3 percent and 7 percent discount rates as "default" values, Circular A-4 also
reminds agencies that "different regulations may call for different emphases in the analysis,
depending on the nature and complexity of the regulatory issues and the sensitivity of the benefit
and cost estimates to the key assumptions." On discounting, Circular A-4 recognizes that
"special ethical considerations arise when comparing benefits and costs across generations," and
Circular A-4 acknowledges that analyses may appropriately "discount future costs and
consumption benefits.. .at a lower rate than for intragenerational analysis." In the 2015 Response
to Comments on the Social Cost of Carbon for Regulatory Impact Analysis, OMB, EPA, and the
other IWG members recognized that "Circular A-4 is a living document" and "the use of 7
percent is not considered appropriate for intergenerational discounting. There is wide support for
this view in the academic literature, and it is recognized in Circular A-4 itself." Thus, the EPA
concludes that a 7 percent discount rate is not appropriate to apply to value the SC-GHGs in the
analysis presented in this RIA. In this analysis, to calculate the present and annualized values of
climate benefits, the EPA uses the same discount rate as the rate used to discount the value of
damages from future GHG emissions, for internal consistency. That approach to discounting
follows the same approach that the February 2021 SC-GHG TSD recommends "to ensure
internal consistency—i.e., future damages from climate change using the SC-GHG at 2.5 percent
should be discounted to the base year of the analysis using the same 2.5 percent rate." EPA has
also consulted the National Academies' 2017 recommendations on how SC-GHG estimates can
"be combined in RIAs with other cost and benefits estimates that may use different discount
rates." The National Academies reviewed "several options," including "presenting all discount
rate combinations of other costs and benefits with [SC-GHG] estimates."
While the IWG works to assess how best to incorporate the latest, peer reviewed science
to develop an updated set of SC-GHG estimates, it recommended the interim estimates to be the
Given the long time horizon over which the damages are expected to occur, the discount rate has a large
influence on the present value of future damages.
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most recent estimates developed by the IWG prior to the group being disbanded in 2017. The
estimates rely on the same models and harmonized inputs and are calculated using a range of
discount rates. As explained in the February 2021 SC-GHG TSD, the IWG has concluded that it
is appropriate for agencies to revert to the same set of four values drawn from the SC-GHG
distributions based on three discount rates as were used in regulatory analyses between 2010 and
2016 and subject to public comment. For each discount rate, the IWG combined the distributions
across models and socioeconomic emissions scenarios (applying equal weight to each) and then
selected a set of four values for use in agency analyses: an average value resulting from the
model runs for each of three discount rates (2.5 percent, 3 percent, and 5 percent), plus a fourth
value, selected as the 95th percentile of estimates based on a 3 percent discount rate. The fourth
value was included to provide information on potentially higher-than-expected economic impacts
from climate change, conditional on the 3 percent estimate of the discount rate. As explained in
the February 2021 SC-GHG TSD, this update reflects the immediate need to have an operational
SC-GHG that was developed using a transparent process, peer-reviewed methodologies, and the
science available at the time of that process. Those estimates were subject to public comment in
the context of dozens of proposed rulemakings as well as in a dedicated public comment period
in 2013.
Table 4-10 summarizes the interim global SC-CO2 estimates for the years 2027 to 2041.
These estimates are reported in 2021$ but are otherwise identical to those presented in the IWG's
2016 TSD (IWG 2016a). For purposes of capturing uncertainty around the SC-CO2 estimates in
analyses, the IWG's February 2021 TSD emphasizes the importance of considering all four of
the SC-CO2 values. The SC-CO2 increases over time within the models - i.e., the societal harm
from one metric ton emitted in 2041 is higher than the harm caused by one metric ton emitted in
2027 - because future emissions produce larger incremental damages as physical and economic
systems become more stressed in response to greater climatic change, and because GDP is
growing over time and many damage categories are modeled as proportional to GDP.
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Table 4-10: Interim Global Social Cost of Carbon Values, 2027-2041 (2021$/Metric Ton
CO2)
Discount Rate and Statistic
Year
5%
3%
2.50%
3%
Average
Average
Average
95th Percentile
2027
$19
$61
$90
$180
2028
$19
$62
$91
$190
2029
$20
$63
$92
$190
2030
$20
$65
$94
$200
2031
$21
$66
$95
$200
2032
$21
$67
$96
$200
2033
$22
$68
$98
$210
2034
$23
$69
$99
$210
2035
$23
$71
$100
$220
2036
$24
$72
$100
$220
2037
$25
$73
$100
$220
2038
$25
$74
$110
$230
2039
$26
$75
$110
$230
2040
$26
$77
$110
$240
2041
$27
$78
$110
$240
Note: These SC-CO2 values are identical to those reported in the 2016 TSD (IWG 2016a, cited in footnote 43 above)
adjusted for inflation to 2021$ using the annual GDP Implicit Price Deflator values in the U.S. Bureau of Economic
Analysis' (BEA) NIPA Table 1.1.9 found at https://fred.stlouisfed.org/release/tables?rid=53&eid=41158. The values
are stated in $/metric ton CO2 (1 metric ton equals 1.102 short tons) and vary depending on the year of CO2
emissions. This table displays the values rounded to the nearest dollar; the annual unrounded values used in the
calculations in this RIA are available on OMB's website: .
Source: https://www.whitehouse.gov/briefing-room/blog/2021/02/26/a-return-to-science-evidence-based-estimates-
of-the-benefits-of-reducing-climate-pollution/
There are a number of limitations and uncertainties associated with the SC-CO2 estimates
presented in Table 4-10. Some uncertainties are captured within the analysis, while other areas
of uncertainty have not yet been quantified in a way that can be modeled. Error! Reference
source not found. Figure 4-1 presents the quantified sources of uncertainty in the form of
frequency distributions for the SC-CO2 estimates for emissions in 2030. The distributions of SC-
CO2 estimates reflect uncertainty in key model parameters such as the equilibrium climate
sensitivity, as well as uncertainty in other parameters set by the original model developers. To
highlight the difference between the impact of the discount rate and other quantified sources of
uncertainty, the bars below the frequency distributions provide a symmetric representation of
quantified variability in the SC-CO2 estimates for each discount rate. As illustrated by the figure,
the assumed discount rate plays a critical role in the ultimate estimate of the SC-CO2. This is
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because CO2 emissions today continue to impact society far out into the future, so with a higher
discount rate, costs that accrue to future generations are weighted less, resulting in a lower
estimate. As discussed in the February 2021 TSD, there are other sources of uncertainty that
have not yet been quantified and are thus not reflected in these estimates.
o
o
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between the discount rate and uncertainty in economic growth over long time horizons.
Likewise, the socioeconomic and emissions scenarios used as inputs to the models do not reflect
new information from the last decade of scenario generation or the full range of projections.
The modeling limitations do not all work in the same direction in terms of their influence
on the SC-CO2 estimates. However, as discussed in the February 2021 TSD, the IWG has
recommended that, taken together, the limitations suggest that the interim SC-CO2 estimates
used in this final action likely underestimate the damages from CO2 emissions. EPA concurs that
the values used in this action conservatively underestimate the action's climate disbenefits. In
particular, the Intergovernmental Panel on Climate Change (IPCC) Fourth Assessment Report
(IPCC 2007), which was the most current IPCC assessment available at the time when the IWG
decision over the ECS input was made, concluded that SC-CO2 estimates "very
likely.. .underestimate the damage costs" due to omitted impacts. Since then, the peer-reviewed
literature has continued to support this conclusion, as noted in the IPCC's Fifth Assessment
report (IPCC 2014) and other recent scientific assessments (e.g., IPCC (2018, 2019a, 2019b));
U.S. Global Change Research Program (USGCRP, 2016, 2018); and the National Academies of
Sciences, Engineering, and Medicine (National Academies, 2017, 2019).
These assessments confirm and strengthen the science, updating projections of future
climate change and documenting and attributing ongoing changes. For example, sea level rise
projections from the IPCC's Fourth Assessment report ranged from 18 to 59 centimeters by the
2090s relative to 1980-1999, while excluding any dynamic changes in ice sheets due to the
limited understanding of those processes at the time (IPCC 2007). A decade later, the Fourth
National Climate Assessment projected a substantially larger sea level rise of 30 to 130
centimeters by the end of the century relative to 2000, while not ruling out even more extreme
outcomes (USGCRP 2018).
The February 2021 SC-GHG TSD briefly previews some of the recent advances in the
scientific and economic literature that the IWG is actively following and that could provide
guidance on, or methodologies for, addressing some of the limitations with the interim SC-GHG
estimates. The IWG is currently working on a comprehensive update of the SC-GHG estimates
taking into consideration recommendations from the National Academies of Sciences,
Engineering and Medicine, recent scientific literature, public comments received on the February
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2021 SC-GHG TSD and other input from experts and diverse stakeholder groups (National
Academies 2017). While that process continues, the EPA is continuously reviewing
developments in the scientific literature on the SC-GHG, including more robust methodologies
for estimating damages from emissions, and looking for opportunities to further improve SC-
GHG estimation going forward. Most recently, EPA has published an updated SC-GHG
methodology in the regulatory impact analysis of EPA's December 2023 final rulemaking for oil
and gas standards that reflects recent advances in the climate science and economics (U.S. EPA,
2023e). Specifically, the updated methodology incorporates new literature and research
consistent with the National Academies near-term recommendations on socioeconomic and
emissions inputs, climate modeling components, discounting approaches, and treatment of
uncertainty, and an enhanced representation of how physical impacts of climate change translate
to economic damages in the modeling framework based on the best and readily adaptable
damage functions available in the peer reviewed literature. The EPA solicited public comment on
these estimates and the accompanying draft technical report, which explains the methodology
underlying the new set of estimates, in the docket for the November 2022 supplemental proposed
Oil and Gas rule. The EPA also conducted an external peer review of the technical report. The
final technical report (U.S. EPA 2023f) and more information about the peer review and public
comments is available on EPA's website.50 As the updated SC-GHG values were still draft at the
time this analysis was conducted, EPA did not use them in the main analysis for this RIA to
monetize the estimated climate disbenefits of this final rule but they are noted below.
Table 4-11 through Table 4-14 show the monetized climate disbenefits from changes in
CO2 emissions expected to occur for the final action from 2027 to 2041 from Table 3-16. For
each year, EPA estimated the dollar value of the C02-related effects by applying the SC-CO2
estimates, shown in Table 4-10, to the estimated changes in CO2 emissions in the corresponding
year under the final action.51 EPA calculated the present value (PV) and equivalent annualized
50 See https://www.epa.gov/environmental-economics/scghg
51 CO2 emissions increases above the baseline as a result of the modeled policy are first expected in 2027, as control
technologies applied in response to the final rule first begin operation in that year, and those emissions increases
are expected to remain at that level afterwards, according to the cost analysis for this rule.
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value of disbenefits (EAV) from the perspective of 2024 by discounting each year-specific value
to the year 2024 using the same discount rate used to calculate the SC-CO2.52
52According to OMB's Circular A-4 (2003), an "analysis should focus on benefits and costs that accrue to citizens
and residents of the United States", and international effects should be reported separately. Circular A-4 also
reminds analysts that "[different regulations may call for different emphases in the analysis, depending on the
nature and complexity of the regulatory issues." To correctly assess the total climate damages to U.S. citizens and
residents, an analysis must account for impacts that occur within U.S. borders, climate impacts occurring outside
U.S. borders that directly and indirectly affect the welfare of U.S. citizens and residents, how U.S. GHG
mitigation activities affect mitigation activities by other countries, and spillover effects from climate action
elsewhere. The SC-GHG estimates used in regulatory analysis under revoked E.O. 13783 were an approximation
of the climate damages occurring within U.S. borders only (e.g., $8/mtC02 (2021$) in 2027 and foryear 2041
$10/mtCO2 in 2041 using a 3% discount rate for emissions occurring in 2025). Applying the same estimate (based
on a 3% discount rate) to the CO2 emission reduction expected under the final option in this final rule would yield
disbenefits from climate impacts within U.S borders of $0.2 to $0.3 million (2021$). However, as discussed at
length in the February 2021 TSD, estimates focusing on the climate impacts occurring solely within U.S. borders
are an underestimate of the benefits of CO2 mitigation accruing to U.S. citizens and residents, as well as being
subject to a considerable degree of uncertainty due to the manner in which they are derived. In particular, the
estimates developed under revoked E.O. 13783 did not capture significant regional interactions, spillovers, and
other effects and so are incomplete underestimates. The U. S. District Court for the Northern District of California
found that by omitting such impacts, those "interim domestic" estimates "fail[ed] to consider.. .important aspect[s]
of the problem" and departed from the "best science available" as reflected in the global estimates. California v.
Bernhardt, 472 F. Supp. 3d 573, 613-14 (N.D. Cal. 2020). EPA continues to center attention in this regulatory
analysis on the global measures of the SC-GHG as the appropriate estimates and as necessary for all countries to
use to achieve an efficient allocation of resources for emissions reduction on a global basis, and so benefit the
U.S. and its citizens.
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Table 4-11: Discounted Monetized Climate Disbenefits under the Final Amendments,
GACT 6B, 2027-2041 (millions 2021$)
Discounted back to 2024
Year
5%
3%
2.50%
3%
Average
Average
Average
95th Percentile
2027
$0.5
$1.8
$2.6
$5.3
2028
$0.5
$1.8
$2.6
$5.4
2029
$0.5
$1.8
$2.6
$5.5
2030
$0.4
$1.9
$2.7
$5.6
2031
$0.4
$1.9
$2.7
$5.7
2032
$0.4
$1.9
$2.8
$5.8
2033
$0.4
$2.0
$2.8
$5.9
2034
$0.4
$2.0
$2.8
$6.0
2035
$0.4
$2.0
$2.9
$6.1
2036
$0.4
$2.1
$2.9
$6.3
2037
$0.4
$2.1
$3.0
$6.4
2038
$0.4
$2.1
$3.0
$6.5
2039
$0.4
$2.2
$3.1
$6.6
2040
$0.4
$2.2
$3.1
$6.7
2041
$0.3
$2.3
$3.1
$6.8
PV
$6.1
$30
$43
$91
EAV
$0.6
$2.5
$3.5
$7.6
Note: Climate disbenefits are based on changes (reductions) in CO2 emissions and are calculated using four different estimates of
the social cost of carbon (SC-CO2) (model average at constant 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile
at 3 percent discount rate) presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide
Interim Estimates under Executive Order 13990 (IWG 2021). Using the updated SC-CO2 estimates that were presented in the
RIA for EPA's December 2023 final rulemaking on oil and natural gas sector sources (U.S. EPA 2023), the PV and EAV of
monetized climate disbenefits under the Final Amendments, GACT 6B, is estimated to be $90 million and $6 million (under the
2% near-term Ramsey discount rate), respectively.
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Table 4-12: Discounted Monetized Climate Disbenefits under the Final Amendments, NSPS
XX, 2027-2041 (millions 2021$)
Discounted back to 2024
Year
5%
3%
2.50%
3%
Average
Average
Average
95th Percentile
2027
$0.03
$0.12
$0.17
$0.35
2028
$0.04
$0.14
$0.21
$0.42
2029
$0.04
$0.17
$0.24
$0.50
2030
$0.05
$0.20
$0.28
$0.59
2031
$0.05
$0.22
$0.32
$0.68
2032
$0.06
$0.25
$0.36
$0.77
2033
$0.06
$0.29
$0.41
$0.86
2034
$0.06
$0.32
$0.45
$0.95
2035
$0.07
$0.35
$0.50
$1.05
2036
$0.07
$0.38
$0.54
$1.16
2037
$0.08
$0.42
$0.59
$1.26
2038
$0.08
$0.45
$0.64
$1.37
2039
$0.08
$0.49
$0.68
$1.48
2040
$0.08
$0.53
$0.73
$1.59
2041
$0.09
$0.57
$0.78
$1.71
PV
$0.94
$4.9
$6.9
$14.7
EAV
$0.09
$0.41
$0.56
$1.23
Note: Climate disbenefits are based on changes (reductions) in CO2 emissions and are calculated using four different estimates of
the social cost of carbon (SC-CO2) (model average at constant 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile
at 3 percent discount rate) presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide
Interim Estimates under Executive Order 13990 (IWG 2021). Using the updated SC-CO2 estimates that were presented in the
RIA for EPA's December 2023 final rulemaking on oil and natural gas sector sources (U.S. EPA 2023), the PV and EAV of
monetized climate disbenefits under the Final Amendments, NSPS XX, is estimated to be $14 million and $1 million (under the
2% near-term Ramsey discount rate), respectively.
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Table 4-13: Discounted Monetized Climate Disbenefits under the Final Amendments, NSPS
XX, MACT R, GACT 6B, 2027-2041 (millions, 2021$)
Discounted back to 2024
5%
3%
2.50%
3%
Year
Average
Average
Average
95th Percentile
2027
$0.5
$1.9
$2.7
$5.6
2028
$0.5
$1.9
$2.8
$5.8
2029
$0.5
$2.0
$2.9
$6.0
2030
$0.5
$2.1
$3.0
$6.2
2031
$0.5
$2.1
$3.0
$6.4
2032
$0.5
$2.2
$3.1
$6.6
2033
$0.5
$2.3
$3.2
$6.8
2034
$0.5
$2.3
$3.3
$7.0
2035
$0.5
$2.4
$3.4
$7.2
2036
$0.5
$2.5
$3.5
$7.4
2037
$0.5
$2.5
$3.6
$7.6
2038
$0.5
$2.6
$3.6
$7.9
2039
$0.4
$2.7
$3.7
$8.1
2040
$0.4
$2.7
$3.8
$8.3
2041
$0.4
$2.8
$3.9
$8.5
PV
$7.1
$35
$50
$105
EAV
$0.7
$2.9
$4.0
$8.8
Note: Climate disbenefits are based on changes (reductions) in CO2 emissions and are calculated using four different estimates of
the social cost of carbon (SC-CO2) (model average at constant 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile
at 3 percent discount rate) presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide
Interim Estimates under Executive Order 13990 (IWG 2021). Using the updated SC-CO2 estimates that were presented in the
RIA for EPA's December 2023 final rulemaking on oil and natural gas sector sources (U.S. EPA 2023), the PV and EAV of
monetized climate disbenefits under the Final Amendments (NSPS XX, MACT R, and GACT 6B) is estimated to be $ 100
million and $7 million (under the 2% near-term Ramsey discount rate), respectively.
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Table 4-14: Undiscounted Monetized Climate Disbenefits under Proposed Amendments,
NSPS XX, MACT R, GACT 6B, 2027-2041 (millions, 2021$)
Undiscounted
5%
3%
2.50%
3%
Year
Average
Average
Average
95th Percentile
2027
$0.6
$1.9
$2.8
$5.8
2028
$0.6
$2.0
$2.9
$6.0
2029
$0.6
$2.0
$3.0
$6.2
2030
$0.7
$2.1
$3.0
$6.3
2031
$0.7
$2.2
$3.1
$6.6
2032
$0.7
$2.2
$3.2
$6.8
2033
$0.7
$2.3
$3.3
$7.0
2034
$0.8
$2.4
$3.4
$7.2
2035
$0.8
$2.4
$3.5
$7.4
2036
$0.8
$2.5
$3.6
$7.6
2037
$0.9
$2.6
$3.6
$7.9
2038
$0.9
$2.6
$3.7
$8.1
2039
$0.9
$2.7
$3.8
$8.3
2040
$1.0
$2.8
$3.9
$8.6
2041
$1.0
$2.9
$4.0
$8.8
Note: Climate disbenefits are based on changes (reductions) in CO2 emissions and are calculated using four different estimates of
the social cost of carbon (SC-CO2) (model average at constant 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile
at 3 percent discount rate) presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide
Interim Estimates under Executive Order 13990 (IWG 2021).
The climate disbenefits associated with the additional CO2 emissions generated as a result
of the requirements of the final action are therefore $35 million in 2024 PV ($2.9 million EAV)
at a 3 percent discount rate, and range from $7.1 million PV ($0.7 million EAV) at a 5 percent
discount rate to $105 million PV ($8.8 million EAV) at a 3 percent discount rate (95th
percentile), all in 2021$.53 These disbenefits are estimated for 2027-2041, 15 years starting from
the first year of full implementation of both GACT 6B and NSPS XX (3 years after the effective
date) using the interim global social cost of carbon (SC-CO2) for 2027-2041 as shown in Table
4-10.54'' The climate disbenefits are less than 7 percent of the monetized long-term health
53 In order to calculate these values, it is necessary to convert tons (short) of emissions to metric tons. These values
may be converted to $/short ton using the conversion factor 0.90718474 metric tons per short ton for application
to the short ton CO2 emissions impacts provided in this action.
54 These SC-CO2 values are stated in $/metric ton CO2 and rounded to the nearest dollar. Such a conversion does not
change the underlying methodology, nor does it change the meaning of the SC-CO2 estimates. For both metric and
short tons denominated SC-CO2 estimates, the estimates vary depending on the year of CO2 emissions and are
defined in real terms, i.e., adjusted for inflation using the Gross Domestic Product (GDP) implicit price deflator.
4-37
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benefits lower bound estimate even at the 3 percent (95th percentile), the discount rate yielding
the highest climate disbenefit estimate. At a discount rate of 3 percent (model average), the
climate disbenefits are less than 3 percent of the monetized long-term health benefits. Thus, the
monetized climate disbenefits are relatively small when compared to the monetized health
benefits.
4.7 Total Monetized Benefits
Table 4-15 through Table 4-18 present a summary of monetized benefits for the final
amendments to GACT 6B and MACT R, and final NSPS XX both individually and
cumulatively. Net benefits in each table are calculated as health benefits minus climate
disbenefits. Benefits related to both short- and long-term exposure to ozone are estimated. Tables
presenting benefits list both estimates, with short-term benefits listed first. A complete discussion
of benefits relative to costs appears in Chapter 6.
4-38
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Table 4-15: Summary of Monetized Benefits PV/EAV for GACT 6B, 2027-2041, (million 2021$)
Final
Less Stringent Alternative
More Stringent Alternative
3%
PV
EAV
PV
EAV
PV
EAV
$200
$17
$58
$4.8
$250
$21
Health Benefits
and
and
and
and
and
and
$1,600
$140
$460
$39
$2,000
$170
Climate Disbenefits
$30
$2.5
$30
$2.5
$30
$2.5
$170
$15
$28
$2.3
$220
$19
Net Benefits
and
and
and
and
and
and
$1,600
$140
$430
$37
$2,000
$170
7%
$120
$13
$34
$3.7
$150
$16
Health Benefits
and
and
and
and
and
and
$980
$110
$280
$30
$1,200
$130
Climate Disbenefits (3%)
$30
$2.5
$30
$2.5
$30
$2.5
$90
$11
$4.0
$1.2
$120
$14
Net Benefits
and
and
and
and
and
and
$950
$110
$250
$28
$1,200
$130
Note: Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and
are presented at real discount rates of 3 and 7 percent s. The two benefits estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do
not represent lower- and upper-bound estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in
the table. These non-monetized benefits also include ozone climate impacts and benefits to ecosystem services associated with improvements in biomass loss and foliar injury. The
unmonetized effects also include disbenefits resulting from a secondary increase in NO2, SO2, and CO emissions. Climate disbenefits are based on changes (increases) in CO2
emissions and are calculated using four different estimates of the social cost of carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th
percentile at 3 percent discount rate) presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order
13990 (IWG 2021). For the presentational purposes of this table, we show the disbenefits associated with the average SC-C02at a 3 percent discount rate. Please see Section 4.6
for more discussion of the climate disbenefits. Rows may not appear to add correctly due to rounding.
4-39
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Table 4-16: Summary of Monetized Benefits PV/EAV for M AC ! R, 2027-2041, (million 2021$)
Final Less Stringent Alternative More Stringent Alternative
3%
PV
EAV
PV
EAV
PV
EAV
$11
$0.89
$2.3
$0.19
$13
$1.1
Health Benefits
and
and
and
and
and
and
$87
$7.3
$19
$1.6
$110
$9.0
Climate Disbenefits
$0
$0
$0
$0
$0
$0
$11
$0.89
$2.3
$0.19
$13
$1.1
Net Benefits
and
and
and
and
and
and
$87
$7.3
$19
$1.6
$110
$9.0
7%
$6.3
$0.70
$1.4
$0.15
$8.0
$0.87
Health Benefits
and
and
and
and
and
and
$52
$5.8
$11
$1.2
$6.5
$7.2
Climate Disbenefits (3%)
$0
$0
$0
$0
$0
$0
$6.3
$0.70
$1.4
$0.15
$8.0
$0.87
Net Benefits
and
and
and
and
and
and
$52
$5.8
$11
$1.2
$6.5
$7.2
Note: Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and
are presented at real discount rates of 3 and 7 percent. The two benefits estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do
not represent lower- and upper-bound estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in
the table. These non-monetized benefits also include ozone climate impacts and benefits to ecosystem services associated with improvements in biomass loss and foliar injury. The
unmonetized effects also include disbenefits resulting from a secondary increase in NO2, SO2, and CO emissions. Climate disbenefits are based on changes (increases) in CO2
emissions and are calculated using four different estimates of the social cost of carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th
percentile at 3 percent discount rate) presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order
13990 (IWG 2021). For the presentational purposes of this table, we show the disbenefits associated with the average SC-C02at a 3 percent discount rate. Please see Section 4.6
for more discussion of the climate disbenefits. Rows may not appear to add correctly due to rounding.
4-40
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Table 4-17: Summary of Monetized Benefits PV/EAV for NSPS XXa, 2027-2041, (million 2021$)
Final Less Stringent Alternative More Stringent Alternative
3%
PV
EAV
PV
EAV
PV
EAV
$34
$2.8
$2.8
$0.24
$34
$2.8
Health Benefits
and
and
and
and
and
and
$280
$24
$23
$2.0
$280
$24
Climate Disbenefits
$4.9
$0.41
$4.9
$0.41
$4.9
$0.41
$29
$2.4
($2.2)
($0.17)
$29
$2.4
Net Benefits
and
and
and
and
and
and
$280
$24
$18
$1.6
$280
$24
7%
$19
$2.1
$1.6
$0.17
$19
$2.1
Health Benefits
and
and
and
and
and
and
$160
$17
$13
$1.4
$160
$18
Climate Disbenefits (3%)
$4.9
$0.41
$4.9
$0.41
$4.9
$0.41
$14
$1.7
($3.3)
($0.24)
$14
$1.7
Net Benefits
and
and
and
and
and
and
$160
$17
$8.1
$0.99
$160
$18
Note: Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and
are presented at real discount rates of 3 and 7 percent. The two benefits estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do
not represent lower- and upper-bound estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in
the table. These non-monetized benefits also include ozone climate impacts and benefits to ecosystem services associated with improvements in biomass loss and foliar injury. The
unmonetized effects also include disbenefits resulting from a secondary increase in NO2, SO2, and CO emissions. Climate disbenefits are based on changes (increases) in CO2
emissions and are calculated using four different estimates of the social cost of carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th
percentile at 3 percent discount rate) presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order
13990 (IWG 2021). For the presentational purposes of this table, we show the disbenefits associated with the average SC-C02at a 3 percent discount rate. Please see Section 4.6
for more discussion of the climate disbenefits. Rows may not appear to add correctly due to rounding.
4-41
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Table 4-18: Summary of Monetized Benefits PV/EAV for All Rules, 2027-2041, (million 2021$)
Final Less Stringent Alternative More Stringent Alternative
3%
PV
EAV
PV
EAV
PV
EAV
$240
$20
$63
$5.3
$290
$25
Health Benefits
and
and
and
and
and
and
$2,000
$170
$500
$42
$2,400
$200
Climate Disbenefits
$35
$2.9
$35
$2.9
$35
$2.9
$210
$17
$28
$2.4
$260
$22
Net Benefits
and
and
and
and
and
and
$2,000
$170
$470
$39
$2,400
$200
7%
$140
$16
$37
$4.0
$180
$19
Health Benefits
and
and
and
and
and
and
$1,200
$130
$300
$33
$1,400
$160
Climate Disbenefits (3%)
$35
$2.9
$35
$2.9
$35
$2.9
$110
$13
$2.0
$1.1
$150
$16
Net Benefits
and
and
and
and
and
and
$1,200
$130
$270
$30
$1,400
$160
Note: Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and
are presented at real discount rates of 3 and 7 percent. The two benefits estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do
not represent lower- and upper-bound estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in
the table. These non-monetized benefits also include ozone climate impacts and benefits to ecosystem services associated with improvements in biomass loss and foliar injury. The
unmonetized effects also include disbenefits resulting from a secondary increase in NO2, SO2, and CO emissions. Climate disbenefits are based on changes (increases) in CO2
emissions and are calculated using four different estimates of the social cost of carbon (SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th
percentile at 3 percent discount rate) presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order
13990 (IWG 2021). For the presentational purposes of this table, we show the disbenefits associated with the average SC-C02at a 3 percent discount rate. Please see Section 4.6
for more discussion of the climate disbenefits. Rows may not appear to add correctly due to rounding.
4-42
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5 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS
5.1 Introduction
As discussed in the previous section, the emissions reductions projected under the action
are projected to produce up to $170 million per year of monetized VOC health benefits. At the
same time, the final amendments to GACT 6B are projected to result in environmental control
expenditures by the Gasoline Distribution sector to comply with the rule. The final amendments
to the NESHAP for Gasoline Distribution MACT R and the final NSPS for Bulk Gasoline
Terminals are significant under E.O. 12866 Section 3(f)(1).
While the national level impacts demonstrate the final action is likely to lead to
substantial benefits and costs, the benefit-cost analysis does not speak directly to all potential
economic and distributional impacts of the final rules, which may be important consequences of
the action. This section includes two sets of economic impact and distributional analyses for each
individual rule included in this final action directed toward complementing the benefit-cost
analysis. This includes a partial equilibrium analysis of market impacts and an analysis of
potentially affected small entities.
5.2 Economic Impact Analysis
To provide a measure of the market impacts of the final amendments to the NESHAPs
for Gasoline Distribution and final NSPS for Bulk Gasoline Terminals, EPA developed a single-
market, static partial equilibrium model of the market for gasoline in the United States. The
model does not consider imports or exports of gasoline. This should not materially affect the
analysis, as gasoline imports make up a very small portion of total consumption and gasoline
exports make up a relatively small portion of total production.55 The model also does not model
linkages between the gasoline market and other energy markets. The goal is to provide broad
insights into national-level market impacts and social costs of the final action. The analysis
allows for an estimate of how the final regulation will affect the price of gasoline and the
55 In 2019, imports of finished gasoline accounted for about 1% of U.S. gasoline consumption. See data from the
U.S. Energy Information Administration:
. The U.S. is a net exporter
of gasoline, with exports accounting for about 8% of U.S. production
(). Gasoline exports are seasonal
increasing during periods of lower U.S. demand (See:
).
5-1
-------
quantity of gasoline consumed and identifies how social costs of the final regulation are
distributed across consumers and firms. Using the model, it is straightforward to estimate the
economic impacts of the amendments to GACT 6B and MACT R and final NSPS XXa both
separately and cumulatively. This analytical approach is consistent with the Economic Impact
Analysis conducted for the 2008 area source NESHAP (U.S. EPA, 2008), which is the most
recent regulatory action taken by EPA to reduce HAP emissions from the gasoline distribution
sector.
5.2,1 Description of Approach/Model/Framework
5.2.1.1 Gasoline Market Model
EPA used a static, single-market partial equilibrium analysis of a national gasoline
market to estimate the economic impacts of the final NESHAP amendments and final NSPS
XXa. The analysis builds on the engineering costs analysis presented earlier and uses economic
theory related to consumer and producer behavior to estimate changes in market prices,
quantities, and economic welfare.
The model assumes perfect competition in the market for gasoline. This assumption was
made in the partial-equilibrium analysis conducted for the Economic Impact Analysis of the
2008 area source NESHAP; given little evidence of structural changes in gasoline distribution
since 2008, maintaining the assumption is reasonable. Supply and demand for gasoline are
isoelastic.56 The model is defined by the following set of equations:
Qst = Ast * (Pt ~ cktYs
(1)
Qot = ADt * PtD
(2)
Qst = Qot
(3)
where pt is price at time t, es and eD are the elasticity of supply and demand for gasoline,
Ast and ADt are supply and demand specific parameters, and ckt is a per-unit cost shifter at time
56This is a simplifying assumption and is justifiable given the small increases to engineering cost on a per-unit basis
for each final rule considered in this ERA.
5-2
-------
t for regulation k. Equations (1) and (2) define the supply and demand curves for gasoline, Qst
and Qot, respectively, and equation (3) defines equilibrium in the gasoline market.
The following steps are necessary to solve the model:
1. Specify values for the elasticity parameters es and eD.
2. Specify baseline values for prices and quantities for all t.
3. Calibrate Ast and ADt by inverting the supply and demand equations given parameter
values, given baseline prices and quantities, and assuming ckt = 0 in the baseline for all
4. Calculate ckt for the following policies: NSPS XXa, MACT R, GACT 6B, and "All,"
where All is the cumulative cost of NSPS XXa, MACT R, and GACT 6B.
5. Solve for equilibrium for each policy and analysis year.
Equilibrium is solved for numerically using the software program GAMS. There is no
relationship between solutions in different years. The model can be characterized as a set of
single-period partial equilibrium models.
5.2.1.2 Model Baseline
This RIA seeks to compare the state of the market with and without the changes to NSPS
XX, MACT R, and GACT 6B in effect. EPA selected the years 2027-2041 as the baseline for the
market analysis. These years were chosen for consistency with the engineering cost analysis
presented previously. The Annual Energy Outlook 2023, compiled by the Energy Information
Administration, projects gasoline prices and consumption through 2050, and provides the
baseline price and quantity data for the analysis. For an overview of the model, see Table 5-1.
Table 5-1: Description of Gasoline Market Model
k and t.
Geographic Scope
Product Groupings
Single gasoline market
Perfect competition
National
Firm/consumer behavior
Baseline gasoline price/quantity
See Table 5-2
Baseline years
Supply elasticity
Demand elasticity
0.29 (Coyle et al 2012)
-0.31 (Levin et al 2017)
2027-2041
5-3
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Table 5-2: AEO 2021 Baseline Gasoline Projections, 2027-2041
Year
Price
($2022/gallon)
Quantity
(billion gallons)
2027
2.85
129.98
2028
2.85
128.32
2029
2.86
126.44
2030
2.87
124.42
2031
2.86
122.51
2032
2.88
120.68
2033
2.89
119.20
2034
2.90
117.92
2035
2.90
116.66
2036
2.93
115.37
2037
2.93
114.29
2038
2.94
113.36
2039
2.95
112.52
2040
2.96
111.91
2041
2.96
111.41
Source: Energy Information Administration. Annual Energy Outlook 2023. Table 12. March 16,2023.
5.2.1.3 Model Parameters
Economic theory suggests consumers will bear a higher share of economic welfare losses
if the supply of gasoline is more responsive to changes than is the demand for gasoline.
Numerous peer-reviewed studies generally agree that over short periods of time demand for
gasoline is price inelastic. A recent study by Levin et al. (2017) estimates short-run gasoline
demand elasticity to be between -0.27 and -0.35. EPA chose the midpoint of this range, -0.31, as
the primary choice for this market analysis. A meta-analysis by Labandeira, Labeaga, and Lopez -
Otero (2017) estimates a short-run gasoline elasticity of demand of -0.293 (significant at the 1
percent level), which is within the range from Levin et al. (and near the mid-point of that range
chosen for this analysis). This is in line with other recent estimates by Coglianese et al. (2016)
of -0.37 and Bento at al. (2009) of -0.35. A demand elasticity of -0.31 suggests that a 10 percent
increase in the price of gasoline will lead to an approximately 3.1 percent reduction in the
quantity of gasoline demanded.
There is relatively less empirical work on the elasticity of gasoline supply. For this
analysis, EPA chose the short-run estimate of 0.29 from Coyle, DeBacker, and Prisinzano
(2012). This is close to the value of 0.24 used in the Economic Impact Analysis for the 2008
Gasoline Distribution Area Source NESHAP, which came from an estimate of supply elasticity
5-4
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for refined petroleum products (Considine, 2002). It is also consistent with applied work on the
incidence of gasoline taxes (Chouinard & Perloff, 2004), which suggests that the national
demand elasticity for gasoline and national supply elasticity for gasoline should be roughly
equal.
5.2,2 Economic Impact Results
5.2.2.1 Market-Level Results
Market-level impacts in the gasoline market caused by the final regulations are projected
to be small, with the bulk of the impacts caused by the final amendments to GACT 6B. All rules
cumulatively are projected to increase the price of gasoline ($2021/gallon) by less than two
hundredths of a cent/gallon in each year from 2027-2041 (less than .006 percent), with about 70
percent of the increase coming from changes to GACT 6B. Further, the quantity of gasoline
consumed is projected to fall by less than .002 percent in each year from 2027-2041 when the
impacts of all rules are included. The maximum fall in quantity is 1.6 million gallons in 2040,
against a baseline projection of 112 billion gallons57. Given that a barrel of crude oil produces
about 20 gallons of gasoline58, this projection implies a reduction in crude oil demand of up to
80,000 barrels in 2040. EIA projects crude oil consumption of approximately 6.3 billion barrel -
of-oil equivalent (BOE) in 204059, so 80,000 barrels represents less than .002 percent of total
demand for crude oil.
When considering the impacts of the less and more stringent alternative options, the
results are qualitatively similar, but slightly smaller in the former case and slightly greater in the
latter case. For tables of market impacts by year for each package of regulatory alternatives, see
Chapter 8 (Appendix A).
5.2.2.2 Welfare Change Estimates
Table 5-3, Table 5-4, and Table 5-5 below present the projected welfare impacts of each
rule in present value (PV) and equivalent annual value (EAV), using both a 3 percent and 7
57 As production adjusts to the new equilibrium, there could be changes to the emissions reductions expected under
the proposed amendments. Any such effects are likely to be small.
58 Energy Information Administration.
. Accessed 1/24/2022.
59 Energy Information Administration. Annual Energy Outlook 2023. Table 1: Total Energy Supply, Disposition,
and Price Summary. Reference Case.
5-5
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percent social discount rate, for the final options and the less/more stringent package of
alternatives. The bulk of the welfare impacts are caused by the final amendments to GACT 6B,
which is expected given the large proportion of the compliance cost for this overall action that is
attributable to this rule, and for each rule the projected costs are substantially offset by cost
savings from product recovery.
Table 5-3: Welfare Impacts of Final Options, 2027-2041 (Discounted to 2024, million
2021$)
3% 7%
KllIC
PV
EAV
PV
EAV
Change In Consumer Surplus60
-$18
-$1.5
-$13
-$1.4
MACTR
Change In Producer Surplus61
-$19
-$1.6
-$14
-$1.5
Change In Welfare with Credits62
-$22
-$1.8
-$15
-$1.7
Change in Welfare Without Credits63
-$38
-$3.2
-$27
-$2.9
Change In Consumer Surplus
-$110
-$9.3
-$79
-$8.7
GACT 6B
Change In Producer Surplus
-$120
-$10
-$84
-$9.2
Change In Welfare with Credits
$65
$5.4
$46
$5.0
Change in Welfare Without Credits
-$230
-$19
-$160
-$18
Change In Consumer Surplus
-$25
-$2.1
-$17
-$1.8
NSPS XXa
Change In Producer Surplus
-$27
-$2.2
-$18
-$2.0
Change In Welfare with Credits
-$1.7
-$0.1
-$1.1
-$0.1
Change in Welfare Without Credits
-$52
-$4.4
-$34
-$3.8
Change In Consumer Surplus
-$150
-$13
-$110
-$12
Change In Producer Surplus
-$170
-$14
-$120
-$13
All
Change In Welfare with Credits
$41
$3.5
$29
$3.2
Change in Welfare Without Credits
-$320
-$27
-$220
-$25
60 Changes in consumer surplus are estimated from changes in prices and quantities using the following linear
approximation formula: ACS = -(AP * Qnew) + -5 * AP * AQ.
61 Changes in producer surplus are estimated from changes in prices and quantities using the following linear
approximation formula: APS = (AP - ck) * Qnew - .5 * AP * AQ.
62 Changes in welfare with product recovery credits included is calculated by adding total product recovery credits to
ACS + APS.
63 Changes in welfare without product recovery credits included is calculated as ACS + APS.
5-6
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Table 5-4: Welfare Impacts of Less Stringent Alternative Options, 2027-2041 (Discounted
to 2024, million 2021$)
3% 7%
Kiue
PV
EAV
PV
EAV
Change In Consumer Surplus
-$13
-$1.1
-$9.4
-$1.0
MACTR
Change In Producer Surplus
Change In Welfare with Credits
-$13
-$14
-$1.6
-$1.8
-$10
-$17
-$1.1
-$1.9
Change in Welfare Without Credits
-$24
-$3.2
-$19
-$2.1
Change In Consumer Surplus
-$39
-$3.2
-$27
-$3.0
GACT 6B
Change In Producer Surplus
-$41
-$3.5
-$29
-$3.2
Change In Welfare with Credits
-$0.2
$0.0
-$0.2
$0.0
Change in Welfare Without Credits
-$80
-$6.7
-$57
-$6.2
Change In Consumer Surplus
-$3.1
-$0.3
-$2.1
-$0.2
NSPS XXa
Change In Producer Surplus
Change In Welfare with Credits
-$3.3
-$2.3
-$0.3
-$0.2
-$2.2
-$1.5
-$0.2
-$0.2
Change in Welfare Without Credits
-$6.5
-$0.5
-$4.3
-$0.5
Change In Consumer Surplus
-$55
-$4.6
-$39
-$4.3
All
Change In Producer Surplus
-$59
-$14
-$42
-$13
Change In Welfare with Credits
-$27
$3.5
-$19
$3.2
Change in Welfare Without Credits
-$110
-$27
-$80
-$25
Table 5-5: Welfare Impacts of More Stringent Alternative Options, 2027-2041 (Discounted
to 2024, million 2021$)
3% 7%
KllIC
PV
EAV
PV
EAV
Change In Consumer Surplus
-$57
-$4.8
-$40
-$4.4
MACTR
Change In Producer Surplus
Change In Welfare with Credits
-$61
-$98
-$5.1
-$8.2
-$43
-$70
-$4.8
-$7.6
Change in Welfare Without Credits
-$118
-$10
-$84
-$9.2
Change In Consumer Surplus
-$363
-$30
-$257
-$28
GACT 6B
Change In Producer Surplus
-$388
-$33
-$274
-$30
Change In Welfare with Credits
-$395
-$33
-$279
-$31
Change in Welfare Without Credits
-$751
-$63
-$531
-$58
Change In Consumer Surplus
-$25
-$2.1
-$17
-$1.9
NSPS XXa
Change In Producer Surplus
-$27
-$2.3
-$18
-$2.0
Change In Welfare with Credits
-$2.2
-$0.2
-$1.4
-$0.2
Change in Welfare Without Credits
-$53
-$4.4
-$35
-$3.8
Change In Consumer Surplus
-$446
-$37
-$314
-$34
All
Change In Producer Surplus
-$477
-$40
-$336
-$37
Change In Welfare with Credits
-$496
-$42
-$350
-$38
Change in Welfare Without Credits
-$923
-$77
-$650
-$71
5-7
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The national compliance cost estimates are often used to approximate the social cost of
the rule. However, in cases where the engineering costs of compliance are used to estimate social
cost, the burden of the regulation is typically measured as falling solely on the affected
producers, who experience a profit loss exactly equal to these cost estimates. Thus, the entire loss
is a change in producer surplus with no change (by assumption) in consumer surplus because no
changes in price and consumption are estimated. This is typically referred to as a "full-cost
absorption" scenario in which all factors of production are assumed to be fixed and firms are
unable to adjust their output levels when faced with additional costs.
In contrast, this market analysis builds on the engineering cost analysis and incorporates
economic theory related to producer and consumer behavior to estimate changes in market
conditions. Gasoline producers can make supply adjustments that will generally affect the market
environment in which they operate. As producers change levels of gasoline supply in response to
a regulation, consumers are typically faced with changes in prices that cause them to alter the
quantity they are willing to purchase. These changes in price and output from the market model
are used to estimate the total surplus losses/gains for two types of stakeholders: gasoline
consumers and producers.
5.2.2.3 Limitations
Ultimately, the regulatory program will increase the costs of supplying gasoline to
consumers, and the model is designed to evaluate behavioral responses to this change in costs
within a market equilibrium setting. However, the results should be viewed with the following
three limitations in mind. First, the national competitive market assumption is clearly very strong
because the gasoline markets in this analysis are regional. Regional price and quantity impacts
could be different from the average impacts reported below if local market structures, production
costs, or demand conditions are substantially different from those used in this analysis. Second,
the model uses a market supply function and analyzes supply behavior at or near a single market
baseline equilibrium using a supply elasticity parameter. Therefore, it does not address facility-
level impacts such as closures or changes in employment. Although developing a facility-level
model could potentially provide these outputs, this type of model requires substantial amounts of
detailed data for individual facilities and a level of effort beyond the scope of this analysis.
Finally, we do not evaluate supply-side welfare losses by segments of the gasoline supply chain.
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EPA relied on the cost-to-sales ratio analysis to make inferences about the relative impacts
across producers within this chain (see Section 5.3 below).
5.3 Small Business Impacts Analysis
The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a
regulatory flexibility analysis of any rule subject to notice and comment rulemaking
requirements under the Administrative Procedure Act or any other statute unless the agency
certifies that the rule will not have a significant economic impact on a substantial number of
small entities. Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts of this action on small entities, a small entity is
defined as: (1) a small business as defined by the Small Business Administration's (SBA)
regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a population of less than 50,000; and (3)
a small organization that is any not-for-profit enterprise that is independently owned and
operated and is not dominant in its field. Businesses in the Gasoline Distribution source category
predominately have NAICS codes 424710 (Petroleum Bulk Stations and Terminals) and 486910
(Pipeline Transportation of Refined Petroleum Products). For the SBA small business size
standard definition for each NAICS classification, see below in Table 5-6.
Table 5-6: SBA Size Standards by NAICS Code
NAICS
Codes
NAICS Industry Description
Size Standards
(in no. of employees)
424710
Petroleum Bulk Stations and Terminals
225
486910
Pipeline Transportation of Refined Petroleum
Products
1,500
Sources: U.S. Small Business Administration, Table of Standards, Effective March 17, 2023.
https://www.sba.gov/document/support--table-size-standards. Accessed March 28, 2023.
This analysis contains two sections: an analysis of potential impacts on small businesses
using a facility list constructed by EPA (Facility List, discussed in Section 2.2.3), and a
supplementary analysis using data collected by the US Census Bureau. Using the Facility List,
EPA conducted a cost-to-sales analysis to estimate the potential impacts of the final action. The
EPA prefers a "sales test" as the impact methodology in small entity analyses for rulemakings as
opposed to a "profits test", in which annualized compliance costs are calculated as a share of
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profits64. This is consistent with guidance published by the U.S. Small Business Administration
(SBA) Office of Advocacy, which suggests that cost as a percentage of total revenues is a metric
for evaluating cost impacts on small entities relative to large entities.65 This is because revenues
or sales data are commonly available for entities impacted by EPA regulations and profits data
are often private or misrepresent true profits earned by firms after undertaking accounting and
tax considerations. Due to data limitations, the analysis in this section does not take into account
that the smallest bulk plants will be exempt from the vapor balancing requirement due to not
reaching a minimum throughput threshold of 4,000 gallons per day. This exemption should cover
most or all bulk plants which could otherwise experience significant impacts from the final
amendments.
While a "sales test" can provide some insight as to the economic impact of an action such
as this one, it assumes that the impacts of a rule are solely incident on a directly affected firm
(therefore, no impact to consumers of the affected product), or solely incident on consumers of
output directly affected by this action (therefore, no impact to companies that are producers of
the affected product). Thus, an analysis such as this one is best viewed as providing insight on
the polar examples of economic impacts: maximum impact to either directly affected companies
or their consumers. A "sales test" analysis does not consider shifts in supply and demand curves
to reflect intermediate economic outcomes. For a partial equilibrium analysis of the economic
impacts of this action that attempts to parse impacts on consumers relative to producers, see
Section 5.2.
5,3,1 Small Business National Overview
EPA constructed a facility list for the Gasoline Distribution source category. For
information on how this list was constructed, see Section 2.2.3. For the initial list of 1,838
facilities, EPA identified the ultimate parent company along with revenue and employment
information for 1,705 of these facilities using D&B Hoover's database. This included 118 major
source facilities owned by 40 ultimate parent companies, 1,587 area source facilities owned by
64 More information on sales and profit tests as used in analyses done by U.S. EPA can be found in the Final
Guidance for EPA Rulewriters: Regulatory Flexibility Act as Amended by the Small Business Regulatory
Enforcement Fairness Act, November 2006, pp. 32-33.
65 U.S. SBA, Office of Advocacy. 2010. A Guide for Government Agencies, How to Comply with the Regulatory
Flexibility Act, Implementing the President's Small Business Agenda and Executive Order 13272.
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262 ultimate parent companies, and 11 facilities known to be subject to NSPS XX owned by 8
ultimate parent companies. In total, EPA identified 268 ultimate parent companies as owners of
the 1,705 facilities, of which 117 were identified as small entities (counts of parent companies do
not sum over rules due to some companies owning facilities subject to multiple rules). Summary
statistics for these ultimate parent companies are in Table 5-7 below.
Table 5-7: Summary Statistics of Potentially Affected Entities
Rule
Size
No. of Ultimate Parent
Companies
Number of
Facilities
Mean Revenue
(million 2021$)
Median Revenue
(million 2021$)
Small
2
2
$12
$12
MACTR
Not Small
38
116
$43,000
$7,700
Small
116
181
$100
$26
GACT 6B
Not Small
146
1,406
$24,000
$2,300
Small
0
0
N/A
N/A
NSPS XX
Not Small
8
11
$72,000
$19,000
All
Small
Not Small
117
151
183
1,522
$100
$24,000
$25
$2,300
Source: EPA Gasoline Distribution Facility List and D&B Hoover's Database.
Only two small ultimate parent companies own a facility subject to MACT R or NSPS
XX. Based on this, it is unlikely that the final amendments to MACT R or the final NSPS XXa
could have a significant impact on a substantial number of small entities. However, while a large
majority of area-source facilities (89 percent) are owned by ultimate parent companies not
classified as small by the SB A, a substantial number of the ultimate parent companies that own
area source gasoline distribution facilities are small entities (116 or 44 percent).
5,3.2 Small Entity Economic Impacts
5.3.2.1 Main Screening Analysis
Using the facility list discussed in the above section, EPA conducted cost-to-sales
analysis for the final action to screen small entities for potentially significant impacts. While
EPA could identify (at least in certain cases) when a facility was a pipeline breakout station or
pumping station, we could not determine for bulk distribution facilities which facilities were bulk
plants and which were bulk terminals. Because of this, EPA constructed "worst-case" total
annualized costs for each rule and facility. This consisted of constructing a total annualized cost
for each model plant and selecting the maximum for two categories of facility: "Plant or
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Terminal," and "Breakout or Pumping Station." For a discussion of the model plants and the
engineering cost analysis performed for this action, see Chapter 3. The worst-case costs for each
rule and facility type are in Table 5-8 below.
Table 5-8: Worst-Case Costs by Model Plant
Rule
Facility Type
Total Annualized Cost without
Product Recovery
($2021)
Total Annualized Cost with
Product Recovery ($2021)
GACT 6B
MACTR
NSPS XXa
Bulk Plant or Terminal
Pipeline Breakout or Pumping Station
Bulk Terminal
Pipeline Breakout Station
Bulk Terminal
$22,000
$2,200
$20,000
$5,100
$130,000
$7,500
$180
$10,000
-$3,700
$43,000
The analysis proceeds as follows:
1. Assign worst-case total annualized cost to each facility based on rule and facility type.
2. Calculate total worst-case costs for each ultimate parent company by summing over a
rules and facilities.
3. Calculate a cost-to-sales ratio (CSR) for each ultimate parent company.
The results of this analysis for the final options are presented below. Table 5-9 shows the
distribution of costs for ultimate parent companies by rule. Table 5-10 and Table 5-11 below
show the distribution of CSRs by rule and the percentage of CSRs clearing 1 percent and 3
percent for each rule.
Table 5-9: Distribution of Estimated Per-Facility Compliance Costs by Rule and Size for
Final Options (2021$)
n . c. . . Average Cost with Average Cost without
Kuie oize JNo. oi -rinns •« . •« .
Product Recovery Product Recovery
Small 2 $10,000 $20,000
MACTR
Not Small 38 $9,400 $19,000
Small 116 $7,500 $22,000
GACT 6B
Not Small 146 $7,500 $22,000
Small 0 N/A N/A
NSPS XXa
Not Small 8 $43,000 $130,000
5-12
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Small 117 $7,700 $23,000
All
Not Small 151 $7,900 $23,000
Table 5-10: Compliance Cost-to-Sales Ratio Distributions for Small Entities, Final Options
Rule
With Product Recovery Without Product
Included Recovery Included
Mean CSR
Maximum Mean Maximum
CSR
CSR
CSR
MACTR
0.12%
0.18% 0.23% 0.35%
GACT 6B
NSPS XXa
No. of Small Entities
116
0
0.13%
2.23% 0.39%
6.56%
All
No. of Small Entities 117
0.14%
2.23% 0.40% 6.56%
Table 5-11: Compliance Cost-to-Sales Ratio Thresholds for Small Entities - Final Options
With Product Recovery Included
Rule
Without Product Recovery
Included
No. of Small
Entities
% of Small
Entities
No. of Small
Entities
% of Small
Entities
No. of Small Entities
2
100.0%
2
100.0%
MACTR
Greater than 1%
0
0.0%
0
0.0%
Greater than 3%
0
0.0%
0
0.0%
No. of Small Entities
116
100.0%
116
100.0%
GACT 6B
Greater than 1%
4
3.4%
10
8.6%
Greater than 3%
0
0.0%
3
2.6%
No. of Small Entities
0
-
0
-
NSPS XXa
Greater than 1%
-
-
-
-
Greater than 3%
-
-
-
-
All
No. of Small Entities
Greater than 1%
Greater than 3%
117
4
0
100.0%
3.4%
0.0%
117
10
3
100.0%
8.5%
2.6%
Given the very low average CSR for small entities (both with and without product
recovery) and the low proportion of small entities with a CSR above 3 percent, it is unlikely that
5-13
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the final changes to MACT R and GACT 6B or final NSPS XXa would have a significant impact
on a substantial number of small entities. Also, given the low (and in the case of MACT R,
negative) worst-case costs associated with pipeline facilities, it is clear that the final action would
not have a significant impact on a substantial number of small entities owning pipeline facilities
(although there are no such facilities on the list compiled by EPA). Further, these CSRs are
conservative and are likely to overstate the impact of the action on small entities.
The above analysis has one main limitation: EPA's facility list does not provide complete
coverage of the Gasoline Distribution source category. Given this circumstance, it is possible
that the facility list is skewed towards larger entities (which may be easier to identify) in the
source category, in which case the above analysis could understate the impacts of the action on
small entities. This could be a particular problem in the case of bulk gasoline plants covered by
GACT 6B. This is less likely to be the case since the worst-case costs used above overstate costs
for bulk plants. Also, this analysis does not take into account that the smallest bulk plants will be
exempt from the vapor balancing requirement due to not reaching a minimum throughput
threshold of 4,000 gallons per day. This exemption should cover most or all bulk plants which
could otherwise experience significant impacts from the final amendments. Assuming a
throughput of 4,000 gallons per day, 200 operating days per year, and an average rack price of
$2.15 (the 2021 average) would generate $1,720,000 in revenue for the smallest bulk plants
required to install loading controls. This is more revenue than all small entities with a CSR
greater than 3 percent, all but 4 small entities with a CSR greater than 1 percent, and would lead
to a maximum worst-case CSR of 2.96 percent. Still, considering this possibility, we supplement
the analysis below using Census data.
5.3.2.2 Supplementary Screening Analysis
The facility list compiled by EPA suggests that most of the small entities affected by the
final action are area sources. Further, given the facility list's gaps in coverage, it is possible the
list is skewed towards larger facilities. In this section, we investigate further the possibility that
the final amendments to GACT 6B could have a significant impact on small entities.
Table 5-12 below shows the number of firms and average sales for firms in various
employment groups tracked by the U.S. Census Bureau. The table shows all employment groups
for which a firm could be classified as a small entity under SBA size standards. Note that this is a
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conservatively high count of small entities in each group, since a firm may be owned by a larger
ultimate parent company with employment above the SB A threshold. There are 2,197 potential
small entities with NAICS classification 424710 based on this data.
This information is augmented by calculations of the cost necessary to hit a 1 percent or 3
percent CSR for a firm in each employment group with average sales, and the worst-case CSR
for a firm in the group with average sales under the final changes to GACT 6B. In the smallest
employment group (<5 employees), the worst-case cost without product recovery included is less
than half of that required to hit the 1 percent CSR threshold under the final changes, and less
than one-sixth of that required to cross the 3 percent CSR threshold. The average worst-case
CSR without product recovery in the smallest employment group is 0.41 percent and is one-
fourth of that or less in each larger employment group. Further, recall that the cost estimates used
to construct the worst-case CSRs are likely to overstate the costs of the final requirements for
small entities. This evidence also suggests that the final changes to GACT 6B will not have a
substantial impact on a significant number of small entities.
In addition, we note that this action does not contain an unfunded mandate of $100
million or more as described in the Unfunded Mandates Reform Act, 2 U.S.C. 1531-1538, and
does not significantly or uniquely affect small governments. The action imposes no enforceable
duty on any state, local or Tribal governments or the private sector.
5-15
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Table 5-12: NAICS 424710 -
Small Entity Impacts
Average Sales
(2021$)
GACT 6B Worst-
GACT 6B Worst-Case
Size
Firms
1% CSR Threshold
3% CSR Threshold
Case CSR with
CSR without Product
Product Recovery
Recovery
<5 employees
508
$5,400,000
$54,000
$160,000
0.14%
0.41%
5-9 employees
415
$23,000,000
$230,000
$690,000
0.03%
0.10%
10-14 employees
267
$31,000,000
$310,000
$920,000
0.02%
0.07%
15-19 employees
144
$37,000,000
$370,000
$1,100,000
0.02%
0.06%
20-24 employees
121
$52,000,000
$520,000
$1,600,000
0.01%
0.04%
25-29 employees
83
$37,000,000
$370,000
$1,100,000
0.02%
0.06%
30-34 employees
65
$59,000,000
$590,000
$1,800,000
0.01%
0.04%
35-39 employees
60
$74,000,000
$740,000
$2,200,000
0.01%
0.03%
40-49 employees
92
$56,000,000
$560,000
$1,700,000
0.01%
0.04%
50-74 employees
115
$250,000,000
$2,500,000
$7,500,000
0.00%
0.01%
75-99 employees
76
$380,000,000
$3,800,000
$11,000,000
0.00%
0.01%
100-149 employees
83
$110,000,000
$1,100,000
$3,400,000
0.01%
0.02%
150-199 employees
57
$260,000,000
$2,600,000
$7,700,000
0.00%
0.01%
200-299 employees
69
$140,000,000
$1,400,000
$4,200,000
0.01%
0.02%
300-399 employees
27
$440,000,000
$4,400,000
$13,000,000
0.00%
0.01%
400-499 employees
15
$590,000,000
$5,900,000
$18,000,000
0.00%
0.00%
Source: U.S. Census Bureau. County Business Patterns 2017 and Economic Census 2017.
5-16
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5.4 Employment Impact Analysis
This section presents a qualitative overview of the various ways that environmental
regulation can affect employment. Employment impacts of environmental regulations are
generally composed of a mix of potential declines and gains in different areas of the economy
over time. Regulatory employment impacts can vary across occupations, regions, and industries;
by labor and product demand and supply elasticities; and in response to other labor market
conditions. Isolating such impacts is a challenge, as they are difficult to disentangle from
employment impacts caused by a wide variety of ongoing, concurrent economic changes. The
EPA continues to explore the relevant theoretical and empirical literature and to seek public
comments in order to ensure that the way the EPA characterizes the employment effects of its
regulations is reasonable and informative.
Environmental regulation "typically affects the distribution of employment among
industries rather than the general employment level" (Arrow, et al., 1996). Even if impacts are
small after long-run market adjustments to full employment, many regulatory actions have
transitional effects in the short run (Office of Management and Budget, 2015). These movements
of workers in and out of jobs in response to environmental regulation are potentially important
and of interest to policymakers. Transitional job losses have consequences for workers that
operate in declining industries or occupations, have limited capacity to migrate, or reside in
communities or regions with high unemployment rates.
As indicated by the market analysis presented in Section 5.2, and the potential impacts on
firms owning Gasoline Distribution facilities in Section 5.3, the final requirements are likely to
cause only small shifts in gasoline consumption and prices. As a result, demand for labor
employed in gasoline distribution activities and associated industries, which we estimate is
approximately 66,000 employees based on 2017 Economic Census data as mentioned in Chapter
2, is unlikely to see large changes but might experience adjustments as there may be increases in
compliance-related labor requirements such as labor associated with the manufacture,
installation, and operation of pollution control equipment such as new or upgraded carbon
adsorbers and thermal combustors (e.g. oxidizers), and monitors. In addition, there may be
changes in employment due to effects on output from directly regulated sectors and sectors that
consume gasoline. If gasoline price increases sufficiently as a result of this action, then revenues
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of firms directly regulated and those in gasoline-consuming sectors may fall and their
employment may potentially decline (though such changes should likely be small in light of the
estimated change in output price mentioned above). For this final action, however, we do not
have the data and analysis available to quantify potential labor impacts although as explained, we
expect those impacts to be relatively small.66
66 The employment analysis in this RIA is part of EPA's ongoing effort to "conduct continuing evaluations of
potential loss or shifts of employment which may result from the administration or enforcement of [the Act]"
pursuant to CAA section 321(a).
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6 COMPARISON OF BENEFITS AND COSTS
In this chapter, we present a comparison of the benefits and costs of this final action. As
explained in the previous chapters, all costs and benefits outlined in this RIA are estimated as the
change from the baseline, which reflects the requirements already promulgated. As stated earlier
in this RIA, there is no monetized estimate of the benefits for the HAP emission reductions
expected to occur as a result of this final action. We do present monetized estimates for other
impacts of this action, such as benefits from reduced exposure to ozone caused by VOC
emissions reductions and disbenefits from increases in CO2 emissions.
6.1 Results
As part of fulfilling analytical guidance with respect to E.O. 12866, EPA presents
estimates of the present value (PV) of the benefits and costs over the period 2027 to 2041. To
calculate the present value of the social net benefits of the final action, annual benefits and costs
are in 2021 dollars and are discounted to 2024 at 3 percent and 7 percent discount rates as
directed by the current version of OMB's Circular A-4. The EPA also presents the equivalent
annualized value (EAV), which represents a flow of constant annual values that 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, consistent with the estimate of the PV, in contrast to year-specific estimates.
Tables 6-1 through 6-4 presents a summary of the monetized benefits, compliance costs,
and net benefits (including climate disbenefits) of each rule, and cumulatively, and the more and
less stringent alternatives for in terms of present value (PV) and equivalent annualized value
(EAV). Benefits related to both short- and long-term exposure to ozone are estimated. Tables
presenting benefits list both figures, with short-term benefits listed first. These tables do not
include non-monetized benefits/disbenefits of each rule. These benefits/disbenefits include health
and climate disbenefits of secondary emissions increases in SO2, NO2, and CO, environmental
and ecosystem impacts (which can include reduced growth and/or biomass production in
sensitive trees, reduced yield and quality of crops, visible foliar injury, changed to species
composition, and other changes in ecosystems and associated ecosystem services) associated
with HAP and VOC emissions reductions, ozone climate impacts, and VOC health benefits
occurring outside of the ozone season. While these impacts are not monetized, EPA expects they
6-1
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have value. For estimates of HAP emission reductions for each regulatory option, see Section
3.4. For a description of the specific HAP emitted by this source category and potential health
impacts, see Section 4.2.
6-2
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Table 6-1: Summary of Monetized Benefits, Compliance Costs, and Net Benefits PV/EAV for GACT 6B, 2027-2041 (million
2021$, discounted to 2024)
Less Stringent Alternative More Stringent Alternative
3%
PV
EAV
PV
EAV
PV
EAV
$200
$17
$58
$4.8
$250
$21
Health Benefits
and
and
and
and
and
and
$1,600
$140
$460
$39
$2,000
$170
Climate Disbenefits(3%)
$30
$2.5
$30
$2.5
$30
$2.5
Net Compliance Costs
-$70
-$6.0
$0.0
$0.0
$390
$33
Compliance Costs
$230
$19
$80
$6.7
$750
$63
Value of Product Recovery
$300
$25
$80
$6.7
$360
$30
$240
$21
$28
$2.3
-$170
-$15
Net Benefits
and
and
and
and
and
and
$1,600
$140
$430
$37
$1,600
$130
7%
$120
$13
$34
$3.7
$150
$16
Health Benefits
and
and
and
and
and
and
$980
$110
$280
$30
$1,200
$130
Climate Disbenefits (3%)
$30
$2.5
$30
$2.5
$30
$2.5
Net Compliance Costs
-$50
-$5.0
$0.0
$0.0
$280
$30
Compliance Costs
$160
$18
$57
$6.2
$530
$58
Value of Product Recovery
$210
$23
$57
$6.2
$250
$28
$140
$16
$4.0
$1.2
-$160
-$17
Net Benefits
and
and
and
and
and
and
$1,000
$110
$250
$28
$890
$98
Note: Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and are presented at real
discount rates of 3 and 7 percent. The two benefits estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound
estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table. The unmonetized effects also include disbenefits
resulting from a secondary increase in N02, S02, and CO emissions. Benefits (incorporating disbenefits) include those related to public health and climate. The health benefits are associated with several
point estimates and are presented at real discount rates of 3 and 7 percent. Climate disbenefits are based on changes (increases) in C02 emissions and are calculated using four different estimates of the
social cost of carbon (SC-C02) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate) presented in the Technical Support Document: Social
Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990 (IWG 2021). For the presentational purposes of this table, we show the disbenefits associated with the
average SC-C02 at a 3 percent discount rate. Please see Section 4.6 for more discussion of the climate disbenefits. Net compliance costs are the compliance costs minus the value of product recovery
from compliance with the rule. Hence, net compliance costs are negative if the value of product recovery exceeds the compliance costs. Rows may not appear to add correctly due to rounding.
6-3
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Table 6-2: Summary of Monetized Benefits, Compliance Costs, and Net Benefits PV/EAV for MACT R, 2027-2041 (million
2021$, discounted to 2024)
Less Stringent Alternative More Stringent Alternative
3%
PV
EAV
PV
EAV
PV
EAV
$11
$0.89
$2.3
$0.19
$13
$1.1
Health Benefits
and
and
and
and
and
and
$87
$7.3
$19
$1.6
$110
$9.0
Climate Disbenefits(3%)
$0
$0
$0
$0
$0
$0
Net Compliance Costs
$22
$1.9
$25
$2.0
$100
$8.2
Compliance Costs
$38
$3.2
$28
$2.3
$120
$10
Value of Product Recovery
$16
$1.3
$3.4
$0.3
$20
$1.7
-$11
-$1.0
-$23
-$1.8
-$87
-$7.1
Net Benefits
and
and
and
and
and
and
$65
$5.4
-$6.0
-$0.40
$100
-$0.8
7%
$6.3
$0.70
$1.4
$0.15
$8.0
$0.87
Health Benefits
and
and
and
and
and
and
$52
$5.8
$11
$1.2
$65
$7.2
Climate Disbenefits (3%)
$0
$0
$0
$0
$0
$0
Net Compliance Costs
$16
$1.6
$17
$1.8
$70
$7.6
Compliance Costs
$27
$2.9
$19
$2.1
$84
$9.2
Value of Product Recovery
$11
$1.3
$2.4
$0.3
$14
$1.6
-$9.7
-$0.91
-$16
-$1.7
-$62
-$6.7
Net Benefits
and
and
and
and
and
and
$36
$4.2
$6.0
$0.60
$5.0
-$0.4
Note: Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and are presented at real
discount rates of 3 and 7 percent s. The two benefits estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound
estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table. The unmonetized effects also include disbenefits
resulting from a secondary increase in N02, S02, and CO emissions. Benefits (incorporating disbenefits) include those related to public health and climate. The health benefits are associated with several
point estimates and are presented at real discount rates of 3 and 7 percent. Climate disbenefits are based on changes (increases) in C02 emissions and are calculated using four different estimates of the
social cost of carbon (SC-C02) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate) presented in the Technical Support Document: Social
Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990 (IWG 2021). For the presentational purposes of this table, we show the disbenefits associated with the
average SC-C02at a 3 percent discount rate. Please see Section 4.6 for more discussion of the climate disbenefits. Net compliance costs are the compliance costs minus the value of product recovery
from compliance with the rule. Hence, net compliance costs are negative if the value of product recovery exceeds the compliance costs. Rows may not appear to add correctly due to rounding.
6-4
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Table 6-3: Summary of Monetized Benefits, Compliance Costs, and Net Benefits PV/EAV for NSPS XXa, 2027-2041 (million
2021$, discounted to 2024)
Less Stringent Alternative More Stringent Alternative
3%
PV
EAV
PV
EAV
PV
EAV
$34
$2.8
$2.8
$0.24
$34
$2.8
Health Benefits
and
and
and
and
and
and
$280
$24
$23
$2.0
$280
$24
Climate Disbenefits(3%)
$4.9
$0.41
$4.9
$0.41
$4.89
$0.41
Net Compliance Costs
$2.0
$0.20
$2.3
$0.19
$2.0
$0.2
Compliance Costs
$52
$4.4
$6.5
$0.54
$53
$4.4
Value of Product Recovery
$50
$4.2
$4.2
$0.35
$51
$4.2
$27
$2.2
-$4.4
-$0.36
$27
$2.2
Net Benefits
and
and
and
and
and
and
$270
$23
$16
$1.4
$230
23
7%
$19
$2.1
$1.6
$0.17
$19
$2.1
Health Benefits
and
and
and
and
and
and
$160
$17
$13
$1.4
$160
$18
Climate Disbenefits (3%)
$4.9
$0.4
$4.9
$0.41
$4.9
$0.41
Net Compliance Costs
$1.0
$0.1
$1.5
$0.17
$1.0
$0.10
Compliance Costs
$34
$3.8
$4.3
$0.47
$35
$3.8
Value of Product Recovery
$33
$3.7
$2.8
$0.30
$34
$3.7
$13
$1.6
-$5.0
-$0.41
$13
$1.6
Net Benefits
and
and
and
and
and
and
$150
$16
$6.6
$0.82
$150
$17
Note: Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and are presented at real
discount rates of 3 and 7 percent. The two benefits estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound
estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table. The unmonetized effects also include disbenefits
resulting from a secondary increase in N02, S02, and CO emissions. Benefits (incorporating disbenefits) include those related to public health and climate. The health benefits are associated with several
point estimates and are presented at real discount rates of 3 and 7 percent. Climate disbenefits are based on changes (increases) in C02 emissions and are calculated using four different estimates of the
social cost of carbon (SC-C02) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate) presented in the Technical Support Document: Social
Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990 (IWG 2021). For the presentational purposes of this table, we show the disbenefits associated with the
average SC-C02at a 3 percent discount rate, Please see Section 4.6 for more discussion of the climate disbenefits. Net compliance costs are the compliance costs minus the value of product recovery
from compliance with the rule. Hence, net compliance costs are negative if the value of product recovery exceeds the compliance costs. Rows may not appear to add correctly due to rounding.
6-5
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Table 6-4: Summary of Monetized Benefits, Compliance Costs, and Net Benefits PV/EAV for All Rules, 2027-2041 (million
2021$, discounted to 2024)
Less Stringent Alternative More Stringent Alternative
3%
PV
EAV
PV
EAV
PV
EAV
$240
$20
$63
$5.3
$290
$25
Health Benefits
and
and
and
and
and
and
$2,000
$170
$500
$42
$2,400
$200
Climate Disbenefits (3%)
$35
$2.9
$35
$2.9
$35
$2.9
Net Compliance Costs
-$46
-$3.9
$27
$2.2
$490
$41
Compliance Costs
$320
$27
$120
$9.5
$920
$77
Value of Product Recovery
$370
$31
$88
$7.3
$430
$36
$250
$21
$1.1
-$0.22
-$240
-$19
Net Benefits
and
and
and
and
and
and
$2,000
$170
$440
$37
$1,900
$160
7%
$140
$16
$37
$4.0
$180
$19
Health Benefits
and
and
and
and
and
and
$1,200
$130
$300
$33
$1,400
$160
Climate Disbenefits (3%)
$35
$2.9
$35
$2.9
$35
$2.9
Net Compliance Costs
-$33
-$3.3
$18
$2.0
$350
$38
Compliance Costs
$220
$25
$80
$9
$650
$71
Value of Product Recovery
$250
$28
$62
$7
$300
$33
$140
$16
-$16
-$0.9
-$210
-$22
Net Benefits
and
and
and
and
and
and
$1,200
$130
$250
$28
$1,000
$120
Note: Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and are presented at real
discount rates of 3 and 7 percent. The two benefits estimates are separated by the word "and" to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound
estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table. The unmonetized effects also include disbenefits
resulting from a secondary increase in N02, S02, and CO emissions. Benefits (incorporating disbenefits) include those related to public health and climate. The health benefits are associated with several
point estimates and are presented at real discount rates of 3 and 7 percent. Climate disbenefits are based on changes (increases) in C02 emissions and are calculated using four different estimates of the
social cost of carbon (SC-C02) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate) presented in the Technical Support Document: Social
Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990 (IWG 2021). For the presentational purposes of this table, we show the disbenefits associated with the
average SC-C02at a 3 percent discount rate. Please see Section 4.6 for more discussion of the climate disbenefits. Net compliance costs are the compliance costs minus the value of product recovery
from compliance with the rule. Hence, net compliance costs are negative if the value of product recovery exceeds the compliance costs. Rows may not appear to add correctly due to rounding.
6-6
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Given these results, the EPA expects that implementation of the GACT 6B, based solely
on an economic efficiency criterion, will provide society with a relatively substantial net gain in
welfare, notwithstanding the expansive set of health and environmental benefits and other
impacts we were unable to quantify such as monetization of benefits from VOC emission
reductions occurring outside of the ozone season (the months of October-April). The same holds
true for NSPS XXa and for all final amendments considered cumulatively. For the final
amendments to MACT R, net benefits are negative when considering only short-term benefits
but become positive when long-term benefits of reduced exposure to ozone are taken into
account. Further quantification of directly emitted VOC and HAP would increase the estimated
net benefits of the final action.
6.2 Uncertainties and Limitations
Throughout the RIA, we considered a number of sources of uncertainty, both
quantitatively and qualitatively, regarding the benefits, and costs of the final amendments. We
summarize the key elements of our discussions of uncertainty here:
Projection methods and assumptions: Overtime, more facilities are newly established
or modified in each year, and to the extent the facilities remain in operation in future years, the
total number of facilities subject to the action could change. Facility closure, if it occurs, affects
the number of facilities subject to GACT 6B and MACT R. We assume 100 percent compliance
with these final rules and existing rules, starting from when the source becomes affected. If
sources do not comply with these rules, at all or as written, the cost impacts and emission
reductions may be overestimated. Additionally, new control technology may become available in
the future at lower cost, and we are unable to predict exactly how industry will comply with the
rules in the future.
In addition, the counts of units projected to be affected by this final action are held
constant. Given our analytical timeframe of 2027-2041, it is possible that the affected unit
counts may change. One factor that may impact these counts, and the impacts of these rules
overall, is a potential increase in electric vehicle use that could serve as a substitute for gasoline
vehicles. AEO 2023 projections indicate a continued increase in battery electric and electric-
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hybrid vehicle use up to 2041.67 The expected consumption of gasoline as projected for this RIA
may be senstitive to such vehicle projections.
Finally, the requirements for EFR tanks under MACT R and GACT 6B require fitting
controls, which will require degassing of the storage vessel. These controls must be installed at
the first degassing of the storage vessel after three years from the promulgation date of the final
action, but in case more than 10 years from the promulgation date of the final action. Facilities
will have 3 years to identify storage vessels that need to be upgraded and identify appropriate
fitting control systems that need to be installed. Facilities are allowed up to 10 years in order to
align the installation of the controls with a planned degassing event, to the extent practicable, to
minimize the offsetting emissions that occur due to a degassing event solely to install the fitting
controls. To the extent that that not all storage vessels have fitting controls installed in the first
10 years of the analysis period, cost and emissions impacts will be overestimated during that
span.
• Years of analysis: The years of the cost analysis are 2027, to represent the first-year
facilities are fully compliant with MACT R and GACT 6B, through 2041, to
represent impacts of the action over the life of installed capital equipment, as
discussed in Chapter 3. Extending the analysis beyond 2041 would introduce
substantial and increasing uncertainties in projected impacts of the final regulations.
• Compliance Costs: There may be an opportunity cost associated with the installation
of environmental controls (for purposes of mitigating the emission of pollutants) that
is not reflected in the compliance costs included in Chapter 3. If environmental
investment displaces investment in productive capital, the difference between the rate
of return on the marginal investment (which is discretionary in nature) displaced by
the mandatory environmental investment is a measure of the opportunity cost of the
environmental requirement to the regulated entity. To the extent that any opportunity
costs are not included in the control costs, the compliance costs presented above for
this final action may be underestimated.
67 U.S. Energy Information Administration. Annual Energy Outlook 2023 Narrative. March 2023, p. 5. Available
at https://www.eia.gov/outlooks/aeo/pdf/AEO2023_Narrative.pdf.
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BPT estimates: All national-average BPT estimates reflect the geographic distribution of
the modeled emissions, which may not exactly match the emission reductions that would occur
due to the action, and they may not reflect local variability in population density, meteorology,
exposure, baseline health incidence rates, or other local factors for any specific location.
Recently, the EPA systematically compared the changes in benefits, and concentrations where
available, from its BPT technique and other reduced-form techniques to the changes in benefits
and concentrations derived from full-form photochemical model representation of a few different
specific emissions scenarios. Reduced form tools are less complex than the full air quality
modeling, requiring less agency resources and time. That work, in which we also explore other
reduced form models is referred to as the "Reduced Form Tool Evaluation Project" (Project),
began in 2017, and the initial results were available at the end of 2018. The Agency's goal was to
better understand the suitability of alternative reduced-form air quality modeling techniques for
estimating the health impacts of criteria pollutant emissions changes in the EPA's benefit-cost
analysis. The EPA continues to work to develop refined reduced-form approaches for estimating
benefits. The scenario-specific emission inputs developed for this project are currently available
online. The study design and methodology are described in the final report summarizing the
results of the project, available at .
Non-monetized benefits and disbenefits: Numerous categories of health and welfare
benefits are not quantified and monetized in this RIA. These benefits/disbenefits include health
and climate disbenefits of secondary emissions increases in SO2, NO2, and CO, environmental
and ecosystem impacts (which can include reduced growth and/or biomass production in
sensitive trees, reduced yield and quality of crops, visible foliar injury, changed to species
composition, and other changes in ecosystems and associated ecosystem services) associated
with HAP and VOC emissions reductions, ozone climate impacts, and VOC health benefits
occuring outside of the ozone season. While these impacts are not monetized, EPA expects they
have value. These unquantified benefits, including benefits from reductions in emissions of
pollutants such as HAP which are to be reduced by this final action, are described in detail in
Chapter 4 of this RIA and various NAAQS RIAs.
VOC health impacts: In this RIA, we quantify an array of adverse health impacts
6-9
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attributable to emissions of VOC. The Integrated Science Assessment for Particulate Matter
(" ISA") (U.S. EPA, 2019) identifies the human health effects associated with ambient particles,
which include premature death and a variety of illnesses associated with acute and chronic
exposures.
Monetized climate disbenefits: The EPA considered the uncertainty associated with the
interim global social cost of carbon (SC-CO2) estimates, which were used to calculate the
climate disbenefits from the increase in CO2 emissions projected under the final amendments to
NSPS XX and GACT 6B. Some uncertainties are captured within the analysis, while other areas
of uncertainty have not yet been quantified in a way that can be modeled. A full list and
discussion of uncertainties in the analysis of monetized climate disbenefits can be found in
Section 4.6 of this RIA.
6-10
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7-14
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8 APPENDIX A: DETAILED MARKET IMPACT TABLES
8.1 Final Options
8.1.1 Price Impacts
Table 8-1: Projected Change in Price, Final Options (2021 cents/gallon of gasoline)
Year
NSPS XXa
MACTR
GACT 6B
All
2027
0.0008
0.0012
0.0076
0.0096
2028
0.0009
0.0013
0.0077
0.0099
2029
0.0011
0.0013
0.0078
0.0100
2030
0.0013
0.0013
0.0080
0.0110
2031
0.0014
0.0013
0.0081
0.0110
2032
0.0016
0.0013
0.0082
0.0110
2033
0.0018
0.0014
0.0083
0.0110
2034
0.0020
0.0014
0.0084
0.0120
2035
0.0022
0.0014
0.0085
0.0120
2036
0.0024
0.0014
0.0086
0.0120
2037
0.0026
0.0014
0.0087
0.0130
2038
0.0027
0.0014
0.0087
0.0130
2039
0.0029
0.0014
0.0088
0.0130
2040
0.0031
0.0014
0.0089
0.0130
2041
0.0033
0.0015
0.0089
0.0140
Table 8-2: Projected Percentage Change in Price, Final Options
Year
NSPS XXa
MACTR
GACT 6B
All
2027
0.0003%
0.0004%
0.0027%
0.0034%
2028
0.0003%
0.0004%
0.0027%
0.0035%
2029
0.0004%
0.0004%
0.0027%
0.0036%
2030
0.0004%
0.0005%
0.0028%
0.0037%
2031
0.0005%
0.0005%
0.0028%
0.0038%
2032
0.0006%
0.0005%
0.0029%
0.0039%
2033
0.0006%
0.0005%
0.0029%
0.0040%
2034
0.0007%
0.0005%
0.0029%
0.0041%
2035
0.0007%
0.0005%
0.0029%
0.0042%
2036
0.0008%
0.0005%
0.0029%
0.0042%
2037
0.0009%
0.0005%
0.0030%
0.0043%
2038
0.0009%
0.0005%
0.0030%
0.0044%
2039
0.0010%
0.0005%
0.0030%
0.0045%
2040
0.0011%
0.0005%
0.0030%
0.0045%
2041
0.0011%
0.0005%
0.0030%
0.0046%
8-1
-------
8,1,2 Quantity Impacts
Table 8-3: Projected Change in Quantity, Final Options (gallons of gasoline)
Year
NSPS XXa
MACTR
GACT 6B
All
2027
-110,000
-180,000
-1,100,000
-1,400,000
2028
-130,000
-180,000
-1,100,000
-1,400,000
2029
-150,000
-180,000
-1,100,000
-1,400,000
2030
-170,000
-170,000
-1,100,000
-1,400,000
2031
-190,000
-180,000
-1,100,000
-1,400,000
2032
-210,000
-170,000
-1,100,000
-1,500,000
2033
-230,000
-170,000
-1,100,000
-1,500,000
2034
-250,000
-170,000
-1,100,000
-1,500,000
2035
-270,000
-170,000
-1,100,000
-1,500,000
2036
-290,000
-170,000
-1,000,000
-1,500,000
2037
-310,000
-170,000
-1,000,000
-1,500,000
2038
-330,000
-170,000
-1,000,000
-1,500,000
2039
-350,000
-170,000
-1,000,000
-1,600,000
2040
-370,000
-170,000
-1,000,000
-1,600,000
2041
-390,000
-170,000
-1,000,000
-1,600,000
Table 8-4: Percentage Change in
Quantity, Final Options
Year
NSPS XXa
MACTR
GACT 6B
All
2027
-0.0001%
-0.0001%
-0.0008%
-0.0010%
2028
-0.0001%
-0.0001%
-0.0008%
-0.0011%
2029
-0.0001%
-0.0001%
-0.0008%
-0.0011%
2030
-0.0001%
-0.0001%
-0.0009%
-0.0011%
2031
-0.0002%
-0.0001%
-0.0009%
-0.0012%
2032
-0.0002%
-0.0001%
-0.0009%
-0.0012%
2033
-0.0002%
-0.0001%
-0.0009%
-0.0012%
2034
-0.0002%
-0.0001%
-0.0009%
-0.0013%
2035
-0.0002%
-0.0001%
-0.0009%
-0.0013%
2036
-0.0003%
-0.0001%
-0.0009%
-0.0013%
2037
-0.0003%
-0.0001%
-0.0009%
-0.0013%
2038
-0.0003%
-0.0002%
-0.0009%
-0.0014%
2039
-0.0003%
-0.0002%
-0.0009%
-0.0014%
2040
-0.0003%
-0.0002%
-0.0009%
-0.0014%
2041
-0.0003%
-0.0002%
-0.0009%
-0.0014%
8-2
-------
8.2 Less Stringent Alternative Options
8,2,1 Price Impacts
Table 8-5: Projected Change in Price, Less Stringent Alternative Options (2021
cents/gallon of gasoline)
Year
NSPS XXa
MACTR
GACT 6B
All
2027
0.0001
0.0009
0.0027
0.0037
2028
0.0001
0.0009
0.0027
0.0037
2029
0.0001
0.0009
0.0027
0.0038
2030
0.0002
0.0010
0.0028
0.0039
2031
0.0002
0.0010
0.0028
0.0040
2032
0.0002
0.0010
0.0029
0.0040
2033
0.0002
0.0010
0.0029
0.0041
2034
0.0003
0.0010
0.0029
0.0042
2035
0.0003
0.0010
0.0030
0.0042
2036
0.0003
0.0010
0.0030
0.0043
2037
0.0003
0.0010
0.0030
0.0044
2038
0.0003
0.0010
0.0030
0.0044
2039
0.0004
0.0011
0.0031
0.0045
2040
0.0004
0.0011
0.0031
0.0045
2041
0.0004
0.0011
0.0031
0.0046
Table 8-6: Projected Percentage Change in Price, Less Stringent Alternative Options
Year
NSPS XXa
MACTR
GACT 6B
All
2027
0.0000%
0.0003%
0.0009%
0.0013%
2028
0.0000%
0.0003%
0.0009%
0.0013%
2029
0.0000%
0.0003%
0.0010%
0.0013%
2030
0.0001%
0.0003%
0.0010%
0.0014%
2031
0.0001%
0.0003%
0.0010%
0.0014%
2032
0.0001%
0.0003%
0.0010%
0.0014%
2033
0.0001%
0.0003%
0.0010%
0.0014%
2034
0.0001%
0.0003%
0.0010%
0.0014%
2035
0.0001%
0.0004%
0.0010%
0.0015%
2036
0.0001%
0.0004%
0.0010%
0.0015%
2037
0.0001%
0.0004%
0.0010%
0.0015%
2038
0.0001%
0.0004%
0.0010%
0.0015%
2039
0.0001%
0.0004%
0.0010%
0.0015%
2040
0.0001%
0.0004%
0.0010%
0.0015%
2041
0.0001%
0.0004%
0.0010%
0.0015%
8-3
-------
8,2,2 Quantity Impacts
Table 8-7: Projected Change in Quantity, Less Stringent Alternative Options (gallons of
gasoline)
Year
NSPS XXa
MACTR
GACT 6B
All
2027
-13,000
-130,000
-370,000
-520,000
2028
-16,000
-130,000
-370,000
-520,000
2029
-18,000
-130,000
-370,000
-520,000
2030
-21,000
-130,000
-370,000
-520,000
2031
-24,000
-130,000
-370,000
-530,000
2032
-26,000
-130,000
-370,000
-530,000
2033
-29,000
-130,000
-370,000
-530,000
2034
-31,000
-130,000
-370,000
-530,000
2035
-34,000
-130,000
-370,000
-530,000
2036
-36,000
-130,000
-360,000
-530,000
2037
-38,000
-130,000
-360,000
-530,000
2038
-41,000
-120,000
-360,000
-530,000
2039
-43,000
-120,000
-360,000
-530,000
2040
-46,000
-120,000
-360,000
-530,000
2041
-48,000
-120,000
-360,000
-530,000
Table 8-8: Percentage Change in
Quantity, Less Stringent Alternative Options
Year
NSPS XXa
MACTR
GACT 6B
All
2027
0.0000%
-0.0001%
-0.0003%
-0.0004%
2028
0.0000%
-0.0001%
-0.0003%
-0.0004%
2029
0.0000%
-0.0001%
-0.0003%
-0.0004%
2030
0.0000%
-0.0001%
-0.0003%
-0.0004%
2031
0.0000%
-0.0001%
-0.0003%
-0.0004%
2032
0.0000%
-0.0001%
-0.0003%
-0.0004%
2033
0.0000%
-0.0001%
-0.0003%
-0.0004%
2034
0.0000%
-0.0001%
-0.0003%
-0.0004%
2035
0.0000%
-0.0001%
-0.0003%
-0.0005%
2036
0.0000%
-0.0001%
-0.0003%
-0.0005%
2037
0.0000%
-0.0001%
-0.0003%
-0.0005%
2038
0.0000%
-0.0001%
-0.0003%
-0.0005%
2039
0.0000%
-0.0001%
-0.0003%
-0.0005%
2040
0.0000%
-0.0001%
-0.0003%
-0.0005%
2041
0.0000%
-0.0001%
-0.0003%
-0.0005%
8-4
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8.3 More Stringent Alternative Options
8.3,1 Price Impacts
Table 8-9: Projected Change in Price, More Stringent Alternative Options (2021
cents/gallon of gasoline)
Year
NSPS XXa
MACTR
GACT 6B
All
2027
0.0008
0.0039
0.0250
0.0300
2028
0.0009
0.0040
0.0250
0.0300
2029
0.0011
0.0040
0.0260
0.0310
2030
0.0013
0.0041
0.0260
0.0310
2031
0.0015
0.0042
0.0260
0.0320
2032
0.0016
0.0042
0.0270
0.0330
2033
0.0018
0.0043
0.0270
0.0330
2034
0.0020
0.0043
0.0270
0.0340
2035
0.0022
0.0044
0.0280
0.0340
2036
0.0024
0.0044
0.0280
0.0350
2037
0.0026
0.0045
0.0280
0.0350
2038
0.0028
0.0045
0.0280
0.0360
2039
0.0030
0.0045
0.0290
0.0360
2040
0.0032
0.0045
0.0290
0.0370
2041
0.0034
0.0046
0.0290
0.0370
Table 8-10: Projected Percentage Change in Price, More Stringent Alternative Options
Year
NSPS XXa
MACTR
GACT 6B
All
2027
0.0003%
0.0014%
0.0087%
0.0103%
2028
0.0003%
0.0014%
0.0088%
0.0105%
2029
0.0004%
0.0014%
0.0089%
0.0107%
2030
0.0004%
0.0014%
0.0091%
0.0109%
2031
0.0005%
0.0015%
0.0092%
0.0112%
2032
0.0006%
0.0015%
0.0093%
0.0113%
2033
0.0006%
0.0015%
0.0094%
0.0115%
2034
0.0007%
0.0015%
0.0095%
0.0117%
2035
0.0008%
0.0015%
0.0095%
0.0118%
2036
0.0008%
0.0015%
0.0096%
0.0119%
2037
0.0009%
0.0015%
0.0096%
0.0120%
2038
0.0009%
0.0015%
0.0097%
0.0122%
2039
0.0010%
0.0015%
0.0097%
0.0123%
2040
0.0011%
0.0015%
0.0098%
0.0124%
2041
0.0011%
0.0015%
0.0098%
0.0125%
8-5
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8,3,2 Quantity Impacts
Table 8-11: Projected Change in Quantity, More Stringent Alternative Options (gallons of
gasoline)
Year
NSPS XXa
MACTR
GACT 6B
All
2027
-110,000
-550,000
-3,500,000
-4,200,000
2028
-130,000
-550,000
-3,500,000
-4,200,000
2029
-150,000
-550,000
-3,500,000
-4,200,000
2030
-170,000
-550,000
-3,500,000
-4,200,000
2031
-190,000
-550,000
-3,500,000
-4,200,000
2032
-210,000
-550,000
-3,500,000
-4,200,000
2033
-230,000
-550,000
-3,500,000
-4,300,000
2034
-250,000
-550,000
-3,500,000
-4,300,000
2035
-270,000
-540,000
-3,500,000
-4,300,000
2036
-290,000
-540,000
-3,400,000
-4,200,000
2037
-310,000
-540,000
-3,400,000
-4,300,000
2038
-330,000
-540,000
-3,400,000
-4,300,000
2039
-350,000
-530,000
-3,400,000
-4,300,000
2040
-370,000
-530,000
-3,400,000
-4,300,000
2041
-390,000
-530,000
-3,400,000
-4,300,000
Table 8-12: Percentage Change in
Quantity, More Stringent Alternative Options
Year
NSPS XXa
MACTR
GACT 6B
All
2027
-0.0001%
-0.0004%
-0.0027%
-0.0032%
2028
-0.0001%
-0.0004%
-0.0027%
-0.0033%
2029
-0.0001%
-0.0004%
-0.0028%
-0.0033%
2030
-0.0001%
-0.0004%
-0.0028%
-0.0034%
2031
-0.0002%
-0.0004%
-0.0029%
-0.0035%
2032
-0.0002%
-0.0005%
-0.0029%
-0.0035%
2033
-0.0002%
-0.0005%
-0.0029%
-0.0036%
2034
-0.0002%
-0.0005%
-0.0029%
-0.0036%
2035
-0.0002%
-0.0005%
-0.0030%
-0.0037%
2036
-0.0003%
-0.0005%
-0.0030%
-0.0037%
2037
-0.0003%
-0.0005%
-0.0030%
-0.0037%
2038
-0.0003%
-0.0005%
-0.0030%
-0.0038%
2039
-0.0003%
-0.0005%
-0.0030%
-0.0038%
2040
-0.0003%
-0.0005%
-0.0030%
-0.0038%
2041
-0.0004%
-0.0005%
-0.0030%
-0.0039%
8-6
-------
United States Office of Air Quality Planning and Standards Publication No. EPA-452/R-24-002
Environmental Protection Health and Environmental Impacts Division January 2024
Agency Research Triangle Park, NC
1
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