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Regulatory Impact Analysis for
the Review and Reconsideration of the Oil and
Natural Gas Sector Emission Standards for
New, Reconstructed, and Modified Sources

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ii

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EPA-452/R-20-004
August 2020
Regulatory Impact Analysis for
the Review and Reconsideration of the Oil and Natural Gas Sector Emission Standards for New,
Reconstructed, and Modified Sources
U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards
Health and Environmental Impacts Division
Research Triangle Park, NC
111

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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
Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air and Radiation,
Research Triangle Park, North Carolina 27711 (email: macpherson.alex@epa.gov).
ACKNOWLEDGEMENTS
In addition to U.S. EPA staff from the Office of Air and Radiation, personnel from the U.S. EPA
Office of Policy and SC&A contributed data and analysis to this document.
iv

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TABLE OF CONTENTS
Table of Contents	v
List of Tables	vii
List of Figures	ix
1	Executive Summary	1-1
1.1	Introduction	1-1
1.2	Summary of Results	1-3
1.3	Organization of this Document	1-5
2	Regulatory Impact Analysis for the Oil and Natural Gas Sector: Emission
Standards for New, Reconstructed, and Modified Sources Review	2-6
2.1	Introduction	2-6
2.1.1	Summary of Changes Since the Final 2016 NSPS RIA	2-7
2.1.2	Rescinded Regulatory Requirements	2-9
2.1.3	Policy Review: Summary of Key Results	2-10
2.1.4	Organization of the Policy Review RIA	2-12
2.2	Projected Compliance Cost Reductions and Forgone Emissions Reductions	2-12
2.2.1	Pollution Controls and Emissions Points Assessed in this RIA	2-12
2.2.2	Compliance Cost Analysis	2-15
2.2.3	Projection of Affected Facilities	2-16
2.2.4	Forgone Emissions Reductions	2-19
2.2.5	Forgone Product Recovery	2-20
2.2.6	Compliance Cost Reductions	2-22
2.2.7	Detailed Impacts Tables	2-24
2.2.8	Present Value and Equivalent Annualized Value of Cost Reductions	2-27
2.3	Forgone Benefits	2-29
2.3.1	Introduction	2-29
2.3.2	Forgone Emissions Reductions	2-33
2.3.3	Methane Climate Effects and Valuation	2-35
2.3.4	VOC as an Ozone Precursor	2-42
2.3.5	VOC as a PM2 5 Precursor	2-44
2.3.6	Hazardous Air Pollutants (HAP)	2-47
2.4	Economic Impacts and Distributional Assessments	2-54
2.4.1	Energy Markets Impacts	2-54
2.4.2	Distributional Impacts	2-55
2.4.3	Small Business Impacts	2-58
2.4.4	Employment Impacts	2-58
2.5	Comparison of Benefits and Costs	2-63
2.5.1	Comparison of Benefits and Costs	2-63
2.5.2	Uncertainties and Limitations	2-64
2.6	References	2-67
3	Regulatory Impact Analysis for the Oil and Natural Gas Sector: the
Emission Standards for New, Reconstructed, and Modified Sources
Reconsideration	3-1
3.1 Introduction	3-1
3.1.1	Summary of Changes Since the Final 2016 NSPS RIA	3-3
3.1.2	Summary of Changes Based on Information Received During Comment Period	3-7
3.1.3	Regulatory Options	3-9
3.1.4	Technical Reconsideration: Summary of Key Results	3-12
v

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3.1.5 Organization of the Technical Reconsideration RIA	3-14
3.2	Compliance Cost Reductions and Forgone Emissions Reductions	3-14
3.2.1	Pollution Controls and Emissions Points Assessed	3-15
3.2.2	Source-level Compliance Cost Reductions and Emission Increases	3-18
3.2.3	Projection of Affected Facilities	3-21
3.2.4	Forgone Emissions Reductions	3-28
3.2.5	Forgone Product Recovery	3-30
3.2.6	Compliance Cost Reductions	3-31
3.2.7	Comparison of Regulatory Alternatives	3-33
3.2.8	Detailed Impact Tables	3-35
3.2.9	Present Value and Equivalent Annualized Value of Cost Reductions	3-39
3.3	Forgone Benefits of the Technical Reconsideration	3-43
3.3.1	Forgone Emissions Reductions	3-44
3.3.2	Methane Climate Effects and Valuation	3-45
3.3.3	VOC as an Ozone Precursor	3-48
3.3.4	VOC as a PM2 5 Precursor	3-48
3.3.5	Hazardous Air Pollutants (HAP)	3-48
3.4	Economic Impacts and Distributional Assessments	3-49
3.4.1	Energy Markets Impacts	3-49
3.4.2	Distributional Impacts	3-49
3.4.3	Small Business Impacts	3-50
3.4.4	Employment Impacts	3-51
3.5	Comparison of Benefits and Costs	3-54
3.5.1	Comparison of Benefits and Costs	3-54
3.5.2	Uncertainties and Limitations	3-56
3.6	References	3-59
4 Analysis of the Combined Regulatory Impacts of the Policy Review and
Technical Reconsideration	4-1
4.1	Introduction	4-1
4.2	Compliance Cost Reductions and Forgone emissions reductions	4-2
4.2.1	Pollution Controls and Emissions Points Assessed in this RIA	4-2
4.2.2	Projection of Affected Facilities	4-2
4.2.3	Forgone Emissions Reductions	4-2
4.2.4	Forgone Product Recovery	4-3
4.2.5	Compliance Cost Reductions	4-4
4.2.6	Present Value and Equivalent Annualized Value of Cost Reductions	4-6
4.3	Forgone Benefits	4-8
4.4	Economic Impacts and Distributional Assessments	4-9
4.5	Comparison of Benefits and Costs	4-10
4.5.1	Comparison of Benefits and Costs	4-10
4.5.2	Uncertainties and Limitations	4-11
APPENDIX A Additional Information on Activity Count Projections	A-1
A.l Updated Baseline	A-l
A.2 Data Sources	A-l
A. 3 Number of Well Sites	A-2
A.4 Gathering and Boosting Stations and Transmission and Storage Compressor Stations	A-4
A. 5 Nationwide Activity Data for Other Equipment	A-5
A.5.1 Pneumatic Pumps	A-6
A.5.2 Compressors	A-7
A.5.3 Storage Vessels	A-8
A.5.4 Pneumatic Controllers	A-8
A.5.5 Summary of Affected Facilities Requiring Certification	A-8
vi

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APPENDIX B Uncertainty Associated with Estimating the Social Cost of
Methane 	B-l
B. 1	Overview of Methodology Used to Develop Interim Domestic SC-CH4 Estimates	B-l
B.2	Treatment of Uncertainty in Interim Domestic SC-CH4 Estimates	B-3
B. 3	Forgone Global Climate Benefits	B -8
B.4	References	B-10
LIST OF TABLES
Table 1-1 Compliance Cost Reductions, Forgone Benefits, and Forgone Emissions Reductions of the Policy
Review, 2021-2030 (millions 2016$)	1-3
Table 1-2 Compliance Cost Reductions, Forgone Benefits, and Forgone Emissions Reductions of the Technical
Reconsideration, 2021-2030 (millions 2016$)	1-4
Table 1-3 Compliance Cost Reductions, Forgone Benefits, and Forgone Emissions Reductions of the Combined
Policy Review and Technical Reconsideration, 2021-2030 (millions 2016$)	1-4
Table 2-1 Projected Impacts of the 2016 NSPS OOOOa Transmission and Storage Requirements: 2016 NSPS
RIA and Updated Baseline Comparison1	2-9
Table 2-2 Emissions Sources and Baseline Requirements in the Transmission and Storage Segment	2-10
Table 2-3 Projected NSPS-Affected Sources in Transmission and Storage, 2021-2030	2-18
Table 2-4 Projected Forgone Emissions Reductions from Policy Review, 2021-2030	2-20
Table 2-5 Projected Decrease in Natural Gas Recovery for Policy Review, 2021-2030	2-21
Table 2-6 Estimated Cost Reductions under the Policy Review, 2021-2030 (millions 2016$)	2-23
Table 2-7 Estimated Cost Reductions for the Policy Review, 2021-2030 (millions 2016$)	2-24
Table 2-8 Affected Sources, Forgone Emissions Reductions, and Compliance Cost Reductions for the Policy
Review, 2021 	2-26
Table 2-9 Affected Sources, Forgone Emissions Reductions, and Compliance Cost Reductions for the Policy
Review, 2030	2-26
Table 2-10 Undiscounted Projected Compliance Cost Reductions for the Policy Review, 2021-2030 (millions
2016$)	2-28
Table 2-11 Discounted Cost Reductions for the Policy Review using 7 and 3 Percent Discount Rates (millions
2016$)	2-29
Table 2-12 Climate and Human Health Effects of Forgone Emission Reductions under the Policy Review	2-32
Table 2-13 Projected Total Forgone Emissions Reductions under the Policy Review, 2021-2030	2-35
Table 2-14 Projected Annual Forgone Reductions of Methane, VOC, and HAP Emissions under the Policy
Review, 2021-2030	2-35
Table 2-15 Interim Domestic Social Cost of CH4, 2021-2030 (in 2016$ per metric ton CH4)1	2-38
Table 2-16 Projected Forgone Domestic Climate Benefits under the Policy Review, 2021-2030 (millions, 2016$)..
	2-39
Table 2-17 Changes in Labor Required to Comply at the Impacted Facility Level	2-61
Table 2-18 Estimates of the Decrease in Upfront Labor Required (in FTEs) under the Policy Review, 2021-2030 ..
	2-62
Table 2-19 Estimates of the Decrease in Annual Labor Required (in FTEs) under the Policy Review, 2021-2030 ...
	2-62
Table 2-20 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone Monetized Benefits, Cost
Reductions, and Net Benefits forthe Policy Review, 2021-2030 (millions, 2016$)	2-64
Table 2-21 Summary of Forgone Emission Reductions for the Policy Review, 2021-2030	2-64
Table 3-1 Estimated Compliance Costs and Emission Reductions of the 2016 NSPS OOOOa Fugitive Emissions
Monitoring Requirements in the Production and Processing Segment: 2016 NSPS RIA and Updated
Baseline Comparison	3-7
Table 3-2 Emissions Sources and Controls Evaluated by Regulatory Alternative	3-10
Table 3-3 Incremental Reconsideration-impacted Source Counts for Finalized Option 3, 2021-2030 	 3-27
Table 3-4 Total Reconsideration-impacted Source Counts for Finalized Option 3, 2021-2030	 3-28

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Table 3-5 Reconsideration-impacted Well Site Counts by Alternative Fugitive Emissions Standards Status for
Finalized Option 3, 2021-2030	 3-28
Table 3-6 Forgone Emissions Reductions under Finalized Option 3, 2021-2030 	 3-29
Table 3-7 Decrease in Natural Gas Recovery for Finalized Option 3, 2021-2030 	 3-31
Table 3-8 Estimated Cost Reductions for Finalized Option 3, 2021-2030 (millions 2016$)	3-32
Table 3-9 Estimated Cost Reductions for Finalized Option 3 at 3 and 7 Percent Interest Rates, 2021-2030
(millions 2016$)	3-33
Table 3-10 Comparison of Regulatory Alternatives in 2021 and 2030	 3-34
Table 3-11 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Option 1, 2021.
	3-36
Table 3-12 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Option 1, 2030.
	3-36
Table 3-13 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Option 2, 2021.
	3-37
Table 3-14 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Option 2, 2030.
	3-37
Table 3-15 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Finalized
Option 3, 2021	 3-38
Table 3-16 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Finalized
Option 3, 2030	 3-38
Table 3-17 Estimated Cost Reductions for Finalized Option 3, 2021-2030 (millions 2016$)	3-40
Table 3-18 Discounted Cost Reductions Estimates for Finalized Option 3, 7 Percent Discount Rate (millions
2016$)	3-41
Table 3-19 Comparison of Regulatory Alternatives, 7 Percent Discount Rate	3-42
Table 3-20 Cost Reductions for the Finalized Option 3 Discounted at 7 and 3 Percent Rates (millions 2016$). 3-42
Table 3-21 Total Direct Increases in Emissions, 2021-2030	 3-45
Table 3-22 Annual Direct Increases in Methane, VOC and HAP Emissions, 2021-2030	 3-45
Table 3-23 Estimated Forgone Domestic Climate Benefits of Option 3, 2021-2030 (millions, 2016$)	3-47
Table 3-24 Total Estimated Forgone Domestic Climate Benefits (millions, 2016$)	3-48
Table 3-25 Facility-level Changes in Labor Required to Comply with NSPS OOOOa (hours per facility per year)..
	3-52
Table 3-26 Estimates of the Decrease in Upfront Labor Required (in FTE), 2021-2030	 3-53
Table 3-27 Estimates of the Decrease in Annual Labor Required (in FTE), 2021-2030	 3-53
Table 3-28 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone Monetized Benefits, Cost
Reductions, and Net Benefits for Unselected Option 1 from 2021 to 2030 (millions, 2016$)	3-55
Table 3-29 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone Monetized Benefits, Cost
Reductions, and Net Benefits for Unselected Option 2 from 2021 to 2030 (millions, 2016$)	3-55
Table 3-30 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone Monetized Benefits, Cost
Reductions, and Net Benefits for Finalized Option 3 from 2021 to 2030 (millions, 2016$)	3-56
Table 3-31 Summary of Total Forgone Emissions Reductions across Options, 2021-2030	 3-56
Table 4-1 Projected Forgone Emissions Reductions from the Combined Policy Review and Technical
Reconsideration, 2021-2030	4-3
Table 4-2 Projected Decrease in Natural Gas Recovery from the Combined Policy Review and Technical
Reconsideration, 2021-2030	4-4
Table 4-3 Estimated Cost Reductions from the Combined Policy Review and Technical Reconsideration, 2021-
2030 (millions 2016$)	4-5
Table 4-4 Estimated Cost Reductions from the Combined Policy Review and Technical Reconsideration, 2021-
2030 (millions 2016$)	4-6
Table 4-5 Undiscounted Projected Compliance Cost Reductions from the Combined Policy Review and
Technical Reconsideration, 2021-2030 (millions 2016$)	4-7
Table 4-6 Discounted Cost Reductions from the Combined Policy Review and Technical Reconsideration, using
7 and 3 Percent Discount Rates (millions 2016$)1	4-7
Table 4-7 Projected Forgone Domestic Climate Benefits Reductions from the Combined Policy Review and
Technical Reconsideration, 2021-2030 (millions, 2016$)	4-9
Table 4-8 Estimates of the Decrease in Labor Required for Compliance (in FTEs), 2021-2030	4-10

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Table 4-9 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone Monetized Benefits, Cost
Reductions, and Net Benefits from the Combined Policy Review and Technical Reconsideration,
2021-2030 (millions, 2016$)	4-11
Table 4-10 Summary of Forgone Emission Reductions from the Combined Policy Review and Technical
Reconsideration, 2021-2030	4-11
LIST OF FIGURES
Figure 2-1 2014 NATA Model Estimated Census Tract Carcinogenic Risk from HAP Exposure from All Outdoor
Sources based on the 2014 National Emissions Inventory	2-49
Figure 3-1 Estimated Percent of Well Sites in Low Production Status by Age of Site	3-26
IX

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1 EXECUTIVE SUMMARY
1.1 Introduction
This regulatory analysis accompanies the final review and reconsideration of the new source
performance standards (NSPS) at 40 Code of Federal Regulations (CFR) part 60, subpart OOOO
(2012 NSPS OOOO) and OOOOa (2016 NSPS 0000a). The Environmental Protection Agency
(EPA) is finalizing two simultaneous actions that amend the requirements of the 2012 NSPS
OOOO and 2016 NSPS OOOOa. This document presents regulatory impact analyses (RIAs) for
both actions separately and presents the combined impacts of the two actions.
Policy Review: The first RIA in this document presents the regulatory impacts of the final
amendments to the 2012 NSPS OOOO and 2016 NSPS OOOOa. These amendments, which we
refer to in this document as the "Policy Review," remove sources in the transmission and storage
segment from the source category, rescind the NSPS (including both the volatile organic
compounds and GHG requirements in form of limitations on methane) applicable to those
sources, and rescind the methane-specific requirements of the NSPS applicable to sources in the
production and processing segments.
Technical Reconsideration: The second RIA in this document presents the regulatory impacts
of the finalized set of amendments pertaining to several technical aspects of the 2016 NSPS
OOOOa, which we refer to in this document at the "Technical Reconsideration." The EPA
finalized amendments to the fugitive emissions requirements, well site pneumatic pump
standards, requirements for certification of closed vent systems (CVS) by a professional
engineer, and alternative fugitive emissions standards for several state programs. The Technical
Reconsideration also includes other amendments, though the impacts of these other amendments
are not presented in this document for reasons discussed below and in Chapter 3. These other
amendments address issues raised in the reconsideration petitions for the oil and natural gas
NSPS, as well as streamline the implementation of the rule. The Technical Reconsideration also
includes technical corrections and additional clarifying language in the regulatory text and/or
preamble where the EPA concluded that further clarification was warranted.
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The impacts of regulatory actions are evaluated relative to a baseline that represents the world
without the regulatory action. Because the preambles and amended regulatory text for the two
actions are sequenced, starting with the Policy Review, we evaluate the regulatory impacts of the
actions within this document using the same sequence. The Policy Review removes sources in
the transmission and storage segment from the source category, so these sources are not affected
by the Technical Reconsideration, and therefore not in the baseline used to estimate impacts of
the Technical Reconsideration.
To better inform the public on the aggregate regulatory impacts of the two final actions, we
follow the two RIAs with an analysis that combines the regulatory impacts of the two actions
relative to a baseline representing the regulatory landscape in the absence of either action, i.e.,
the same baseline used in the Policy Review analysis. Throughout this document, we focus the
analysis on the final amendments that result in quantifiable compliance cost or emissions
changes compared to the relevant baseline. We do not analyze the regulatory impacts of all
amendments because we either do not have sufficient data or because it is assumed the
provisions would not result in compliance cost or emissions impacts; in these instances, we
qualitatively discuss the amendments.
Compared to the analysis presented in the 2016 NSPS RIA, this analysis reflects updated
assumptions based on new information on existing and projected source counts, model plant
emissions and control costs, natural gas prices, and state and local regulations that have been
promulgated since the 2016 NSPS OOOOa was finalized. Additional updates reflect information
received during the comment period of the Technical Reconsideration.1 Aside from these
updates, which are described in detail in Sections 2.1 and 3.1, the same assumptions and methods
used in the 2016 NSPS RIA were used in this analysis to estimate an updated baseline. The
updated baseline represents the EPA's best assessment of the current and future state of the
industry absent the changes finalized under the Policy Review and Technical Reconsideration.
1 See the preamble for the Technical Reconsideration and its response to comments document, which are available
in the docket.
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1.2 Summary of Results
Table 1-1 presents the present value (PV) and equivalent annual value (EAV), estimated using
discount rates of 7 and 3 percent, of the changes in quantified benefits, costs, and net benefits, as
well as the forgone emissions reductions relative to the baseline due to the Policy Review. These
values reflect a 2021 through 2030 analysis period, discounted to 2020, and are presented in
2016 dollars. When discussing net benefits, we refer to the cost reductions as the "benefits" of
the final actions and the forgone benefits as the "costs" of the final actions. The net benefits are
the benefits (cost reductions) minus the costs (forgone benefits). All costs and benefits presented
in Table 1-1 are estimated relative to a baseline without the Policy Review or Technical
Reconsideration. Table 1-2 presents the PV and EAV for the Technical Reconsideration, which
includes the final amendments of the Policy Review in the baseline. Table 1-3 presents the
combined results of the Policy Review and Technical Reconsideration, compared to a baseline
without either of the two final rules, which is equivalent to summing the results in Table 1-2 and
Table 1-3.
Table 1-1 Compliance Cost Reductions, Forgone Benefits, and Forgone Emissions
Reductions of the Policy Review, 2021-2030 (millions 2016$)	
7% Discount Rate
3% Discount Rate

Present
Value
Equivalent
Annualized
Value
Present
Value
Equivalent
Annualized
Value
Benefits (Total Cost Reductions)
$31
$4.1
$38
$4.3
Cost Reductions
$67
$8.9
$83
$9.4
Forgone Value of Product Recovery
$36
$4.7
$45
$5.1
Costs (Forgone Domestic Climate Benefits)1
$17
$2.2
$63
$7.2
Net Benefits
$14
$1.9
-$25
-$2.9
Forgone Emissions Reductions	2021-2030 Total
Methane (short tons)	400,000
VOC	11,000
HAP	330
Methane (million metric tons CO2 Eq.)	9
Note: Estimates may not sum due to independent rounding.
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions. While we expect
that the forgone VOC and HAP emissions reductions may also degrade air quality and adversely affect health and
welfare, data limitations prevent us from quantifying and monetizing these effects.
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Table 1-2 Compliance Cost Reductions, Forgone Benefits, and Forgone Emissions
Reductions of the Technical Reconsideration, 2021-2030 (millions 2016$)	
7% Discount Rate
3% Discount Rate

Present
Value
Equivalent
Annualized
Value
Present
Value
Equivalent
Annualized
Value
Benefits (Total Cost Reductions)
$750
$100
$950
$110
Cost Reductions
$800
$110
$1,000
$110
Forgone Value of Product Recovery
$44
$5.9
$57
$6.5
Costs (Forgone Domestic Climate Benefits)1
$19
$2.5
$71
$8.1
Net Benefits
$730
$97
$880
$100
Forgone Emissions Reductions	2021-2030 Total
Methane (short tons)	450,000
VOC	120,000
HAP	4,700
Methane (million metric tons CO2 Eq.)	10
Note: Estimates may not sum due to independent rounding.
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions. While we expect
that the forgone VOC and HAP emissions reductions may also degrade air quality and adversely affect health and
welfare, data limitations prevent us from quantifying and monetizing these effects.
Table 1-3 Compliance Cost Reductions, Forgone Benefits, and Forgone Emissions
Reductions of the Combined Policy Review and Technical Reconsideration, 2021-2030
(millions 2016$)	
7% Discount Rate
3% Discount Rate

Present
Value
Equivalent
Annualized
Value
Present
Value
Equivalent
Annualized
Value
Benefits (Total Cost Reductions)
$780
$100
$990
$110
Cost Reductions
$860
$110
$1,100
$120
Forgone Value of Product Recovery
$80
$11
$100
$12
Costs (Forgone Domestic Climate Benefits)1
$35
$4.7
$130
$15
Net Benefits
$750
$99
$850
$97
Forgone Emissions Reductions	2021-2030 Total
Methane (short tons)	850,000
VOC	140,000
HAP	5,000
Methane (million metric tons CO2 Eq.)	19
Note: Estimates may not sum due to independent rounding.
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions. While we expect
that the forgone VOC and HAP emissions reductions may also degrade air quality and adversely affect health and
welfare, data limitations prevent us from quantifying and monetizing these effects.
Beyond the top-level cost and benefit information presented in Tables 1-1 through 1-3, there may
be other economic impacts resulting from the final Policy Review and the final Technical
Reconsideration. Under both actions individually and combined, we expect reductions in the
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small (less than 1 percent) impacts on energy production and markets estimated for the final
NSPS in the 2016 NSPS RIA. While we did not conduct quantitative distributional impacts
analyses of the rules, we do not expect the cost reductions to be distributed evenly across
affected entities, and we do not expect the forgone benefits resulting from the finalized actions to
be distributed uniformly across the U.S. Since these final actions are deregulatory, we concluded
that they will relieve regulatory burden for small (and non-small) entities subject to the
reconsidered provisions, and thus will not have a significant impact on a substantial number of
small entities (SISNOSE). Finally, we expect reductions in labor associated with compliance-
related activities due to the Policy Review and Technical Reconsideration; however, we did not
quantify broader labor impacts on the industry or other sectors of the economy.
1.3 Organization of this Document
Chapters 2, 3, and 4 present the results of this RIA for the Policy Review, Technical
Reconsideration, and Full Review and Reconsideration {i.e., combined actions), respectively.
Each of these chapters describes the emissions, compliance cost, and forgone benefits analysis of
the final actions relative to their respective baselines, as well as their economic impacts. The
analyses use similar methods to those used in the 2016 NSPS RIA.2 The remainder of this report
describes this methodology, with explanations of the instances in which the underlying data,
assumptions, or methods changed from the 2016 NSPS RIA. The bulk of the supporting
technical details which apply to all three analyses are presented in Chapter 2, with Chapters 3
and 4 referring to Chapter 2 rather than repeating those details.
2 Found at: https://www3.epa.gov/ttn/ecas/docs/ria/oilgas_ria_nsps_final_2016-05.pdf.
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2 REGULATORY IMPACT ANALYSIS FOR THE OIL AND NATURAL GAS
SECTOR: EMISSION STANDARDS FOR NEW, RECONSTRUCTED, AND
MODIFIED SOURCES REVIEW
2.1 Introduction
This final action (called the "Policy Review" in this document) rescinds the requirements of the
subpart OOOO (2012 NSPS 0000) and 0000a (2016 NSPS 0000a) for oil and natural gas
sources in the transmission and storage segment. The Policy Review also rescinds the methane
standards for sources in the production and processing segments, while leaving VOC
requirements in place for production and processing sources. The EPA has determined in this
final action that the methane control options are the same as VOC control options, and thus the
methane standard is redundant. As such, there are no expected cost or emissions impacts from
removing the methane requirements for potential new, reconstructed, and modified sources in the
production and processing segments.
In this RIA, we present estimated benefits and costs of the final Policy Review action. A more
detailed description of the regulatory baseline is below. We project impacts for the years 2021
through 2030. All monetized impacts of these changes are presented in 2016 dollars. This
analysis also presents benefits and costs in a present value (PV) framework. All sources in the
transmission and storage segment that are affected by subparts 0000 and 0000a (hereafter
referred to as "the NSPS") are impacted by this final deregulatory action if they would have been
affected by the NSPS in the baseline.
The regulatory impacts of this action pertain specifically to potential new, reconstructed, and
modified sources under the NSPS. The EPA recognizes that by rescinding the applicability of the
NSPS for methane, issued under CAA section 111(b), existing sources in the source category
will not be subject to regulation under C AA section I I 1(d). Analysis of potential impacts of
removing the requirement to regulate existing sources under 111(d) is outside the scope of this
RIA.
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2.1.1 Summary of Changes Since the Final 2016 NSPS RIA
2.1.1.1 Updated Information
This analysis uses the same methodologies as the 2016 NSPS RIA but changes some
assumptions based on updated data. The following list highlights the updates and revisions made
to the methodology since the 2016 NSPS RIA:
•	Annual Energy Outlook: For the 2016 NSPS RIA, we used the 2015 Annual Energy
Outlook (AEO). For this analysis, we use the AE02020, published in January 2020.3 The
natural gas price projections are used to estimate the value of product recovery. The use
of the AE02020 for the final rule is also an update from the RIA associated with the
proposal of this action, which used the AEO2018. The projections of Henry Hub natural
gas prices in AE02020 are lower than the AEO2015 projections used in the 2016 RIA.
•	Source Projections: Since the promulgation of the 2016 NSPS OOOOa, the U.S.
Greenhouse Gas Inventory (GHGI) has been updated.4 The data from the updated GHGI
were used to project the number of NSPS-affected compressor stations, reciprocating
compressors, and pneumatic controllers over time. Compared to the 2016 NSPS RIA, the
projected number of NSPS-affected compressor stations, reciprocating compressors, and
pneumatic controllers in the transmission and storage segment increased. For centrifugal
compressors and storage vessels, we relied on information from the 2016 NSPS OOOOa
rule compliance reports received in 2018 and determined that there are unlikely to be new
centrifugal compressors and storage vessels constructed in the future in the transmission
and storage segment.
•	Social Cost of Methane: In the 2016 NSPS OOOOa, the EPA used an estimate of the
global social cost of methane to monetize the climate related benefits associated with
reductions in methane emissions. Since the promulgation of the 2016 NSPS OOOOa,
Executive Order (E.O.) 13783 has been signed, which directs agencies to ensure that
estimates of the social cost of greenhouse gases used in economic analyses are consistent
with the guidance contained in the Office of Management and Budget (OMB) Circular A-
4, "including with respect to the consideration of domestic versus international impacts
and the consideration of appropriate discount rates" (E.O. 13783, Section 5(c)). Thus, for
this action, we use an interim estimate of the domestic social cost of methane to estimate
the forgone climate benefits resulting from the forgone methane emissions reductions due
to this final action.
•	Model Plants: The costs of the fugitive emissions monitoring requirements promulgated
in 2016 for transmission and storage compressor stations have been updated. Specifically,
the estimate of upfront costs of the fugitive monitoring program have increased while the
annual cost estimates have decreased.5
3	AE02020 can be found at https://www.eia.gov/outlooks/aeo/. Accessed April 26, 2020.
4	The updated GHGI data used is from the April 2018 release. For information on the inventory, visit
https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks/. Accessed April 26, 2020.
5	For more information on the model plants, see the docketed memorandum titled: U.S. EPA. 2020. Memorandum:
Control Cost and Emission Changes under the Final Amendments to 40 CFR Part 60, subpart OOOOa Under
Executive Order 13783.
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• Other: In the 2016 NSPS OOOOa, all dollar figures were presented in 2012 dollars. In
this analysis, all estimated impacts are presented in 2016 dollars.6 In the 2016 NSPS RIA,
we presented impacts for the snapshot years of 2020 and 2025. For this analysis, we
estimate cost reductions and emissions changes resulting from changes in compliance
activities projected to occur in each year from 2021 through 2030 due to this final action.
We discount the annual cost reductions to 2020 and present total PV and equivalent
annualized value (EAV) over the analysis period.7
Note that, although there are states with similar requirements for transmission and storage
sources as the NSPS, we are unable to account for these requirements in the evaluation of this
action.8
2.1.1.2 Updated Baseline for the Policy Review
Table 2-1 shows the projected number of NSPS-affected facilities, methane, VOC, and HAP
emission reductions, and the total annualized costs including the value of product recovery in
2021 and 2025 for the sources in the transmission and storage segment as estimated in the 2016
NSPS RIA and relative to the baseline used for this action. Based on updated facility
projections,9 there may be more affected facilities than anticipated in the 2016 NSPS RIA.10
Consequently, for the subset of 2016 NSPS provisions affected by the Policy Review,
compliance cost and emissions impacts of the 2016 NSPS were likely underestimated in the 2016
analysis. The emission reductions presented here are the emission reductions assuming the
affected sources were not performing compliance activities prior to the 2016 NSPS OOOOa.
6	Costs were adjusted to 2016 dollars using the seasonally adjusted annual Gross Domestic Product: Implicit Price
Deflator updated by the Federal Reserve on April 13, 2020.
7	The proposal RIA discounted to 2016. In this RIA, we discount to 2020 to improve interpretability.
8	For the Policy Review and for the Technical Reconsideration, the EPA projected affected facilities using a
combination of historical data from the U.S. GHG Inventory, DI Desktop, EPA compliance reports, and
projected activity levels taken from the AEO. Because oil and natural gas well locations are identified in DI
Desktop, we can forecast well drilling activities by state. As a result, we can estimate the effects of state
regulations on future affected facilities that draw upon state-specific information. However, projections of
affected facilities that draw upon the GHGI, such as sources in the transmission and storage segment, are
national-scale and, hence, we are unable to account for state-level regulations in our analysis.
9	See Section 2.3 and Appendix A for details on facility projections.
10	Results from the 2016 NSPS RIA are generally not comparable to results in this analysis because of changes to
the baseline. The higher count of affected facilities in transmission and storage results from higher growth in the
historical period used to estimate new facilities compared to the historical data used in 2016, which showed little
growth in transmission and storage. Affected facility counts in transmission and storage are sensitive to the
historical data used. Changes in transmission and storage-related methane, VOC, and HAP emissions compared
to the 2016 baseline shown in Table 2-1 result from changes in the projected facility counts as the source-level
emissions characteristics are the same as in the 2016 analysis.
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Table 2-1 Projected Impacts of the 2016 NSPS OOOOa Transmission and Storage
Requirements: 2016 NSPS RIA and Updated Baseline Comparison1	

2016 NSPS RIA
Updated Baseline

20212
2025
2021
2025
Counts of NSPS-Affected Sources in
970
1,500
3,000
4,600
Transmission and Storage
Methane Emission Reductions (short tons)
12,000
20,000
27,000
43,000
VOC Emission Reductions (tons)
340
540
760
1,200
Total Annualized Compliance cost, without
Product Recovery (7%, millions, 2016$)3
$3.7
$5.8
$6.0
$9.5
Total Annualized Compliance cost, with
Product Recovery (7%, millions, 2016$)3
$1.1
$1.8
$2.9
$3.9
1	The emission reductions presented here are the emission reductions assuming the affected sources were not
performing compliance activities prior to the 2016 NSPS OOOOa.
2	While the 2016 NSPS RIA only summarized results for 2020 and 2025, we used the same underlying data
described in the 2016 NSPS TSD to estimate impacts for 2021.
3	Excluding compliance cost of professional engineer certification, as well as other provisions in the 2016 NSPS
OOOOa unrelated to fugitive emissions monitoring requirements.
2.1.2 Rescinded Regulatory Requirements
The projected compliance cost reductions and forgone emission reductions from rescinding the
NSPS requirements for transmission and storage sources are equal to the cost and emissions
impacts that would have resulted from keeping the 2016 requirements in place after accounting
for the updates described in the preceding section. The universe of affected sources includes all
sources in the transmission and storage segment that would be considered new or modified under
the oil and natural gas NSPS and would be complying with the rule in absence of this action.
For example, compressor stations in the transmission sector that become NSPS-affected sources
in 2016 are also affected by this action because they are expected to cease NSPS-required
activities related to the fugitive emissions monitoring and repair requirements. However,
compressor stations in the gathering and boosting sector are not affected by this action because
they are in the production and processing segment, which is still required to comply with
quarterly fugitive emissions monitoring and repair requirements. Table 2-2 summarizes the
sources affected by this action and their respective regulatory requirements in the baseline.
We estimate that there are no affected centrifugal compressors and storage vessels in the
transmission and storage segment, so we do not anticipate any regulatory impacts associated with
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the Policy Review on these sources. Similarly, we do not currently have the necessary data to
estimate the effects of the Policy Review on compressor stations on the Alaska North Slope.
Table 2-2 Emissions Sources and Baseline Requirements in the Transmission and
Storage Segment	
Emissions Point and Control
Requirements in the Baseline
Fugitive Emissions - Planning, Monitoring and Maintenance
Compressor Stations
Compressor Stations on Alaska North Slope1
Pneumatic Controllers
Reciprocating Compressors
Centrifugal Compressors3
Storage Vessels3
Quarterly monitoring
Annual monitoring
Replace high-bleed with low-bleed
Replace rod packing every 26,000
hours2
Route to control
Storage vessels with VOC emissions
of 6 tons a year or more must reduce
VOC emissions by at least 95 percent
1	We do not currently have data to estimate the effects of the Policy Review on compressor stations on the Alaska
North Slope.
2	Operators have a choice to replace rod packings either every 36 months or 26,000 hours. As in the 2016 NSPS
TSD, we assume compliance with the latter, which suggests replacement every 3.8 years for transmission sources
and 4.4 years for storage sources based on operating data.
3	We currently estimate that there are no affected centrifugal compressors or storage vessels in the transmission and
storage segment.
2.1.3 Policy Review: Summary of Key Results
A summary of the key results is shown below. All estimates are in 2016 dollars. Also, all
compliance costs, emissions changes, and benefits are estimated relative to a baseline without the
impacts of the Policy Review and Technical Reconsideration. We estimate that the Policy
Review will potentially affect approximately 38 firms.11
• Emissions Analysis: The Policy Review is projected to forgo methane emission
reductions of 22,000 short tons in 2021 and 58,000 short tons in 2030 and a total of
400,000 short tons from 2021 to 2030. Forgone VOC emission reductions are projected
to be 610 short tons in 2021 and 1,600 short tons in 2030 and a total of 11,000 short tons
from 2021 to 2030. Forgone HAP emissions are projected to be 18 short tons in 2021 and
48 short tons in 2030 and a total of 330 short tons from 2021 to 2030.
11 We estimate the number of firms potentially affected firms using information in the Information Collection
Request (ICR) Supporting Statement associated with this rulemaking. Before promulgating the Policy Review,
the EPA estimates that up to 575 firms would be subject to NSPS OOOOa during the 3-year period covered by
the ICR (Table Id of the Supporting Statement). We then estimate that up to 537 respondents per year will be
subject to NSPS OOOOa during the 3-year period covered by the ICR (Section 6(d) of the Supporting
Statement). As a result, we estimate the incremental number of firms potentially affected by the Policy Review to
be the difference between 575 and 537, or 38 firms.
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•	Benefits Analysis: The Policy Review is projected to result in forgone climate, health,
and welfare benefits. The PV of the domestic forgone climate benefits, using an interim
estimate of the domestic social cost of methane (SC-CH4) and discounting at a 7 percent
rate is $17 million from 2021 to 2030. The EAV is estimated to be $2.2 million per year.
Using the interim SC-CH4 estimate based on the 3 percent rate, the PV of forgone
domestic climate benefits is estimated to be $63 million; the EAV is estimated to be $7.2
million per year. The EPA expects that forgone VOC emission reductions will negatively
affect air quality and likely affect health and welfare adversely due to impacts on ozone,
PM2.5, and HAP, but we are unable to quantify these effects at this time. This omission
does not imply that these forgone benefits do not exist.
•	Compliance Cost Analysis: The Policy Review is projected to result in compliance cost
reductions. The PV of the compliance cost reduction associated with this final rule over
the 2021 to 2030 period is estimated to be $67 million (2016$) using a 7 percent discount
rate and $83 million using a 3 percent discount rate. The EAV of these cost reductions is
estimated to be $8.9 million per year using a 7 percent discount rate and $9.4 million per
year using a 3 percent discount rate. These estimates do not include the forgone producer
revenues associated with a decrease in the recovery of saleable natural gas due to this
final action, as some of the compliance actions required in the baseline would likely have
captured saleable product that would have otherwise been emitted. Using the AE02020
projection of natural gas prices to estimate the value of the change in the recovered gas at
the wellhead expected to result from this action, the EPA estimated a PV of regulatory
compliance cost reductions of the final rule over the 2021 to 2030 period of $31 million
using a 7 percent discount rate and $38 million using a 3 percent discount rate. The
corresponding estimates of the EAV of cost reductions after accounting for forgone
product recovery revenues are $4.1 million per year using a 7 percent discount rate and
$4.3 million per year using a 3 percent discount rate.12
•	Energy Markets Impacts Analysis: The 2016 NSPS RIA estimated small (less than 1
percent) impacts on energy production and markets. The EPA expects that the
deregulatory Policy Review will reduce energy market impacts of the NSPS.
•	Distributional Impacts: The cost reductions and any forgone benefits likely to arise
from the Policy Review are not expected to be distributed uniformly across the
population, and may not accrue equally to the same individuals, firms, or communities
impacted by the 2016 rule. The EPA did not conduct a quantitative assessment of the
distributional impacts of the final Policy Review, but we provide a qualitative discussion
of the distributional aspects of the cost reductions and the forgone health benefits.
•	Small Entity Impacts Analysis: The EPA expects this final deregulatory action to
reduce the small entity impacts estimated in the RIA for the 2016 NSPS OOOOa. We
therefore find that this final action will relieve regulatory burden for small entities
affected by this final action and thus will not have a Significant Impact on a Substantial
Number of Small Entities (SISNOSE).
12 There may also 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 control costs. In the event that investment in
environmental compliance displaces other investment in productive capital, the difference between the rate of
return on the investment displaced by the mandatory environmental investment is a measure of the opportunity
cost of the environmental requirement. To the extent that such opportunity costs of capital are not accounted for
in the estimated compliance cost reductions, the cost reductions may be underestimated.
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• Employment Impacts Analysis: The EPA expects reductions in labor associated with
compliance-related activities due to this action. The EPA estimated the labor impacts due
to the forgone installation, operation, and maintenance of control equipment and control
activities, as well as the reductions labor associated with reduced reporting and
recordkeeping requirements. The EPA estimated one-time and continual, annual labor
requirements by estimating hours of labor required for compliance and converting this to
full-time equivalents (FTE) by dividing by 2,080 (40 hours per week multiplied by 52
weeks). The reduction in one-time labor needed to comply with the NSPS due to this
action is estimated to be about 1.2 FTE in 2021 and 2.5 FTE in 2030. The reduction in
annual labor needed to comply with the NSPS due to this action is estimated at about 29
FTE in 2021 and 65 FTE in 2030. The EPA notes that this type of FTE-estimate cannot
be used to identify the specific number of employees involved or whether new jobs are
created for employees who potentially lose their jobs, versus displacing jobs from other
sectors of the economy.
2.1.4 Organization of the Policy Review RIA
Section 2.2 describes the estimated compliance cost reductions and forgone emissions reductions
from the Policy Review, including the PV of the projected cost reductions over the 2021 to 2030
period and the associated EAV. Section 2.3 describes the projected forgone benefits resulting
from this rule, including the PV and EAV over the 2021 to 2030 period. Section 2.4 describes the
economic impacts expected from this action. Section 2.5 compares the projected forgone benefits
and compliance cost reductions of this action, as well as a summary of the net benefits.
2.2 Projected Compliance Cost Reductions and Forgone Emissions Reductions
2.2.1 Pollution Controls and Emissions Points Assessed in this RIA
This section provides a basic description of the emissions sources and controls affected by the
final Policy Review.
Fugitive Emissions Requirements: Fugitive emissions occur when connection points are not
fitted properly or when seals and gaskets start to deteriorate. Pressure, changes in pressure, or
mechanical stresses can also cause components or equipment to leak. Potential sources of
fugitive emissions include valves, connectors, pressure relief devices, open-ended lines, flanges,
closed vent systems, and thief hatches or other openings on a controlled storage vessel. These
fugitive emissions do not include devices that vent as part of normal operations.
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The projected cost and emission impacts assume implementation of a leak monitoring program
based on the use of optical gas imaging (OGI) leak detection combined with leak correction. The
monitoring and repair frequency under the baseline is quarterly for transmission and storage
compressor stations.13 This chapter presents estimates of the impacts of removing the fugitive
emission requirements for compressor stations in the transmission and storage segment.
Pneumatic Controllers: Pneumatic controllers are automated instruments used for maintaining
process conditions such as liquid level, pressure, pressure differential, and temperature. In many
situations across all segments of the oil and natural gas industry, pneumatic controllers make use
of the available high-pressure natural gas to operate or control a valve. In these "gas-driven"
pneumatic controllers, natural gas may be released with every valve movement and/or
continuously from the valve control pilot. Not all pneumatic controllers are gas-driven. These
"non-gas-driven" pneumatic controllers use sources of power other than pressurized natural gas.
Examples include solar, electric, and instrument air. At oil and gas locations with electrical
service, non-gas-driven controllers are typically used. Continuous bleed pneumatic controllers
can be classified into two types based on their emissions rates: (1) high-bleed controllers and (2)
low-bleed controllers. This chapter presents estimates of the impact of not installing low-bleed
instead of high-bleed controllers to comply with the bleed limit requirement established in the
2016 NSPS for the transmission and storage segment.
Reciprocating and Centrifugal Compressors: Compressors are mechanical devices that
increase the pressure of natural gas and allow the natural gas to be transported from the
production site, through the supply chain, and to the consumer. The types of compressors that are
used by the oil and gas industry as prime movers are reciprocating and centrifugal compressors.
Centrifugal compressors use either wet or dry seals.
Emissions from compressors occur when natural gas leaks around moving parts in the
compressor. In a reciprocating compressor, emissions occur when natural gas leaks around the
piston rod when pressurized natural gas is in the cylinder. Over time, during operation of the
compressor, the rod packing system becomes worn and needs to be replaced to prevent excessive
13 Monitoring frequency for compressor stations on the Alaska North Slope is annual, however, we do not estimate
any compressor stations on the Alaska North Slope.
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leaking from the compression cylinder. This RIA estimates the impact of removing the
requirements to replace the rod packing approximately either every 3 years (36 months) or
26,000 hours in reciprocating compressors in the transmission and storage segment. As in the
2016 NSPS TSD, we assume compliance with the latter, which suggests replacement every 3.8
years for transmission sources and 4.4 years for storage sources based on operating data.
Emissions from centrifugal compressors depend on the type of seal used: either "wet," which use
oil circulated at high pressure, or "dry," which use a thin gap of high-pressure gas. The use of
dry gas seals substantially reduces emissions. In addition, their use significantly reduces
operating costs and enhances compressor efficiency. The EPA evaluated using a mechanical dry
seal system to limit or reduce the emissions from the rotating shaft of a centrifugal compressor.
For centrifugal compressors equipped with wet seals, a flare was evaluated as an option for
reducing emissions from centrifugal compressors. However, a review of 2016 NSPS OOOOa
compliance reports submitted in 2018 from sources in several EPA Regions (3, 6, 8, 9, and 10)
with the greatest oil and natural gas activity indicates that there are no affected centrifugal
compressors in the transmission and storage segment.14 As a result, we project there would be no
affected centrifugal compressors in the future absent this rule, meaning there are no regulatory
impacts associated with deregulating centrifugal compressors.
Storage vessels: Crude oil, condensate, and produced water are typically stored in fixed-roof
storage vessels. Some vessels used for storing produced water may be open-top tanks. These
vessels, which are operated at or near atmospheric pressure conditions, are typically used in tank
batteries. A tank battery refers to the collection of process equipment used to separate, treat, and
store crude oil, condensate, natural gas, and produced water. The extracted products from
production wells enter the tank battery through the production header, which may collect product
from many wells. Emissions from storage vessels are a result of working, breathing, and flash
losses. Working losses occur due to the emptying and filling of storage tanks. Breathing losses
are due to the release of gas associated with daily temperature fluctuations and other equilibrium
14 For more information on the EPA's review of the oil and natural gas NSPS compliance reports, see the docketed
memorandum titled: U.S. EPA. 2020. Oil and Natural Gas Sector: Emission Standards for New, Reconstructed,
and Modified Sources Background Technical Support Document for the Final Reconsideration of the New
Source Performance Standards, 40 CFR Part 60, subpart OOOOa. Detailed reports are also available at:
https://www.foiaonline.gov/foiaonline/action/public/submissionDetails?trackingNumber=EPA-HQ-2018-
001886&type=request. Accessed April 26, 2020.
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effects. Flash losses occur when a liquid with entrained gases is transferred from a vessel with
higher pressure to a vessel with lower pressure, thus allowing entrained gases or a portion of the
liquid to vaporize or flash. In the oil and natural gas production segment, flashing losses occur
when live crude oils or condensates flow into a storage tank from a processing vessel operated
under higher pressure. Typically, the larger the pressure drop, the greater the flashing emissions
in the storage stage. Two ways of control tanks with significant emissions are to install a vapor
recovery unit (VRU) and recover all the vapors from the tanks, or to route the emissions from the
tanks to a control device. However, a review of 2016 NSPS OOOOa compliance reports
submitted in 2018 from sources in the EPA Regions (3, 6, 8, 9, and 10) with the greatest oil and
natural gas activity indicates that there were no storage vessels emitting more than 6 tons per
year of VOC in the transmission and storage segment,15 and therefore we presume there are no
regulatory impacts associated with deregulating sources of this type.
2.2.2 Compliance Cost Analysis
There are two main steps in the compliance cost analysis. First, the EPA developed a
representative or model plant for each affected emission source, point, and control option.16 The
characteristics of the model plant include typical equipment, operating characteristics, and
representative factors including baseline emissions and the costs, emissions reductions, and
product recovery resulting from each control option. This source-level cost and emission
information for the requirements affected by this action can be found in a docketed technical
memorandum associated with this action.17 Second, the number of incrementally affected
facilities for each type of equipment or facility are estimated. Changes in national-level
emissions and cost estimates are calculated by multiplying the modeled source-level estimates
from the first step by the number of affected facilities in each projection year from the second
step. In addition to emissions reductions, some control options result in natural gas recovery,
which can then be combusted in production or sold. The estimates of national cost reductions
include the value of the forgone product recovery where applicable.
15	Ibid.
16	See Section 2 of the TSD accompanying this final action for more detail on how model plants were developed.
17	U.S. EPA. 2020. Memorandum: Control Cost and Emission Changes under the Final Amendments to 40 CFR Part
60, subpart OOOOa Under Executive Order 13783.
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In this section, we present the costs and emissions impacts of the Policy Review from 2021
through 2030, under the assumption that 2021 is the first full year any changes from this action
will be in effect. In addition, we provide detailed analysis for 2021 and 2030, which allows the
reader to draw comparisons between the first year after the promulgation of the Policy Review
and nine years after the impacts have accumulated.18 While it would be desirable to analyze
impacts beyond 2030, the EPA has chosen not to, largely because of the limited information
available to model long-term changes in practices and equipment use in the oil and natural gas
industry. For example, the EPA has limited information on how practices, equipment, and
emissions at new facilities change as they age or shut down. The current analysis assumes that
newly established facilities remain in operation for the entire analysis period, which would be
less realistic in a longer-term analysis. In addition, in a dynamic industry like oil and natural gas,
technological progress is likely to change control methods to a greater extent over a longer time
horizon, creating more uncertainty about impacts of the NSPS. For example, the current analysis
does not include potential fugitive emissions controls employing remote sensing technologies
currently under development.
2.2.3 Projection of Affected Facilities
To project the number of NSPS-affected facilities in transmission and storage, we first updated
the number of NSPS-affected facilities for this analysis using average year-over-year increases in
facility counts from the GHGI.19 We assumed that this average number of new affected sources
18	Any comparison of the 2016 NSPS RIA results to this analysis should be done with caution. The baseline of
affected sources has been updated in this analysis, the years of analysis are different, and results in this RIA are
presented in 2016 dollars, while the 2016 NSPS RIA presents results in 2012 dollars.
19	More detailed description of the calculations on new sources are provided in Appendix A. We applied the year-
by-year rate of change derived from AE02020 oil and natural gas drilling projections to the estimated number of
wells in 2014 from Drillinglnfo, regardless of well type, to project the estimated number of new well sites through
2030.. In addition to well sites, the fugitive emissions requirements apply to gathering and boosting stations,
transmission compressor stations, and storage compressor stations. The GHGI is used to estimate the count of newly
affected compressor stations in each year. The GHGI uses a variety of data sources and studies to estimate
equipment counts and emissions. Many equipment counts are based on the data reported under the GHGRP, scaled
up to reflect the total population including both GHGRP-reporting and non-reporting oil and natural gas facilities.
We estimated the number of new compressor stations, by type, by averaging the increases in the year-to-year
changes in total national counts of equipment over the 10-year period from 2004 through 2014. Year-to-year
increases were assumed to represent newly constructed facilities. Decreases in total counts were represented as zeros
for that year, and average together with the annual increases. This approach results in the same number of new
compressor stations in each projected year, regardless of increases or decreases in AEO projected drilling or
production. The average year-to-year increase in compressor station counts are: 212 for gathering and boosting
stations, 36 for transmission compressor stations, and 2 for storage compressor stations.
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is constant from 2021 through 2030. While new source counts are likely to vary across years, we
use this assumption as our best approximation of the average number of new sources in each
year. See Appendix A for details on activity count projections.
Over time, facilities are constructed 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 NSPS
accumulates.20 This analysis assumes that all projected new sources from 2015 through 2029 are
still in operation in 2030. These sources include fugitive emissions sources at compressor
stations, pneumatic controllers, and centrifugal and reciprocating compressors.21
Table 2-3 shows the projected number of NSPS-affected sources in each year. The estimates for
affected sources are based upon projections of new sources alone, and do not include
replacement or modification of existing sources. While some of these sources are unlikely to be
modified, the impact estimates may be underestimated due to the focus on new sources. For
compressor stations and reciprocating compressors, newly constructed affected facilities are
estimated based on averaging year-to-year changes in activity data in the GHGI between 2004
and 2014. The approach averages the number of newly constructed units in all years. In years
when the total count of equipment decreased, there were assumed to be no new units. For
pneumatic controllers, we use the same averaging technique applied to 2011 to 2014 GHGI data,
since the Inventory did not disaggregate pneumatic controllers into high and low bleed prior to
2011.22 We assume there are no new wet seal centrifugal compressors or affected storage vessels
based on the assessment of the recent NSPS oil and natural gas compliance reports.23
20	This RIA provides more detailed information than previous oil and natural gas NSPS RIA analyses by including
year-by-year results over the 2021 to 2030 analysis period.
21	Due to data limitations, we do not quantify any emissions or cost changes associated with new compressor
stations on the Alaska North Slope.
22	Based on comment received on the proposal of this rule, we treat the installation of low-bleed pneumatic
controllers from 2015 to 2020 as irreversible, meaning that they are not assumed to be replaced with high-bleed
controllers as a result of this action until the end of their assumed equipment lifetime.
23	For more information on the EPA's review of the oil and natural gas NSPS compliance reports, see the docketed
memorandum titled: U.S. EPA. 2020. Oil and Natural Gas Sector: Emission Standards for New, Reconstructed,
and Modified Sources Background Technical Support Document for the Final Reconsideration of the New
Source Performance Standards, 40 CFR Part 60, subpart OOOOa. Detailed reports are also available at:
https://www.foiaonline.gov/foiaonline/action/public/submissionDetails?trackingNumber=EPA-HQ-2018-
001886&type=request. Accessed April 26, 2020.
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Table 2-3
Projected NSPS-Affected Sources in Transmission and Storage, 2021-203024
Year
Compressor
Stations
Reciprocating
Compressors
Centrifugal
Compressors
Pneumatic
Controllers1
Storage
Vessels
Total
2021
270
530
0
310
0
1,100
2022
300
610
0
620
0
1,500
2023
340
680
0
920
0
2,000
2024
380
760
0
1,200
0
2,400
2025
420
840
0
1,500
0
2,800
2026
460
910
0
1,800
0
3,200
2027
490
990
0
2,200
0
3,600
2028
530
1,100
0
2,500
0
4,100
2029
570
1,100
0
2,800
0
4,500
2030
610
1,200
0
3,400
0
5,200
Note: Estimates may not sum due to independent rounding
1 Counts in this column do not include pneumatic controllers installed between 2015 and 2020, which are affected
sources under the NSPS but are not expected to change activities as a result of this action until the end of their
assumed equipment lifetimes.
There have been multiple updates to the GHGI, and the data the EPA used to estimate the
number of affected sources in the 2016 NSPS OOOOa was revised where appropriate. We
updated the time period used to estimate the number of affected sources. The 2016 NSPS RIA
used the ten-year period leading up to 2012, whereas this proposed action estimates the number
of affected sources in the ten-year period leading up to 2014. The projected number of affected
sources in the transmission and storage segment is sensitive to the ten-year period used for
averaging. For example, the 2016 NSPS RIA estimated four new transmission compressor
stations a year, and this analysis estimates 36 new transmission compressor stations per year.
Though the difference in the count of affected sources as estimated for the 2016 NSPS RIA and
the Policy Review is large, when compared to the total number of transmission compressor
24 See Appendix A for more discussion. Nationwide impacts of certifications for closed vent system design and
technical infeasibility of routing pneumatic pumps to an existing control device, rod-packing replacements at
reciprocating compressors, route-to-control measures for wet-seal centrifugal compressors, and use of low-bleed
pneumatic controllers were calculated by estimating the count of affected facilities installed in a typical year and
then using that typical year estimate to estimate the number of new affected facilities for each of the years in the
study period, 2021 through 2030. The basis for the counts of affected facilities that would require closed vent
system and technical infeasibility certifications in a typical year was information from 2016 NSPS OOOOa
compliance information for 2017. These represent the number of new affected facilities in a "typical year." The
GHGI was used to generate counts of reciprocating compressors and pneumatic controllers in transmission and
storage only. The 2017 compliance report's nationwide number of new affected facilities reported are: 663
pneumatic pumps, 180 reciprocating compressors, 0 centrifugal compressors, 697 storage vessels and 308
pneumatic controllers
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stations nationally in 2014 (about 1,800), both are small: 0.2 percent and 2.0 percent,
respectively.
In addition, since the 2016 NSPS RIA (which used 2015 GHGI data), the EPA updated the
GHGI methodology used to develop station counts. This update had only a small impact on total
national counts in the GHGI.25 The update also resulted in minor changes in year-to-year trends,
which have impacted the affected source projection. National estimates of other sources (e.g.,
compressors and pneumatic controllers) in the transmission and storage segment rely on station
counts as an input and are therefore impacted by this change as well. As annual national counts
of transmission and storage stations are not directly available from any national-level data
source, the EPA applies a methodology to estimate the total national counts of transmission and
storage stations. This method was updated between the 2015 GHGI and the 2018 GHGI. For the
2016 NSPS, (using the previous GHGI methodology) transmission station counts were estimated
by applying a factor of stations per mile of transmission pipeline to the total national
transmission pipeline mileage.26 Storage station counts were also developed using the previous
GHGI methodology (applying a factor of stations per unit of gas consumption to total national
gas consumption). In this RIA, transmission station counts are developed using updated data
from the 2018 GHGI. In the 2018 GHGI, transmission stations are estimated based on scaled-up
Greenhouse Gas Reporting Program (GHGRP) data. Storage stations are estimated by applying a
factor to total national storage fields. These improvements to the methods were developed with
stakeholder input.
2.2.4 Forgone Emissions Reductions
Table 2-4 summarizes the forgone emissions reductions associated with the Policy Review. The
forgone emissions reductions are estimated by multiplying the source-level forgone emissions
25	For example, the 2018 GHG Inventory estimate of station counts in 2013 is 5 percent lower for transmission
stations and 12 percent lower for storage stations.
26	The EPA used the GHGRP subpart W station count scaled by a factor of 3.52 to adjust for GHGRP coverage. In
2016 for example, 529 transmission stations reported to GHGRP, and the national GHG Inventory calculated
1,862 transmission stations as the national total.
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reductions associated with each applicable control and facility type by the number of affected
sources of that facility type.27
Table 2-4 Projected Forgone Emissions Reductions from Policy Review, 2021-2030
Emission Changes
Year
Methane
(short tons)
VOC
(short tons)
HAP
(short tons)
Methane
(metric tons CO2
Eq.)
2021
22,000
610
18
500,000
2022
26,000
720
21
590,000
2023
30,000
830
25
680,000
2024
34,000
940
28
770,000
2025
38,000
1,000
31
860,000
2026
42,000
1,200
34
940,000
2027
46,000
1,300
37
1,000,000
2028
49,000
1,400
41
1,100,000
2029
53,000
1,500
44
1,200,000
2030
58,000
1,600
48
1,300,000
Total
400,000
11,000
330
9,000,000
Note: Estimates may not sum due to independent rounding.
2.2.5 Forgone Product Recovery
The projected compliance cost reductions presented below include the forgone revenue from the
reductions in natural gas recovery projected under the Policy Review. Requirements for
compressor stations, reciprocating compressors, and pneumatic controllers are assumed to
increase the capture of methane and VOC emissions that would otherwise be vented to the
atmosphere, and we assume that a large proportion of the averted methane emissions can be
directed into natural gas production streams and sold.
Table 2-5 summarizes the decrease in natural gas recovery and the associated forgone revenue.
The AE02020 projects Henry Hub natural gas prices rising from $2.49/MMBtu in 2021 to
$3.29/MMBtu in 2030 in 2019 dollars.28 To be consistent with other financial estimates in the
27	For more information on the EPA's review of the oil and natural gas NSPS compliance reports, see the docketed
memorandum titled: U.S. EPA. 2020. Oil and Natural Gas Sector: Emission Standards for New, Reconstructed,
and Modified Sources Background Technical Support Document for the Final Reconsideration of the New
Source Performance Standards, 40 CFR Part 60, subpart OOOOa. Detailed reports are also available at:
https://www.foiaonline.gov/foiaonline/action/public/submissionDetails?trackingNumber=EPA-HQ-2018-
001886&type=request. Accessed April 26, 2020.
28	Available at: http://www.eia.gov/forecasts/aeo/tables_ref.cfm. Accessed April 26, 2020
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RIA, we adjust the projected prices in AE02020 from 2019 dollars to 2016 dollars using the
GDP-Implicit Price Deflator. We also adjust prices for the wellhead using an EIA study that
indicated that the Henry Hub price is, on average, about 11 percent higher than the wellhead
price,29 and therefore we use a conversion factor of 1.036 MMBtu equals 1 Mcf. Incorporating
these adjustments, wellhead natural gas prices are assumed to rise from $2.20/Mcf in 2021 to
$2.89/Mcf in 2030.
Table 2-5 Projected Decrease in Natural Gas Recovery for Policy Review, 2021-2030
Year
Decrease in Gas Recovery (Tcf)
Forgone Revenue
(millions 2016$)
2021
1.3
$2.5
2022
1.5
$3.0
2023
1.7
$3.4
2024
2.0
$4.0
2025
2.2
$4.9
2026
2.4
$5.8
2027
2.6
$6.7
2028
2.9
$7.5
2029
3.1
$8.1
2030
3.4
$8.7
Operators in the transmission and storage segment of the industry do not typically own the
natural gas they transport; rather, they receive payment for the transportation service they
provide. From a social perspective, however, the increased financial returns from natural gas
recovery accrues to entities somewhere along the natural gas 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 natural gas recovery. The change in
economic surplus resulting from natural gas recovery is likely to be spread across different
market participants. Therefore, the simplest and most transparent option for allocating these
revenues would be to keep the compliance costs and revenues within a given source category and
not make assumptions regarding the allocation of costs and revenues across agents.30
29	See:
https://www.researchgate.net/publication/265155970_US_Natural_Gas_Markets_Relationship_Between_Henry
Hub_Spot_Prices_and_US_Wellhead_Prices. Accessed 04/26/2020.
30	As a sensitivity, we calculated forgone natural gas revenues using the Henry Hub price instead of the estimated
wellhead price, as the former may better reflect the value of natural gas in the transmission and storage segment.
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2.2.6 Compliance Cost Reductions
Table 2-6 summarizes the compliance cost reductions and forgone revenue from product
recovery for the evaluated emissions sources and points. Total cost reductions consist of capital
cost reductions; annual operating and maintenance cost reductions, including reporting and
recordkeeping costs;31 and forgone revenue from product recovery. Capital cost reductions
include the capital cost reductions from removing the requirements on newly affected controllers
and compressors and the planning cost reductions from removing requirements for compressor
stations to create survey monitoring plans for the fugitive emissions, as well as the cost
reductions for sources that would have had to renew survey monitoring plans or purchase new
capital equipment at the end of its useful life. The annual operating and maintenance cost
reductions are due to the fugitives monitoring requirement and other reporting and recordkeeping
requirements.
Under this alternative fuel price assumption, the forgone revenue associated with unrecovered natural gas is $3.4
million in 2021 and $10.4 million in 2030.
31 Reporting and recordkeeping cost reductions not due to changes in the fugitive emissions monitoring requirements
were drawn from the information collection request (ICR) that have been submitted to the Office of Management
and Budget (OMB) under the Paperwork Reduction Act (see preamble for more detail). These reporting and
recordkeeping cost reductions are estimated to be about $210,000 in 2021 and increasing to about $330,000 in
2030. Reporting and recordkeeping cost reductions for fugitive emissions monitoring requirements are captured
directly as operating and maintenance cost reductions associated with that program. Recordkeeping and
recordkeeping cost reductions are estimated for the Policy Review for all affected facilities regardless of whether
they are in states with regulatory requirements similar to the final 2016 NSPS OOOOa.
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Table 2-6 Estimated Cost Reductions under the Policy Review, 2021-2030 (millions
2016$)	
Compliance Cost Reductions
Year
Capital Cost
Reductions1
Operating and
Maintenance
Cost Reductions
Annualized
Cost Reductions
(w/o Forgone
Revenue)2
Forgone
Revenue from
Product
Recovery
Annualized Cost
Reductions (with
Forgone
Revenue)
2021
$1.9
$4.2
$6.2
$2.5
$3.7
2022
$1.9
$4.8
$7.1
$3.0
$4.1
2023
$3.2
$5.4
$8.0
$3.4
$4.5
2024
$3.2
$5.9
$8.8
$4.0
$4.8
2025
$3.2
$6.5
$10
$4.9
$4.8
2026
$3.2
$7.1
$11
$5.8
$4.7
2027
$3.6
$7.7
$11
$6.7
$4.7
2028
$3.6
$8.3
$12
$7.5
$4.9
2029
$3.6
$8.9
$13
$8.1
$5.1
2030
$3.7
$9.5
$14
$8.7
$5.4
Note: Sums may not total due to independent rounding.
1	The capital cost reductions include the planning cost reductions for newly affected sources for fugitive emissions
monitoring and capital cost reductions for newly affected controllers and compressors, as well as the cost reductions
for sources that would renew survey monitoring plans and purchase new capital at the end of its useful life.
2	These cost reductions include the capital cost reductions annualized over the requisite equipment lifetimes at an
interest rate of 7 percent and the annual operating and maintenance cost reductions for every year, which include the
cost reductions from recordkeeping and reporting.
The cost of designing, or redesigning, a fugitive emissions monitoring program occurs every
eight years to comply with the 2016 NSPS OOOOa. Pneumatic controllers are assumed to have a
lifetime of ten years. Rod packing replacement is assumed to happen about every 3.8 years in the
transmission segment and every 4.4 years in the storage segment.32 The lifetime of the sources
affected by this action are unchanged from the assumptions used for the 2016 NSPS OOOOa.
The reduction in capital costs in each year outlined in Table 2-6 includes the estimated reduction
in costs for newly affected sources in that year, plus the reduction in costs for sources affected
previously that have reached the end of their assumed economic lifetime.
The capital and planning cost reductions for reciprocating compressors, pneumatic controllers,
and fugitive emissions monitoring program design are annualized over their requisite expected
lifetimes at an interest rate of 7 percent and are added to the annual operating and maintenance
cost reductions of the requirements to get the annualized cost reductions in each year. The
32 For the purposes of assigning unannualized capital costs of subsequent replacements to years, we round the
lifetimes for rod packing in both transmission and storage to four years.
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forgone value of product recovery is then subtracted to get the total annualized cost reductions in
each year.
Table 2-7 illustrates the sensitivity of the estimated cost reductions to a given interest rate. We
present cost reductions using interest rates of 7 and 3 percent. The choice of interest rate has a
very small effect on nationwide annualized cost reductions. The interest rate generally affects
estimates of annualized costs for controls with high planning or capital costs relative to annual
costs. In this analysis, the planning and capital cost reductions are small relative to the annual
operating and maintenance cost reductions, so the interest rate has little impact on total
annualized cost reductions for these sources.
Table 2-7 Estimated Cost Reductions for the Policy Review, 2021-2030 (millions 2016$)
7 percent
3 percent
Year
Annualized
Cost
Reductions (w/o
Forgone
Revenue)
Forgone
Revenue from
Product
Recovery
Annualized Cost
Reductions
(with Forgone
Revenue)
Annualized
Cost
Reductions
(w/o Forgone
Revenue)
Forgone
Revenue
from
Product
Recovery
Annualized
Cost Reductions
(with Forgone
Revenue)
2021
$6.2
$2.5
$3.7
$6.0
$2.5
$3.4
2022
$7.1
$3.0
$4.1
$6.8
$3.0
$3.9
2023
$8.0
$3.4
$4.5
$7.6
$3.4
$4.2
2024
$8.8
$4.0
$4.8
$8.5
$4.0
$4.5
2025
$10
$4.9
$4.8
$9.3
$4.9
$4.4
2026
$11
$5.8
$4.7
$10
$5.8
$4.3
2027
$11
$6.7
$4.7
$11
$6.7
$4.3
2028
$12
$7.5
$4.9
$12
$7.5
$4.4
2029
$13
$8.1
$5.1
$13
$8.1
$4.6
2030
$14
$8.7
$5.4
$14
$8.7
$4.9
Note: Estimates may not sum due to independent rounding.
2.2.7 Detailed Impacts Tables
The following tables show the full details of the cost reductions and forgone emissions
reductions by emissions source in 2021 and 2030.
Two of the affected source types, reciprocating compressors and pneumatic controllers, have
negative cost reductions, meaning that the potential capital and annual cost reductions from
deregulating the transmission and storage segment may be outweighed by the forgone revenue
from product recovery. This observation may typically support an assumption that operators
would continue to perform the emissions abatement activity, regardless of whether a requirement
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is in place, because it is in their private self-interest. However, as discussed in the 2016 RIA,
operators in the transmission and storage segment of the industry do not typically own the
natural gas they transport; rather, the operators receive payment for the transportation service
they provide. As a result, financial incentives to reduce emissions may be minimal because
operators are not able to recoup the financial value of captured natural gas that may otherwise be
emitted. Alternatively, there may also 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 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 cost reductions presented above may be underestimated.
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Table 2-8
Affected Sources, Forgone Emissions Reductions, and Compliance Cost Reductions for the Policy Review, 2021
Forgone Emissions Reductions	Compliance Cost Reductions (millions $2016)
Total
Annualized
Source/Emissions Points in
Transmission and Storage
Projected
No. of
Affected
Sources
Methane
(short
tons)
voc
(short
tons)
HAP
(short
tons)
Methane
(metric
tons CO2
Eq.)
Annualized
Capital Cost
Reductions
Operating
and
Maintenance
Reductions
Forgone
Product
Recovery
Cost
Reductions
with Forgone
Revenue
Fugitive Emissions - Compressor Stations
270
9,700
270
8.0
220,000
$1.00
$4.0
$1.1
$3.9
Reciprocating Compressors
530
12,000
320
9.5
260,000
$0.99
$0
$1.3
-$0.32
Centrifugal Compressors
0
0
0
0
0
$0
$0
$0
$0
Pneumatic Controllers
310
860
24
0.7
19,000
$0,008
$0
$0.10
-$0.09
Reporting and Recordkeeping1
N/A
0
0
0
0
$0
$0.21
$0
$0.21
TOTAL
1,100
22,000
610
18
500,000
$2.0
$4.2
$2.5
$3.7
Note: Estimates may not sum due to independent rounding.
1 Applies to reporting and recordkeeping for requirements other than the fugitive emissions monitoring requirements.
Table 2-9 Affected Sources, Forgone Emissions Reductions, and Compliance Cost Reductions for the Policy Review, 2030
Forgone Emissions Reductions	Compliance Cost Reductions (millions $2016)
Total
Annualized
Source/Emissions Points in
Transmission and Storage
Projected
No. of
Affected
Sources
Methane
(short
tons)
VOC
(short
tons)
HAP
(short
tons)
Methane
(metric
tons CO2
Eq.)
Annualized
Capital Cost
Reductions
Operating
and
Maintenance
Reductions
Forgone
Product
Recovery
Cost
Reductions
with Forgone
Revenue
Fugitive Emissions - Compressor Stations
610
22,000
620
18
500,000
$2.3
$9.1
$3.3
$8.1
Reciprocating Compressors
1,200
26,000
730
22
600,000
$2.3
$0
$3.9
-$1.7
Centrifugal Compressors
0
0
0
0
0
$0
$0
$0
$0
Pneumatic Controllers
3,400
9,400
260
8
210,000
$0.09
$0
$1.4
-$1.3
Reporting and Recordkeeping1
N/A
0
0
0
0
$0
$0.33
$0
$0.33
TOTAL
5,200
58,000
1,600
48
1,300,000
$4.7
$9.1
$8.7
$5.4
Note: Estimates may not sum due to independent rounding.
1 Applies to reporting and recordkeeping for requirements other than the fugitive emissions monitoring requirements.
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2.2.8 Present Value and Equivalent Annualized Value of Cost Reductions
This section presents the compliance cost reductions of the Policy Review in a PV framework.
The stream of the estimated cost reductions for each year from 2021 through 2030 is discounted
back to 2020 using 7 and 3 percent discount rates and summed to get the PV of the cost
reductions. The PV is then used to estimate the EAV of the cost reductions. The EAV is the
single annual value which, if summed in PV terms across years in the analytical time frame,
equals the PV of the original (i.e., likely time-varying) stream of cost reductions. In other words,
the EAV takes the potentially "lumpy" stream of cost reductions and converts them into a single
value that, when discounted and added together over each period in the analysis time frame,
equals the original stream of values in PV terms.
Table 2-10 shows the undiscounted stream of cost reductions for each year from 2021 through
2030 due to the Policy Review. Capital cost reductions are the projected capital and planning
costs which will no longer be incurred. Total cost reductions are the sum of the capital cost
reductions, annual operating cost reductions, and reporting and recordkeeping cost reductions.
The forgone revenue from the decrease in product recovery is estimated using the AE02020
natural gas price projections, as described earlier. Total cost reductions with forgone revenue
equals the total cost reductions minus the forgone revenue. Over time, with the addition of new
affected sources in each year, the capital cost reductions, annual operating cost reductions,
reporting and recordkeeping cost reductions, and forgone revenue increase.
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Table 2-10 Undiscounted Projected Compliance Cost Reductions for the Policy Review,
2021-2030 (millions 2016$)		
Year
Capital Cost
Reductions
Annual
Operating Cost
Reductions
Total Cost
Reductions (w/o
Forgone
Revenue)
Forgone
Revenue from
Product
Recovery
Total Cost
Reductions
(with Forgone
Revenue)
2021
$1.9
$4.0
$6.1
$2.5
$3.5
2022
$1.9
$4.6
$6.6
$3.0
$3.7
2023
$3.2
$5.1
$8.5
$3.4
$5.1
2024
$3.2
$5.7
$9.1
$4.0
$5.1
2025
$3.2
$6.3
$10
$4.9
$4.8
2026
$3.2
$6.8
$10
$5.8
$4.5
2027
$3.6
$7.4
$11
$6.7
$4.6
2028
$3.6
$8.0
$12
$7.5
$4.5
2029
$3.6
$8.5
$13
$8.1
$4.4
2030
$3.7
$9.1
$13
$8.7
$4.5
Note: Estimates may not sum due to independent rounding.
Table 2-11 shows the discounted stream of cost reductions discounted to 2020 using a 7 percent
discount rate. The PV of total compliance cost reductions is $31 million, with an EAV of $4.1
million per year. The PV of the stream of cost reductions discounted to 2020 using a 3 percent
discount rate is $38 million, with an EAV of $4.3 million per year.
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Table 2-11 Discounted Cost Reductions for the Policy Review using 7 and 3 Percent
Discount Rates (millions 2016S)1	
7 Percent
3 Percent
Year
Total Annual
Cost
Reductions
(w/o Forgone
Revenue)
Forgone
Revenue
from Product
Recovery
Total Cost
Reductions
(with Forgone
Revenue)
Total Annual
Cost
Reductions
(w/o Forgone
Revenue)
Forgone
Revenue
from Product
Recovery
Total Cost
Reductions
(with Forgone
Revenue)
2021
$5.7
$2.4
$3.3
$5.9
$2.4
$3.4
2022
$5.8
$2.6
$3.2
$6.2
$2.8
$3.5
2023
$7.0
$2.8
$4.2
$7.8
$3.1
$4.7
2024
$7.0
$3.1
$3.9
$8.0
$3.6
$4.5
2025
$6.9
$3.5
$3.4
$8.3
$4.2
$4.2
2026
$6.9
$3.9
$3.0
$8.5
$4.9
$3.7
2027
$7.1
$4.2
$2.9
$9.1
$5.5
$3.8
2028
$6.9
$4.3
$2.6
$9.3
$5.9
$3.5
2029
$6.8
$4.4
$2.4
$9.4
$6.2
$3.4
2030
$6.7
$4.4
$2.3
$10
$6.5
$3.3
PV
$67
$36
$31
$83
$45
$38
EAV
$8.9
$4.7
$4.1
$9.4
$5.1
$4.3
Note: Estimates may not sum due to independent rounding.
1 Cost reductions and forgone revenue in each year are discounted to 2020.
The Policy Review is considered a deregulatory action under E.O. 13771, Reducing Regulation
and Controlling Regulatory Costs. The PV of the projected cost reductions from the Policy
Review calculated in accordance with E.O. 13771 accounting standards are $45 million over an
infinite time horizon (in 2016$, discounted to 2016 at 7 percent). The EAV of the cost reductions
over an infinite time horizon are $3.2 million per year (in 2016$, discounted to 2016 at 7
percent).
2.3 Forgone Benefits
2.3.1 Introduction
For the oil and natural gas sector NSPS promulgated in 2012 and 2016, the EPA projected
climate and ozone benefits from methane reductions, ozone and fine particulate matter (PM2.5)
health benefits from VOC reductions, and health benefits from ancillary HAP reductions. These
benefits were expected to occur because the control techniques to meet the standards
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simultaneously reduce methane, VOC, and HAP emissions.33 As in the 2016 NSPS RIA,
methane is the only pollutant with monetized impacts in this RIA. The Policy Review is
projected to forgo emissions reductions relative to the baseline. The total forgone emissions
reductions over 2021 to 2030 is estimated to be about 400,000 short tons of methane, 11,000 tons
of VOC, and 330 tons of HAP. The associated increase in CO2 Eq. methane emissions is
estimated to be 9 million metric tons.
The PV of the projected forgone methane-related climate benefits are estimated to be $19 million
from 2021 to 2030 using an interim estimate of the domestic social cost of methane (SC-CH4)
and discounted at 7 percent. The associated EAV is estimated to be $2.9 million per year. Using
the interim SC-CH4 estimate based on the 3 percent rate, the PV of the forgone domestic climate
benefits is estimated to be $63 million, and the EAV is estimated to be $10 million per year.
Under the final action, the EPA expects that the forgone VOC emission reductions will worsen
air quality and adversely affect health and welfare due to the impacts on ozone, PM2.5, and HAP,
but we did not quantify these impacts at this time. This omission should not imply that these
forgone benefits do not exist, and to the extent that the EPA were to quantify the ozone and PM
impacts, it would estimate the number and value of avoided premature deaths and illnesses using
the approach detailed in the PM National Ambient Air Quality Standards (NAAQS) and Ozone
NAAQS RIAs (U.S. EPA, 2012b; U.S. EPA, 2014). This approach relies on full-form air quality
modeling. The Agency is committed to assessing ways of conducting full-form air quality
modeling for the oil and gas sector that would be suitable for use in regulatory analysis in the
context of New Source Performance Standards, including ways to address the uncertainties
regarding the scope and magnitude of VOC emissions. When quantifying the incidence and
economic value of the human health impacts of air quality changes, the Agency sometimes relies
upon alternative approaches to using full-form air quality modeling, called reduced-form
techniques, often reported as "benefit-per-ton" values that relate air pollution impacts to changes
in air pollutant precursor emissions (U.S. EPA, 2018). A small, but growing, literature
characterizes the air quality and health impacts from the oil and natural gas sector, including
33 The specific control techniques for the 2016 NSPS OOOOa were also anticipated to have minor disbenefits
resulting from secondary emissions of carbon dioxide (CO2), nitrogen oxides (NOx), PM, carbon monoxide
(CO), and total hydrocarbons (THC), and emission changes associated with the energy markets impacts. This
final action is anticipated to reduce these minor secondary emissions.
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preliminary VOC benefit-per-ton values (Fann et al., 2018; Litovitz et al., 2013; Loomis and
Haefele, 2017). The Agency feels more work needs to be done to vet the analysis and
methodologies for all potential approaches for valuing the health effects of VOC emissions
before they are used in regulatory analysis but is committed to continuing this work.
In addition, the EPA systematically compared the changes in benefits, and concentrations where
available, from its benefit-per-ton technique and other reduced-form techniques to the changes in
benefits and concentrations derived from full-form photochemical model representation of five
different stationary and mobile source emissions scenarios (IEc, 2019).34 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.35 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 RIAs.
For these reasons, we did not quantify VOC-related health impacts in this RIA. This omission
should not imply that these forgone benefits may not exist; rather, it reflects the inherent
difficulties in modeling the direct and indirect impacts of the reductions in emissions for this
industrial sector with the data currently available. Here, we qualitatively assess the forgone
health benefits associated with reducing exposure to these pollutants, as well as visibility
impairment and forgone ecosystem benefits. Table 2-12 summarizes the quantified and
unquantified forgone benefits in this analysis.
34	This analysis compared the benefits estimated using full-form photochemical air quality modeling simulations
(CMAQ and CAMx) against four reduced-form tools, including InMAP; AP2/3; EASIUR and EPA's benefit-
per-ton.
35	85 FR 23823. April 29, 2020.
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Table 2-12 Climate and Human Health Effects of Forgone Emission Reductions under
the Policy Review	
Category
Specific Effect
Effect Has
Been
Quantified
Effect Has
Been
Monetized
More
Information
Environment
Climate effects
Climate impacts from methane (CH4)
Other climate impacts (e.g., ozone, black
carbon, aerosols, other impacts)
	1
~
Section 3.3
IPCC, Ozone ISA,
PM ISA2
Human Health
Incidence of
premature mortality
from exposure to
Adult premature mortality based on cohort
study estimates and expert elicitation estimates
(age >25 or age >30)
—
—
PM ISA3
PM2.5
Infant mortality (age <1)
—
—
PM ISA3

Non-fatal heart attacks (age >18)
—
—
PM ISA3

Hospital admissions—respiratory (all ages)
—
—
PM ISA3

Hospital admissions—cardiovascular (age >20)
—
—
PM ISA3

Emergency room visits for asthma (all ages)
—
—
PM ISA3

Acute bronchitis (age 8-12)
—
—
PM ISA3

Lower respiratory symptoms (age 7-14)
—
—
PM ISA3

Upper respiratory symptoms (asthmatics age 9-
11)
—
—
PM ISA3
Incidence of morbidity
Asthma exacerbation (asthmatics age 6-18)
—
—
PM ISA3
from exposure to
PM2.5
Lost work days (age 18-65)
—
—
PM ISA3
Minor restricted-activity days (age 18-65)
—
—
PM ISA3

Chronic Bronchitis (age >26)
—
—
PM ISA3

Emergency room visits for cardiovascular
effects (all ages)
—
—
PM ISA3

Strokes and cerebrovascular disease (age 50-
79)
—
—
PM ISA3

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

Other respiratory effects (e.g., pulmonary
function, non-asthma ER visits, non-bronchitis
chronic diseases, other ages and populations)
—
—
PM ISA2

Reproductive and developmental effects (e.g.,
low birth weight, pre-term births, etc.)
—
—
PM ISA2-4

Cancer, mutagenicity, and genotoxicity effects
—
—
PM ISA2-4
Incidence of mortality
from exposure to
ozone
Premature mortality based on short-term study
estimates (all ages)
—
—
Ozone ISA3
Premature mortality based on long-term study
estimates (age 30-99)
—
—
Ozone ISA3

Hospital admissions—respiratory causes (age >
65)
—
—
Ozone ISA3
Incidence of morbidity
from exposure to
Hospital admissions—respiratory causes (age
<2)
—
—
Ozone ISA3
ozone
Emergency department visits for asthma (all
ages)
—
—
Ozone ISA3

Minor restricted-activity days (age 18-65)
—
—
Ozone ISA3
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Effect Has
Effect Has
More
Information
Category
Specific Effect
Been
Quantified
Been
Monetized

School absence days (age 5-17)
—
—
Ozone ISA3

Decreased outdoor worker productivity (age
18-65)
—
—
Ozone ISA3

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

Cardiovascular and nervous system effects
—
—
Ozone ISA2

Reproductive and developmental effects
—
—
Ozone ISA2-4
Incidence of morbidity
from exposure to HAP
Effects associated with exposure to hazardous
air pollutants such as benzene
—
—
ATSDR, IRIS2'3
Welfare
Visibility
Visibility in Class 1 areas
—
—
PM ISA3
Visibility in residential areas
—
—
PM ISA3
Effects from PM
deposition (organics)
Effects on Individual organisms and
ecosystems
—
—
PM ISA2

Visible foliar injury on vegetation
—
—
Ozone ISA3

Reduced vegetation growth and reproduction
—
—
Ozone ISA3

Yield and quality of commercial forest
products and crops
—
—
Ozone ISA3
Vegetation and
ecosystem effects
Damage to urban ornamental plants
—
—
Ozone ISA2
Carbon sequestration in terrestrial ecosystems
—
—
Ozone ISA3
from exposure to
ozone
Recreational demand associated with forest
aesthetics
—
—
Ozone ISA2

Other non-use effects
—
—
Ozone ISA2

Ecosystem functions (e.g., water cycling,
biogeochemical cycles, net primary
productivity, leaf-gas exchange, community
composition)
—
—
Ozone ISA2
1	The climate and related impacts of CO2 and methane (CH4) emissions changes, such as sea level rise, are estimated
within each integrated assessment model as part of the calculation of the domestic SC-CO2 and SC-CH4. The
resulting monetized damages, which are relevant for conducting the benefit-cost analysis, are used in this RIA to
estimate the domestic welfare effects of quantified changes in CH4 emissions.
2	We assess these benefits qualitatively because we do not have sufficient confidence in available data or methods.
3	We assess these benefits qualitatively due to data limitations for this analysis, but we have quantified them in other
analyses.
4	We assess these benefits qualitatively because current evidence is only suggestive of causality or there are other
significant concerns over the strength of the association.
2.3.2 Forgone Emissions Reductions
Oil and natural gas operations in the U.S. include a variety of emission points for methane, VOC,
and HAP, including wells, well sites, processing plants, compressor stations, storage equipment,
and transmission and distribution lines. These emission points are located throughout much of
the country, though they are concentrated in particular geographic regions. For example, wells
and processing plants are largely concentrated in the South Central, Midwest, and Southern
California regions of the U.S., whereas natural gas compressor stations are located all over the
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country. Distribution lines to customers are frequently located within areas of high population
density.
The Policy Review may result in forgone reductions in ambient PM2.5 and ozone concentrations
in areas attaining and not attaining the NAAQS. Due to the high degree of variability in the
responsiveness of ozone and PM2.5 formation to VOC emission reductions, we are unable to
determine how this rule might affect attainment status without modeling air quality changes.36
Because the NAAQS RIAs also calculate ozone and PM2.5 benefits, there are important
differences worth noting in the design and analytical objectives of each impact analysis. The
NAAQS RIAs illustrate the potential costs and benefits of attaining new nationwide air quality
standards based on an array of emission control strategies for different sources.37 By contrast, the
emission impacts of implementation rules, including the oil and natural gas NSPS, are generally
from a specific class of well-characterized sources. In general, The EPA is more confident in the
magnitude and location of the emission reductions for implementation rules rather than
illustrative NAAQS analyses. Emission changes realized under these and other promulgated
rules will ultimately be reflected in the baseline of future NAAQS analyses, which would affect
the incremental benefits and costs associated with attaining future NAAQS.
Table 2-13 shows the total forgone emissions reductions projected under the Policy Review for
the period of 2021 to 2030. The impacts of these pollutants accrue at different spatial scales.
HAP emissions increase exposure to carcinogens and other toxic pollutants primarily near the
emission source. VOC emissions are precursors to secondary formation of PM2.5 and ozone on a
broader regional scale. Climate effects associated with long-lived greenhouse gases like methane
generally do not depend on the location of the emission of the gas and have global impacts.
Methane is also a precursor to global background concentrations of ozone (Sarofim, 2015).
36	The responsiveness of ozone and PM2 5 formation is discussed in greater detail in Sections 2.3.4 and 2.3.5,
respectively.
37	NAAQS RIAs hypothesize, but do not predict, the control strategies States may choose to enact when
implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the
NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other
regulations that result in specific costs of control and emission reductions. However, some benefits and costs
estimated in this RIA may account for the same air quality improvements as estimated in an illustrative NAAQS
RIA.
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Table 2-13 Projected Total Forgone Emissions Reductions under the Policy Review,
2021-2030
Pollutant
Policy Review
Methane (short tons)
400,000
VOC (short tons)
11,000
HAP (short tons)
330
Methane (metric tons)
360,000
Methane (million metric tons CO2 Eq.)
9
Table 2-14 shows the projected forgone reductions of methane, VOC, and HAP emissions under
the Policy Review for each year from 2021 to 2030.
Table 2-14 Projected Annual Forgone Reductions of Methane, VOC, and HAP
Emissions under the Policy Review, 2021-2030	
Policy Review
Year
Methane (metric tons)
VOC (short tons)
HAP (short tons)
2021
20,000
610
18
2022
24,000
720
21
2023
27,000
830
25
2024
31,000
940
28
2025
34,000
1,000
31
2026
38,000
1,200
34
2027
41,000
1,300
37
2028
45,000
1,400
41
2029
48,000
1,500
44
2030
53,000
1,600
48
Total
360,000
11,000
330
Note: Estimates may not sum due to independent rounding.
2.3.3 Methane Climate Effects and Valuation
Methane is the principal component of natural gas. Methane is also a potent greenhouse gas
(GHG) that, once emitted into the atmosphere, absorbs terrestrial infrared radiation, which in
turn contributes to increased global warming and continuing climate change. Methane reacts in
the atmosphere to form ozone, which also impacts global temperatures. Methane, in addition to
other GHG emissions, contributes to warming of the atmosphere, which over time leads to
increased air and ocean temperatures; changes in precipitation patterns; melting and thawing of
global glaciers and ice sheets; increasingly severe weather events, such as hurricanes of greater
intensity; and sea level rise, among other impacts.
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According to the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report
(IPCC, 2013), changes in methane concentrations since 1750 contributed 0.48 W/m2 of forcing,
which is about 17 percent of all global forcing due to increases in anthropogenic GHG
concentrations, and which makes methane the second leading long-lived climate forcer after
CO2. However, after accounting for changes in other greenhouse substances such as ozone and
stratospheric water vapor due to chemical reactions of methane in the atmosphere, historical
methane emissions were estimated to have contributed to 0.97 W/m2 of forcing today, which is
about 30 percent of the contemporaneous forcing due to historical greenhouse gas emissions.
The oil and natural gas sector emits significant quantities of methane. The U.S. Inventory of
Greenhouse Gas Emissions and Sinks: 1990-2018 (published 2020) estimates 2018 methane
emissions from Petroleum and Natural Gas Systems (not including petroleum refineries,
petroleum transportation, and natural gas distribution) to be 171 million metric tons CO2 Eq. In
2018, total methane emissions from the oil and natural gas industry represented 27 percent of the
total methane emissions from all sources and account for about 3 percent of all CO2 Eq.
emissions in the U.S., with the combined petroleum and natural gas systems being the largest
contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2020).
To give a sense of the magnitude of the forgone methane emissions reduction under the Policy
Review, the projected reductions for 2021 (0.5 million metric tons CO2 Eq.) are equivalent to
less than one percent of the methane emissions for this sector reported in the U.S. GHGI for
2018 (about 197 million metric tons CO2 Eq. are from petroleum and natural gas production and
gas processing, transmission, and storage). Expected forgone emission reductions in 2030 (about
1.3 million metric tons CO2 Eq.) are also equivalent to less than one percent of 2017 emissions.
We estimate the forgone climate benefits under the finalized and alternative options using an
interim measure of the domestic social cost of methane (SC-CH4). The SC-CH4 is an estimate of
the monetary value of impacts associated with marginal changes in CH4 emissions in a given
year. It includes a wide range of anticipated climate impacts, such as net changes in agricultural
productivity and human health, property damage from increased flood risk, and changes in
energy system costs, such as reduced costs for heating and increased costs for air conditioning. It
is typically used to assess the avoided damages as a result of regulatory actions {i.e., benefits of
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rulemakings that lead to an incremental reduction in cumulative global CH4 emissions). The SC-
CH4 estimates used in this analysis focus on the direct impacts of climate change that are
anticipated to occur within U.S. borders.
The SC-CH4 estimates presented here are interim values developed under E.O. 13783 for use in
regulatory analyses until an improved estimate of the impacts of climate change to the U.S. can
be developed based on the best available science and economics. E.O. 13783 directed agencies to
ensure that estimates of the social cost of greenhouse gases used in regulatory analyses "are
based on the best available science and economics" and are consistent with the guidance
contained in OMB Circular A-4, "including with respect to the consideration of domestic versus
international impacts and the consideration of appropriate discount rates" (E.O. 13783, Section
5(c)). In addition, E.O. 13783 withdrew the technical support documents (TSDs) and the August
2016 Addendum to these TSDs describing the global social cost of greenhouse gas estimates
developed under the prior Administration as no longer representative of government policy. The
withdrawn TSDs and Addendum were developed by an interagency working group (IWG) that
included the EPA and other executive branch entities and were used in the 2016 NSPS RIA.
Regarding the two analytical considerations highlighted in E.O. 13783 - how best to consider
domestic versus international impacts and appropriate discount rates - current guidance in OMB
Circular A-4 is as follows. Circular A-4 states that analysis of economically significant proposed
and final regulations "should focus on benefits and costs that accrue to citizens and residents of
the United States." Because this action is economically significant as defined in E.O. 12866,
Section 3(f)(1), we follow this guidance by adopting a domestic perspective in our central
analysis. Regarding discount rates, Circular A-4 states that regulatory analyses "should provide
estimates of net benefits using both 3 percent and 7 percent." The 7 percent rate is intended to
represent the average before-tax rate of return to private capital in the U.S. economy. The 3
percent rate is intended to reflect the rate at which society discounts future consumption, which
is particularly relevant if a regulation is expected to affect private consumption directly. The
EPA follows this guidance below by presenting estimates based on both 3 and 7 percent discount
rates in the main analysis. See Appendix B for a discussion the modeling steps involved in
estimating the domestic SC-CH4 estimates based on these discount rates.
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The SC-CH4 estimates developed under E.O. 13783 will be used in regulatory analysis until
improved domestic estimates can be developed, which will take into consideration the recent
recommendations from the National Academies of Sciences, Engineering, and Medicine (2017)
for a comprehensive update to the current methodology to ensure that the social cost of
greenhouse gas estimates reflect the best available science. While the Academies' review
focused on the methodology to estimate the social cost of carbon (SC-CO2), the
recommendations on how to update many of the underlying modeling assumptions also pertain
to the SC-CH4 estimates since the framework used to estimate SC-CH4 is the same as that used
for SC-CO2.
Table 2-15 presents the average domestic SC-CH4 estimates across all the model runs for each
discount rate for emissions occurring in 2021 to 2030. As with the global SC-CH4 estimates, the
domestic SC-CH4 increases over time because future emissions are expected to produce larger
incremental damages as physical and economic systems become more stressed in response to
greater climatic change and because GDP is growing over time and many damage categories are
modeled in proportion to gross GDP.
Table 2-15 Interim Domestic Social Cost of CH4, 2021-2030 (in 2016$ per metric ton
CH4)1	
Discount Rate and Statistic
Year
7% Average
3% Average
2021
58
180
2022
60
190
2023
63
190
2024
65
200
2025
68
200
2026
70
210
2027
73
220
2028
75
220
2029
78
230
2030
81
230
1 SC-CH4 values are stated in $/metric ton CH4 and rounded to two significant digits. The estimates vary depending
on the year of CH4 emissions and are defined in real terms, i.e., adjusted for inflation using the GDP implicit price
deflator.
Table 2-16 presents the monetized forgone domestic climate benefits under the Policy Review.
Projected forgone methane emissions reductions increases in methane emissions each year are
multiplied by the SC-CH4 estimate for that year. The table shows the annual forgone benefits
discounted back to 2020 and the PV and the EAV for the 2021 to 2030 period under each
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discount rate. The PV of forgone benefits under a 7 percent discount rate is about $17 million,
with an EAV of about $2.2 million per year. The PV of forgone benefits under a 3 percent
discount rate of $63 million, with an EAV of about $7.2 million per year.
Table 2-16 Projected Forgone Domestic Climate Benefits under the Policy Review,
2021-2030 (millions, 2016$)	
Undiscounted
Discounted back to 2020
Year
7 percent
3 Percent
7 percent
3 Percent
2021
$1.2
$3.6
$1.1
$3.5
2022
$1.4
$4.4
$1.2
$4.2
2023
$1.7
$5.2
$1.4
$4.8
2024
$2.0
$6.1
$1.5
$5.4
2025
$2.3
$7.0
$1.7
$6.0
2026
$2.7
$7.9
$1.8
$6.6
2027
$3.0
$8.9
$1.9
$7.2
2028
$3.4
$10
$2.0
$7.8
2029
$3.8
$11
$2.1
$8.4
2030
$4.2
$12
$2.2
$9.1
PV


$17
$63
EAV


$2.2
$7.2
Note: Estimates may not sum due to independent rounding.
The limitations and uncertainties associated with the global SC-CH4 estimates, which were
discussed in detail in the 2016 NSPS RIA, likewise apply to the forgone domestic SC-CH4
estimates presented in this analysis.38 Some uncertainties are captured within the analysis, as
discussed in detail in Appendix B, while other areas of uncertainty have not yet been quantified
in a way that can be modeled. For example, as with the methodology used to calculate SC-CO2
estimates, limitations include incomplete or inadequate representation in the integrated
assessment models of several important factors: catastrophic and non-catastrophic impacts,
adaptation and technological change, inter-regional and inter-sectoral linkages, uncertainty in the
extrapolation of damages to high temperatures, and the relationship between the discount rate
and uncertainty in economic growth over long time horizons. The science incorporated into these
models understandably lags the most recent research, and the limited amount of research linking
climate impacts to economic damages makes the modeling exercise even more difficult.
38 The SC-CH4 estimates presented in the 2016 NSPS RIA are the same as the SC-CH4 estimates presented in EPA-
HQ-OAR-2015-0827-5886, "Addendum to Technical Support Document on Social Cost of Carbon for
Regulatory Impact Analysis under Executive Order 12866: Application of the Methodology to Estimate the
Social Cost of Methane and the Social Cost of Nitrous Oxide (August 2016)", except the estimates in the 2016
NSPS RIA were adjusted to 2012 dollar. The estimates published in the 2016 NSPS RIA were labeled as
"Marten et al. (2014)" estimates. In addition, EPA-HQ-OAR-2015-0827-5886 provides a detailed discussion of
the limitations and uncertainties associated with the SC-GHG estimates.
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There are several limitations specific to the estimation of SC-CH4. For example, the SC-CH4
estimates do not reflect updates from the IPCC regarding atmospheric and radiative efficacy.39
Another limitation is that the SC-CH4 estimates do not account for the direct health and welfare
impacts associated with tropospheric ozone produced by methane (see the 2016 NSPS RIA for
further discussion). In addition, the SC-CH4 estimates do not reflect that methane emissions lead
to a reduction in atmospheric oxidants, like hydroxyl radicals, nor do they account for impacts
associated with CO2 produced from methane oxidizing in the atmosphere. See EPA-HQ-OAR-
2015-0827-5886 for more detailed discussion about the limitations specific to the estimation of
SC-CH4. These individual limitations and uncertainties do not all work in the same direction in
terms of their influence on the SC-CH4 estimates. In accordance with guidance in OMB Circular
A-4 on the treatment of uncertainty, Appendix B provides a detailed discussion of the ways in
which the modeling underlying the development of the SC-CH4 estimates used in this analysis
addresses quantified sources of uncertainty and presents a sensitivity analysis to show
consideration of the uncertainty surrounding discount rates over long time horizons.
Recognizing the limitations and uncertainties associated with estimating the social cost of
greenhouse gases, the research community has continued to explore opportunities to improve
estimates of SC-CO2 and other greenhouse gases. Notably, the National Academies of Sciences,
Engineering, and Medicine conducted a multi-discipline, multi-year assessment to examine
potential approaches, along with their relative merits and challenges, for a comprehensive update
to the IWG methodology. The task was to ensure that the SC-CO2 estimates that are used in
Federal analyses reflect the best available science, focusing on issues related to the choice of
models and damage functions, climate science modeling assumptions, socioeconomic and
emissions scenarios, presentation of uncertainty, and discounting. In January 2017, the
Academies released their final report, Valuing Climate Damages: Updating Estimation of the
Social Cost of Carbon Dioxide,40 and recommended specific criteria for future updates to the
SC-CO2 estimates, a modeling framework to satisfy the specified criteria, and both near-term
39	The SC-CH4 estimates used in the 2016 NSPS RIA served as the starting point to calculate the interim domestic
estimates presented in this RIA. The 2016 NSPS RIA SC-CH4 estimates were calculated in 2014 using
atmospheric and radiative efficacy values that have since been updated by the IPCC.
40	National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages: Updating
Estimation of the Social Cost of Carbon Dioxide. National Academies Press. Washington, DC Available at
https://www.nap.edu/catalog/24651/valuing-climate-damages-updating-estimation-of-the-social-cost-of/.
Accessed April 26, 2020.
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updates and longer-term research needs pertaining to various components of the estimation
process (National Academies 2017). Since the framework used to estimate SC-CH/jis the same
as that used for SC-CO2, the Academies' recommendations on how to update many of the
underlying modeling assumptions also apply to the SC-CH4 estimates.
The Academies' report also discussed the challenges in developing domestic SC-CO2 estimates,
noting that current IAMs do not model all relevant regional interactions—e.g., how climate
change impacts in other regions of the world could affect the United States, through pathways
such as global migration, economic destabilization, and political destabilization. The Academies
concluded that it "is important to consider what constitutes a domestic impact in the case of a
global pollutant that could have international implications that impact the United States. More
thoroughly estimating a domestic SC-CO2 would therefore need to consider the potential
implications of climate impacts on, and actions by, other countries, which also have impacts on
the United States." (National Academies 2017, pg 12-13). This challenge is equally applicable to
the estimation of a domestic SC-CH4.
In addition to requiring reporting of domestic impacts, Circular A-4 states that when an agency
"evaluate[s] a regulation that is likely to have effects beyond the borders of the United States,
these effects should be reported separately" (page 15). This guidance is relevant to the valuation
of damages from methane and other GHGs, given that GHGs contribute to damages around the
world independent of the country in which they are emitted. Therefore, in accordance with this
guidance in OMB Circular A-4, Appendix B presents the forgone global climate benefits under
the Policy Review using global SC-CH4 estimates based on both 3 and 7 percent discount rates.
Note that the EPA did not quantitatively project the full impact of the 2012 and 2016 NSPS on
international trade and the location of production, so it is not possible to present analogous
estimates of global cost reductions resulting from the finalized action. However, to the extent
that affected firms have some foreign ownership, some of the cost reductions accruing to entities
outside U.S. borders is captured in the compliance cost reductions presented in this RIA.
2.3.4 VOC as an Ozone Precursor
This rulemaking may forgo emission reductions of VOC, which are a precursor to ozone. Ozone
is not emitted directly into the air, but is created when its two primary components, VOC and
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oxides of nitrogen (NOx), react in the atmosphere in the presence of sunlight. In urban areas,
compounds representing all classes of VOC are important for ozone formation, but biogenic
VOC emitted from vegetation tend to be more important compounds in non-urban vegetated
areas (U.S. EPA, 2013). Forgone emission reductions may increase ozone formation, human
exposure to ozone, and the incidence of ozone-related health effects. However, we have not
quantified the ozone-related forgone benefits in this analysis due to the complex non-linear
chemistry of ozone formation, which introduces uncertainty to the development and application
of a benefit-per-ton estimate, particularly for sectors with substantial new growth. In addition,
the impact of forgone VOC emission reductions is spatially heterogeneous and highly dependent
on local air chemistry. Urban areas with a high population concentration are often VOC-limited,
which means that ozone is most effectively reduced by lowering VOC. Rural areas and
downwind suburban areas are often NOx-limited, which means that ozone concentrations are
most effectively reduced by lowering NOx emissions, rather than lowering emissions of VOC.
Between these areas, ozone is relatively insensitive to marginal changes in both NOx and VOC.
Due to data limitations regarding potential locations of new, reconstructed, and modified sources
affected by this rulemaking, we did not perform air quality modeling for this rule needed to
quantify the forgone ozone benefits associated with forgone VOC emission reductions. Due to
the high degree of variability in the responsiveness of ozone formation to VOC emissions and
data limitations regarding the location of new, reconstructed, and modified well sites, we are
unable to estimate the effect that forgone VOC emission reductions will have on ambient ozone
concentrations without air quality modeling.41
2.3.4.1 Ozone Health Effects
Human exposure to ambient ozone concentrations is associated with adverse health effects,
including premature mortality and cases of respiratory morbidity (U.S. EPA, 2010). Researchers
have associated ozone exposure with adverse health effects in numerous toxicological, clinical
and epidemiological studies (U.S. EPA, 2013). When adequate data and resources are available,
the EPA has generally quantified several health effects associated with exposure to ozone (e.g.,
41 EPA is working on improving our understanding of the effects of VOC emission reductions in the oil and natural
gas sector.
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U.S. EPA, 2010; U.S. EPA, 2011c). These health effects include respiratory morbidity, such as
asthma attacks; hospital and emergency department visits; lost school days; and premature
mortality. The scientific literature is also suggestive that exposure to ozone is also associated
with chronic respiratory damage and premature aging of the lungs.
The EPA has previously estimated the ozone-related benefits of reducing VOC emissions from
the industrial boiler sector (U.S. EPA, 201 lb)42 and in the RIA for the proposed Ozone NAAQS
(U.S. EPA, 2014). While the benefit-per-ton estimates used to quantify impacts for those rules
may provide useful context, the geographic distribution of VOC emissions from the oil and
natural gas sector is not consistent with emissions modeled in either analysis. Therefore, we do
not believe that those estimates are representative of the monetized forgone benefits of this rule,
even as a bounding exercise.
2.3.4.2	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, 2013). 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 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.
2.3.4.3	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,
42 While EPA has estimated the ozone benefits for many scenarios, most of those scenarios also reduce NO2
emissions, which make it difficult to isolate the benefits attributable to VOC reductions.
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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.
2.3.5 VOC as a PM2.5 Precursor
This rulemaking is expected to result in forgone emission reductions of VOC, which are a
precursor to PM2.5, thus increasing human exposure to PM2.5 and the incidence of PIVh.s-related
health effects, although the magnitude of this effect cannot be quantified at this time. Most VOC
emitted are oxidized to CO2 rather than to PM, but a portion of VOC emission contributes to
ambient PM2.5 levels as organic carbon aerosols (U.S. EPA, 2009a). Analysis of organic carbon
measurements suggest only a fraction of secondarily formed organic carbon aerosols are of
anthropogenic origin. The current state of the science of secondary organic carbon aerosol
formation indicates that anthropogenic VOC contribution to secondary organic carbon aerosol is
often lower than the biogenic (natural) contribution and photochemical models typically estimate
secondary organic carbon from anthropogenic VOC emissions to be less than 0.1 |ig/m3 (U.S.
EPA, 2009a). Given that only a small fraction of secondarily formed organic carbon aerosols is
from anthropogenic VOC emissions, it is unlikely that this sector has a large contribution to
ambient secondary organic carbon aerosols. Therefore, we have not quantified the forgone
PM2.5-related benefits in this analysis.
2.3.5.1 PM2.5 Health Effects
Increasing VOC emissions would increase secondary PM2.5 formation, and, thus, the incidence
of PM2.5-related health effects. Increasing exposure to PM2.5 is associated with significant human
health detriments, including mortality and respiratory morbidity. Researchers have associated
PM2.5 exposure with adverse health effects in numerous toxicological, clinical and
epidemiological studies (U.S. EPA, 2009a). These health effects include premature death in
people with heart or lung disease, nonfatal heart attacks, irregular heartbeat, aggravated asthma,
decreased lung function, and increased respiratory symptoms, such as irritation of the airways,
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coughing, or difficulty breathing (U.S. EPA, 2009a). These health effects result in hospital and
ER visits, lost workdays, and restricted activity days. When adequate data and resources are
available, The EPA has quantified the health effects associated with exposure to PM2.5 {e.g., U.S.
EPA (2011c)).
When the EPA quantifies PIVh.s-related benefits, the Agency assumes that all fine particles,
regardless of their chemical composition, are equally potent in causing premature mortality
because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by
particle type (U.S. EPA, 2009a). Based on our review of the current body of scientific literature,
the EPA estimates PM-related premature mortality without applying an assumed concentration
threshold. This decision is supported by the data, which are quite consistent in showing effects
down to the lowest measured levels of PM2.5 in the underlying epidemiology studies.
2.3.5.2 Organic PM Welfare Effects
According to the residual risk assessment that the EPA performed for this sector (U.S. EPA,
2012a), persistent and bioaccumulative HAP reported as emissions from oil and natural gas
operations include polycyclic organic matter (POM). POM defines a broad class of compounds
that includes polycyclic aromatic hydrocarbon compounds (PAHs). Several significant
ecological effects are associated with the deposition of organic particles, including persistent
organic pollutants, and PAHs (U.S. EPA, 2009a). This summary is from Section 6.6.1 of the
2012 PM NAAQS RIA (U.S. EPA, 2012b).
PAHs can accumulate in sediments and bioaccumulate in freshwater, flora, and fauna. The
uptake of organics depends on the plant species, site of deposition, physical and chemical
properties of the organic compound and prevailing environmental conditions (U.S. EPA, 2009a).
PAHs can accumulate to high enough concentrations in some coastal environments to pose an
environmental health threat that includes cancer in fish populations, toxicity to organisms living
in the sediment and risks to those (e.g., migratory birds) that consume these organisms.
Atmospheric deposition of particles is thought to be the major source of PAHs to the sediments
of coastal areas of the U.S. Deposition of PM to surfaces in urban settings increases the metal
and organic component of storm water runoff. This atmospherically associated pollutant burden
can then be toxic to aquatic biota. The contribution of atmospherically deposited PAHs to
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aquatic food webs was demonstrated in high elevation mountain lakes with no other
anthropogenic contaminant sources.
The Western Airborne Contaminants Assessment Project (WACAP) is the most comprehensive
database available on contaminant transport and the effects of PM deposition on sensitive
ecosystems in the Western U.S. (Landers et al., 2008). In this project, the transport, fate, and
ecological impacts of anthropogenic contaminants from atmospheric sources were assessed from
2002 to 2007 in seven ecosystem components (air, snow, water, sediment, lichen, conifer
needles, and fish) in eight core national parks. The study concluded that bioaccumulation of
semi-volatile organic compounds occurred throughout park ecosystems, that an elevational
gradient in PM deposition exists with greater accumulation in higher altitude areas, and that
contaminants accumulate in proximity to individual agriculture and industry sources, which is
counter to the original working hypothesis that most of the contaminants would originate from
Eastern Europe and Asia.
2.3.5.3 Visibility Effects
Increasing secondary formation of PM2.5 from VOC emissions could reduce visibility throughout
the U.S. Fine particles with significant light-extinction efficiencies include sulfates, nitrates,
organic carbon, elemental carbon, and soil (Sisler, 1996). Suspended particles and gases degrade
visibility by scattering and absorbing light. Higher visibility impairment levels in the East are
due to higher concentrations of fine particles, particularly sulfates, and higher average relative
humidity levels. Visibility impairment has a direct impact on people's enjoyment of daily
activities and their overall sense of wellbeing. Good visibility increases the quality of life where
individuals live and work, and where they engage in recreational activities. Previous analyses
(U.S. EPA, 2006; U.S. EPA, 2011a; U.S. EPA, 2011c; U.S. EPA, 2012b) show that visibility
benefits are a significant welfare benefit category. However, without air quality modeling, we are
unable to estimate forgone visibility related benefits, nor are we able to determine whether
forgone VOC emissions would be likely to have a significant impact on visibility in urban areas
or Class I areas.
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2.3.6 Hazardous Air Pollutants (HAP)
When looking at exposures from all air toxic sources of outdoor origin across the U.S., we see
that emissions declined by approximately 60 percent since 1990. However, despite this decline,
the 2014 National-Scale Air Toxics Assessment (NATA) predicts that some Americans are still
exposed to ambient concentrations of air toxics at levels that have the potential to cause adverse
health effects.43 The levels of air toxics to which people are exposed vary depending on where
they live and work and the kinds of activities in which they engage. In order to identify and
prioritize air toxics, emission source types and locations that are of greatest potential concern, the
EPA conducts the NATA.44 The most recent NATA was conducted for calendar year 2014 and
was released in August 2018. NATA includes four steps:
1)	Compiling a national emissions inventory of air toxics emissions from outdoor sources;
2)	Estimating ambient concentrations of air toxics across the U.S. using dispersion models;
3)	Estimating population exposures across the U.S. using exposure models; and
4)	Characterizing potential public health risk due to inhalation of air toxics including both
cancer and noncancer effects.
Based on the 2014 NATA, the EPA estimates that less than 1 percent of census tracts nationwide
have increased cancer risks greater than 100-in-l million. The average national cancer risk is
about 30-in-l million. Nationwide, the key pollutants that contribute most to the overall cancer
risks are formaldehyde and benzene.45-46 Secondary formation (e.g., formaldehyde forming from
43 The 2014 NATA is available on the Internet at http://www.epa.gov/nataA_Accessed April 26, 2020.
44The NATA modeling framework has several limitations that prevent its use as the sole basis for setting regulatory
standards. These limitations and uncertainties are discussed on the 2014 NATA website. Even so, this modeling
framework is very useful in identifying air toxic pollutants and sources of greatest concern, setting regulatory
priorities, and informing the decision-making process. U.S. EPA. (2018) 2014 National-Scale Air Toxics
Assessment, http://www.epa.gov/nata/. Accessed April 26, 2020.
45	Details on EPA's approach to characterization of cancer risks and uncertainties associated with the 2014 NATA
risk estimates can be found at http://www.epa.gov/national-air-toxics-assessment/nata-limitations/ Accessed
April 26, 2020.
46	Details about the overall confidence of certainty ranking of the individual pieces of NATA assessments including
both quantitative (e.g., model-to-monitor ratios) and qualitative (e.g., quality of data, review of emission
inventories) judgments can be found at http://www.epa.gov/national-air-toxics-assessment/nata-limitations/
Accessed April 26, 2020.
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other emitted pollutants) was the largest contributor to cancer risks, while stationary, mobile,
biogenics, and background sources contribute lesser amounts to the remaining cancer risk.
Noncancer health effects can result from chronic,47 subchronic,48 or acute49 inhalation exposure to
air toxics, and include neurological, cardiovascular, liver, kidney, and respiratory effects as well
as effects on the immune and reproductive systems. According to the 2014 NATA, less than 1
percent of the U.S. population was exposed to an average chronic concentration of air toxics that
had the potential for adverse noncancer health effects. Results from the 2014 NATA indicate that
acrolein is the primary respiratory driver for noncancer respiratory risk.
Figure 2-1 depicts the 2014 NATA estimated census tract-level carcinogenic risk from the
assessment. It is important to note that increases in HAP emissions may not necessarily translate
into significant increases in health risk because toxicity varies by pollutant, and exposures may
or may not exceed levels of concern. For example, just a few pounds of some metals {i.e.,
Hexavalent Chromium) is more toxic than a ton of benzene. However, the Integrated Risk
Information System (IRIS) unit risk estimate (URE) for hexavalent chromium is considerably
higher (more toxic) than that for benzene.50 Thus, it is important to account for the toxicity and
exposure, as well as the mass of the targeted emissions.
47	Chronic exposure is defined in the glossary of the Integrated Risk Information System (IRIS) database
(http://www.epa.gov/iris) as repeated exposure by the oral, dermal, or inhalation route for more than
approximately 10 of the life span in humans (more than approximately 90 days to 2 years in typically used
laboratory animal species).
48	Defined in the IRIS database as repeated exposure by the oral, dermal, or inhalation route for more than 30 days,
up to approximately 10 of the life span in humans (more than 30 days up to approximately 90 days in typically
used laboratory animal species).
49	Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.
50	Details on the derivation of IRIS values and available supporting documentation for individual chemicals (as well
as chemical values comparisons) can be found at http://www.epa.gov/iris/. Accessed April 26, 2020.
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Total Cancer Risk

(in a million)

6-25

25-50

IMI 50 - 75

— 75 - 100

Ml > 100

> > Zero Pop Tract

Figure 2-1 2014 NATA Model Estimated Census Tract Carcinogenic Risk from HAP
Exposure from All Outdoor Sources based on the 2014 National Emissions Inventory
Due to methodology and data limitations, we were unable to estimate the benefits or disbenefits
associated with the hazardous air pollutant emissions changes that could occur as a result of this
rule. In a few previous analyses of the benefits of reductions in HAP, the EPA has quantified the
benefits of potential reductions in the incidences of cancer and noncancer risk (e.g., U.S. EPA,
1995). In those analyses, The EPA relied on unit risk estimate (URE) and reference
concentrations (RfC) developed through risk assessment procedures. The URE is a quantitative
estimate of the carcinogenic potency of a pollutant, often expressed as the probability of
contracting cancer from a 70-year lifetime continuous exposure to a concentration of one |ig/m3
of a pollutant. These UREs are designed to be conservative, and as such, are more likely to
represent the high end of the distribution of risk rather than a best or most likely estimate of risk.
An RfC is an estimate (with uncertainty spanning perhaps an order of magnitude) of a
continuous inhalation exposure to the human population (including sensitive subgroups) that is
likely to be without an appreciable risk of deleterious noncancer health effects during a lifetime.
As the purpose of a forgone benefit analysis is to describe the benefits most likely to result from
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a forgone reduction in pollution, use of high-end, conservative risk estimates would overestimate
the forgone benefits of the regulation. While we used high-end risk estimates in past analyses,
advice from the EPA's Science Advisory Board (SAB) recommended that we avoid using high-
end estimates in benefit analyses (U.S. EPA-SAB, 2002). Since that time, the EPA has continued
to develop better methods for analyzing the benefits of reductions in HAP.
As part of the second prospective analysis of the benefits and costs of the Clean Air Act (U.S.
EPA, 201 la), the EPA conducted a case study analysis of the health effects associated with
reducing exposure to benzene in Houston from implementation of the Clean Air Act (IEc, 2009).
While reviewing the draft report, the EPA's Advisory Council on Clean Air Compliance
Analysis concluded that "the challenges for assessing progress in health improvement as a result
of reductions in emissions of hazardous air pollutants (HAP) are daunting...due to a lack of
exposure-response functions, uncertainties in emissions inventories and background levels, the
difficulty of extrapolating risk estimates to low doses and the challenges of tracking health
progress for diseases, such as cancer, that have long latency periods" (U.S. EPA-SAB, 2008).
In summary, monetization of the forgone 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 forgone health
benefits of forgone reductions in HAP in this analysis. Instead, we are providing a qualitative
analysis of the health effects associated with the HAP anticipated to be forgone by this rule. The
EPA remains committed to improving methods for estimating HAP benefits by continuing to
explore additional concepts of benefits, including changes in the distribution of risk.
Available emissions data show that several different HAP are emitted from oil and natural gas
operations, either from equipment leaks, processing, compressing, transmission and distribution,
or storage tanks. Emissions of eight HAP make up a large percentage of the total HAP emissions
by mass from the oil and natural gas sector: toluene, hexane, benzene, xylenes (mixed), ethylene
glycol, methanol, ethyl benzene, and 2,2,4-trimethylpentane (U.S. EPA, 2012a). In the
subsequent sections, we describe the health effects associated with the main HAP of concern
from the oil and natural gas sector: benzene, toluene, carbonyl sulfide, ethylbenzene, mixed
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xylenes, and n-hexane. This rule is anticipated to result an increase of a total of 370 tons of HAP
emissions over 2021 through 2030. With the data available, it was not possible to estimate the
change in emissions of each individual HAP.
2.3.6.1	Benzene
The EPA's IRIS database lists benzene as a known human carcinogen (causing leukemia) by all
routes of exposure, and concludes that exposure is associated with additional health effects,
including genetic changes in both humans and animals and increased proliferation of bone
marrow cells in mice (U.S EPA, 2000; IARC 1982; Irons, 1992). The EPA states in its IRIS
database that data indicate a causal relationship between benzene exposure and acute
lymphocytic leukemia and suggest a relationship between benzene exposure and chronic non-
lymphocytic leukemia and chronic lymphocytic leukemia. The International Agency for
Research on Carcinogens (IARC) has determined that benzene is a human carcinogen and the
U.S. Department of Health and Human Services has characterized benzene as a known human
carcinogen (IARC, 1987; NTP, 2004). Several adverse noncancer health effects including blood
disorders, such as preleukemia and aplastic anemia, have also been associated with long-term
exposure to benzene (Aksoy, 1989; Goldstein, 1988).
2.3.6.2	Toluene51
Under the 2005 Guidelines for Carcinogen Risk Assessment, there is inadequate information to
assess the carcinogenic potential of toluene because studies of humans chronically exposed to
toluene are inconclusive, toluene was not carcinogenic in adequate inhalation cancer bioassays of
rats and mice exposed for life, and increased incidences of mammary cancer and leukemia were
reported in a lifetime rat oral bioassay.
The central nervous system (CNS) is the primary target for toluene toxicity in both humans and
animals for acute and chronic exposures. CNS dysfunction (which is often reversible) and
narcosis have been frequently observed in humans acutely exposed to low or moderate levels of
51 All health effects language for this section came from: U.S. EPA. 2005. "Full IRIS Summary for Toluene
(CASRN 108-88-3)" Environmental Protection Agency, Integrated Risk Information System (IRIS), Office of
Health and Environmental Assessment, Environmental Criteria and Assessment Office, Cincinnati, OH.
Available at http://www.epa.gov/iris/subst/0118.ht/. Accessed April 26, 2020.
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toluene by inhalation: symptoms include fatigue, sleepiness, headaches, and nausea. Central
nervous system depression has been reported to occur in chronic abusers exposed to high levels
of toluene. Symptoms include ataxia, tremors, cerebral atrophy, nystagmus (involuntary eye
movements), and impaired speech, hearing, and vision. Chronic inhalation exposure of humans
to toluene also causes irritation of the upper respiratory tract, eye irritation, dizziness, headaches,
and difficulty with sleep.
Human studies have also reported developmental effects, such as CNS dysfunction, attention
deficits, and minor craniofacial and limb anomalies, in the children of women who abused
toluene during pregnancy. A substantial database examining the effects of toluene in subchronic
and chronic occupationally exposed humans exists. The weight of evidence from these studies
indicates neurological effects {i.e., impaired color vision, impaired hearing, decreased
performance in neurobehavioral analysis, changes in motor and sensory nerve conduction
velocity, headache, and dizziness) as the most sensitive endpoint.
2.3.6.3	Carbonyl Sulfide
Limited information is available on the health effects of carbonyl sulfide. Acute (short-term)
inhalation of high concentrations of carbonyl sulfide may cause narcotic effects and irritate the
eyes and skin in humans.52 No information is available on the chronic (long-term), reproductive,
developmental, or carcinogenic effects of carbonyl sulfide in humans. Carbonyl sulfide has not
undergone a complete evaluation and determination under U.S. EPA's IRIS program for
evidence of human carcinogenic potential.53
2.3.6.4	Ethylbenzene
Ethylbenzene is a major industrial chemical produced by alkylation of benzene. The pure
chemical is used almost exclusively for styrene production. It is also a constituent of crude
52	Hazardous Substances Data Bank (HSDB), online database. US National Library of Medicine, Toxicology Data
Network, available online at https://pubchem.ncbi.nlm.nih.gov/. Carbonyl sulfide health effects summary
available at https://pubchem.ncbi.nlm.nih.gov/compound/10039#section=Safety-and-Hazards. Accessed April
26, 2020.
53	U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Carbonyl
Sulfide. Research and Development, National Center for Environmental Assessment, Washington, DC. This
material is available electronically at http://www.epa.gov/iris/subst/0617.htm/. Accessed April 26, 2020.
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petroleum and is found in gasoline and diesel fuels. Acute (short-term) exposure to ethylbenzene
in humans results in respiratory effects such as throat irritation and chest constriction, and
irritation of the eyes, and neurological effects such as dizziness. Chronic (long-term) exposure of
humans to ethylbenzene may cause eye and lung irritation, with possible adverse effects on the
blood. Animal studies have reported effects on the blood, liver, and kidneys and endocrine
system from chronic inhalation exposure to ethylbenzene. No information is available on the
developmental or reproductive effects of ethylbenzene in humans, but animal studies have
reported developmental effects, including birth defects in animals exposed via inhalation. Studies
in rodents reported increases in the percentage of animals with tumors of the nasal and oral
cavities in male and female rats exposed to ethylbenzene via the oral route (Maltoni, 1985,
Maltoni, 1997). The reports of these studies lacked detailed information on the incidence of
specific tumors, statistical analysis, survival data, and information on historical controls, thus the
results of these studies were considered inconclusive by the International Agency for Research
on Cancer (IARC, 2000) and the National Toxicology Program (NTP, 1999). The NTP (1999)
carried out a chronic inhalation bioassay in mice and rats and found clear evidence of
carcinogenic activity in male rats and some evidence in female rats, based on increased
incidences of renal tubule adenoma or carcinoma in male rats and renal tubule adenoma in
females. NTP (1999) also noted increases in the incidence of testicular adenoma in male rats.
Increased incidences of lung alveolar/bronchiolar adenoma or carcinoma were observed in male
mice and liver hepatocellular adenoma or carcinoma in female mice, which provided some
evidence of carcinogenic activity in male and female mice (NTP, 1999). IARC (2000) classified
ethylbenzene as Group 2B, possibly carcinogenic to humans, based on the NTP studies.
2.3.6.5 Mixed Xylenes
Short-term inhalation of mixed xylenes (a mixture of three closely-related compounds) in
humans may cause irritation of the nose and throat, nausea, vomiting, gastric irritation, mild
transient eye irritation, and neurological effects (U.S. EPA, 2003). Other reported effects include
labored breathing, heart palpitation, impaired function of the lungs, and possible effects in the
liver and kidneys (ATSDR, 2007). Long-term inhalation exposure to xylenes in humans has been
associated with a number of effects in the nervous system including headaches, dizziness,
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fatigue, tremors, and impaired motor coordination (ATSDR, 2007). The EPA has classified
mixed xylenes in Category D, not classifiable with respect to human carcinogenicity.
2.3.6.6	n-Hexane
The studies available in both humans and animals indicate that the nervous system is the primary
target of toxicity upon exposure of n-hexane via inhalation. There are no data in humans and
very limited information in animals about the potential effects of n-hexane via the oral route.
Acute (short-term) inhalation exposure of humans to high levels of hexane causes mild central
nervous system effects, including dizziness, giddiness, slight nausea, and headache. Chronic
(long-term) exposure to hexane in air causes numbness in the extremities, muscular weakness,
blurred vision, headache, and fatigue. Inhalation studies in rodents have reported behavioral
effects, neurophysiological changes and neuropathological effects upon inhalation exposure to n-
hexane. Under the Guidelines for Carcinogen Risk Assessment (U.S. EPA, 2005), the database
for n-hexane is considered inadequate to assess human carcinogenic potential, therefore The
EPA has classified hexane in Group D, not classifiable as to human carcinogenicity.
2.3.6.7	Other Air Toxics
In addition to the compounds described above, other toxic compounds might be affected by this
rule, including hydrogen sulfide (H2S). Information regarding the health effects of those
compounds can be found in the EPA's IRIS database.54
2.4 Economic Impacts and Distributional Assessments
This section includes four sets of discussion for this final action: energy markets impacts,
distributional impacts, small business impacts, and employment impacts.
2.4.1 Energy Markets Impacts
As it is implemented, the 2016 NSPS OOOOa may have impacts on energy production and
markets, which would be reduced by the finalized Policy Review. For the 2016 NSPS RIA, The
EPA used the National Energy Modeling System (NEMS) to project drilling activity, price, and
54U.S. EPA Integrated Risk Information System (IRIS) database is available at www.epa.gov/iris. Accessed April
26, 2020
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quantity changes in the production of crude oil and natural gas, and changes in international trade
of crude oil and natural gas national energy markets as a result of the 2016 NSPS OOOOa.55 In
that analysis, the EPA estimated the following impacts under the final 2016 NSPS OOOOa:
•	Natural gas and crude oil drilling levels would decline slightly over the 2020 to 2025
period (by about 0.17 percent for natural gas wells and 0.02 percent for crude oil wells);
•	Crude oil production would not change appreciably under the rule, while natural gas
production would decline slightly over the 2020 to 2025 period (about 0.03 percent);
•	Crude oil wellhead prices for onshore production in the lower 48 states were not
estimated to change appreciably over the 2020 to 2025 period, while wellhead natural gas
prices for onshore production in the lower 48 states were estimated to increase slightly
over the 2020 to 2025 period (about 0.20 percent); and,
•	Net imports of natural gas were estimated to increase slightly in 2020 (by about 0.12
percent) and in 2025 (by about 0.11 percent), while net imports of crude oil were not
estimated to change appreciably over the 2020 to 2025 period.
As described earlier in this RIA, this final action removes requirements in the 2016 NSPS
OOOOa for sources in the transmission and storage segment. The finalized Policy Review is
expected to lead to cost reductions compared to the baseline. As a result, the EPA expects this
final action to reduce the impacts associated with the 2016 NSPS.
2.4.2 Distributional Impacts
The cost reductions and forgone benefits presented above are not expected to be distributed
uniformly across the population. OMB recommends including a description of distributional
effects in regulatory analysis, "so that decision makers can properly consider them along with the
effects on economic efficiency [i.e., net benefits]. Executive Order 12866 authorizes this
approach." (U.S. Office of Management and Budget 2003). Understanding the distribution of the
compliance cost reductions and forgone benefits can reveal community-level impacts associated
55 See Section 6.2 of the 2016 NSPS RIA.
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with regulatory actions. This section discusses the general expectations regarding how cost
reductions might be distributed across affected entities and how forgone health benefits might be
distributed across the U.S. informed by a review of recent literature. The EPA did not conduct a
quantitative assessment of these distributional impacts for the final Policy Review, but this
section provides a qualitative discussion of the types of distributional impacts that could result
from this final action.
2.4.2.1 Distributional Aspects of Compliance Cost Reductions
The compliance costs associated with an environmental regulation can impact households by
raising the prices of goods and services; the extent of the price increase depends on if and how
producers pass-through those costs to consumers. The literature evaluates the distributional
effects of introducing a new regulation; for this action, which is deregulatory, these effects can
generally be interpreted in reverse. Expenditures on energy are usually a larger share of low-
income household income than that of other households, and this share falls as income increases.
Therefore, policies that increase energy prices have been found to be regressive, placing a
relatively higher burden on lower income households (e.g., Burtraw et al., 2009; Hassett et al.,
2009; Williams et al. 2015). However, compliance costs will not be solely passed on in the form
of higher energy prices, but also through lower labor earnings and returns to capital in the sector.
Changes in employment associated with lower labor earnings can have distributional
consequences depending on several factors (Section 2.4.4 discusses employment effects further).
Capital income tends to make up a greater proportion of overall income for high income
households. As a result, the costs passed through to households via lower returns to capital tend
to be progressive, placing a greater share of the burden on higher income households in these
instances (Rausch et al., 2011; Fullerton et al., 2012).
The ultimate distributional outcomes of a regulation will depend on how changes in energy
prices and lower returns to labor and capital propagate through the economy and interact with
existing government transfer programs. Some studies that use economy-wide frameworks find
that the overall distribution of compliance costs could be progressive for some policies due to the
changes in capital payments and the expectation that existing government transfer indexed to
inflation will offset the burden to lower income households (Fullerton et al., 2011; Blonz et al.,
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2012).56 However, others have found the distribution of compliance costs to be regressive due to
a dominating effect of changes in energy prices to consumers (Fullerton 2011; Burtraw, et. al.,
2009; Williams, et al., 2015). There may also be significant heterogeneity in the costs borne by
individuals within income deciles (Rausch et al., 2011; Cronin et al., 2019). Different
classifications of households, such as those based on lifetime income rather than
contemporaneous annual income, may indicate notably different results in a distributional
analysis (Fullerton and Metcalf, 2002; Fullerton et al., 2011). Furthermore, there may be
important regional differences in the incidence of regulations. There are differences in the
composition of goods consumed, regional production methods, the stringency of a rule, as well
as the location of affected labor and capital ownership (the latter of which may be foreign-
owned) (e.g. Caron et al. 2017; Hassett et al. 2009).
2.4.2.2 Distributional Aspects of the Forgone Health Benefits
This section discusses the distribution of forgone health benefits that result from the final Policy
Review. The EPA guidance directs analysts to first consider the distribution of impacts in the
baseline, prior to any regulatory action (U.S. EPA 2016). Often the baseline incidence of health
problems is higher in low-income or minority populations due to a variety of factors, including
the tendency for more pollution sources to be located in areas where low-income and minority
populations live, work, and play (Bullard, et al. 2007; United Church of Christ 1987); greater
susceptibility to a given exposure level due to physiology or other triggers (Akinbami 2012); and
higher incidence of pre-existing conditions (Schwartz et al 2011). EPA (2016) recommends
analysts examine the distribution of health impacts under the regulatory options being
considered. Finally, after assessing the differences between the baseline and policy scenario,
analysts should take note of whether the action ameliorates or exacerbates any pre-existing
disparities.
Because regulatory health impacts are distributed based on the degree to which housing and
work locations overlap geographically with areas where atmospheric concentrations of pollutants
56 The incidence of government transfer payments (e.g., Social Security) is generally progressive because these
payments represent a significant source of income for lower income deciles and only a small source for high
income deciles. Government transfer programs are often, implicitly or explicitly, indexed to inflation. For
example, Social Security payments and veterans' benefits are adjusted every year to account for changes in
prices (i.e., inflation).
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change, it is difficult to fully know the distributional impacts of a rule. Air dispersion models
provide some information on changes in air quality induced by regulation, but it may be difficult
to identify the characteristics of populations in those affected areas, as well as to perform local
air dispersion modeling nationwide. Furthermore, the overall distribution of health benefits will
depend on whether and how households engage in averting behaviors in response to changes in
air quality, e.g., by moving or changing the amount of time spent outside (Sieg et al., 2004).
2.4.3	Small Business Impacts
The Regulatory Flexibility Act (RFA; 5 U.S.C. ง601 et seq.), as amended by the Small Business
Regulatory Enforcement Fairness Act (Public Law No. 104121), requires that whenever an
agency publishes a proposed rule, it must prepare and make available an initial regulatory
flexibility analysis (IRFA), unless it certifies that the rule, if promulgated, will not have a
significant economic impact on a substantial number of small entities (5 U.S.C. ง605[b]). Small
entities include small businesses, small organizations, and small governmental jurisdictions. An
IRFA describes the economic impact of the rule on small entities and any alternative options that
would accomplish the objectives of the rule while minimizing economic impacts on small
entities.
An agency may certify that a rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has
a positive economic effect on the small entities subject to the rule. As the Policy Review
eliminates the regulatory requirements of the oil and natural gas sector NSPS for all transmission
and storage sources, we have concluded that this final action will relieve regulatory burden for
affected small entities in the transmission and storage segment that would otherwise be subject to
requirements under the baseline.
2.4.4	Employment Impacts
We analyzed the impacts of the Policy Review on employment, which are discussed in this
section.57 This analysis uses detailed engineering information on labor requirements for the
57 The employment analysis in this RIA is part of the 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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rescinded provisions in order to estimate partial employment impacts for affected entities in the
oil and natural gas industry. These bottom-up, engineering-based estimates represent only one
portion of potential employment impacts within the regulated industry and do not represent
estimates of the net employment impacts of this rule. Due to data and methodological limitations,
other potential employment impacts in the affected industry and impacts in related industries
could not be estimated. First, this section presents an overview of the various ways that
environmental regulation can affect employment. 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.
The section concludes with estimates of partial employment impacts based on engineering-based
information for labor requirements.
2.4.4.1 Employment Impacts of Environmental Regulation
E.O. 13777 directs federal agencies to consider a variety of issues regarding the characteristics
and impacts of regulations, including the effect of regulations on jobs (Executive Order 13777).
Employment impacts of environmental regulations are 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 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.
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 (OMB, 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, have
limited capacity to migrate, or live in communities or regions with high unemployment rates.
As rescinding the oil and natural gas NSPS for transmission and storage segment is likely to
cause little change in oil and natural gas exploration and production (and the production and
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processing segment continues to be regulated by the NSPS), demand for labor employed in
exploration and production and associated industries is unlikely to change much, if at all. For
affected oil and natural gas entities, some may reduce the labor they allocate to compliance-
related activities associated with the now-rescinded oil and natural gas NSPS requirements for
the transmission and storage segment.
2.4.4.2 Estimates of Reduction in Labor Required to Comply
The focus of this part of the analysis is on changes in the compliance-related labor requirements
resulting from the removal of the requirements for the transmission and storage segment from the
oil and natural gas NSPS. This analysis estimates the incremental change in labor required to
satisfy environmental mitigation requirements as well as reporting and recordkeeping
requirements due to the rescission of requirements for transmission and storage sources. Most of
the estimated change in labor requirements relative to the baseline come from rescinding the
fugitive emissions program for compressor stations in the transmission and storage segment.
The labor information is based on the cost analysis presented in the TSD that supports this rule.
The labor estimates include labor associated with company-level activities and activities at field
sites. Company-level activities included one-time "up-front" activities such as planning the
company's fugitive emissions program and annual requirements such as reporting and
recordkeeping. Field-level activities included inspection and repair of leaks.
Table 2-17 presents the incremental change in labor required to comply with the NSPS due to the
Policy Review at the facility level in hours per facility per year. The change in estimates for each
of the facility types reflect the following changes from the baseline:
•	Compressor Stations (in transmission and storage segment): removal of quarterly
fugitives monitoring requirements.
•	Reciprocating Compressors: removal of requirement to replace rod-packing every 36
months, or 26,000 hours.
•	Pneumatic Controllers: removal of requirement to replace high-bleed controllers with
low-bleed controllers.
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Table 2-17 Changes in Labor Required to Comply at the Impacted Facility Level
Upfront Labor Estimate	Annual Labor Estimate
(hours per facility)	(hours per facility per year)
Facility
Under the
Baseline
Under
Final
Policy
Review
Incremental
Change
Under the
Baseline
Under
Final
Policy
Review
Incremental
Change
Compressor Stations






Transmission
64
0
-64
123.2
0
-123.2
Storage
64
0
-64
227.4
0
-227.4
Compressors






Reciprocating
1
0
-1
1
0
-1
Pneumatic Controllers
0
0
0
0
0
0
Table 2-18 and Table 2-19 present estimates of the decrease in upfront and annual labor
requirements, respectively. The estimates are presented in full-time equivalent (FTE) units in
these tables; in this analysis we assume one FTE equals 2,080 hours (the product of 40 hours per
week over 52 weeks). Note that reductions in labor requirements increase from 2021 to 2030 as
the number of sites that would have been regulated under the NSPS under the baseline
accumulates.
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Table 2-18 Estimates of the Decrease in Upfront Labor Required (in FTEs) under the
Policy Review, 2021-2030	
Compressor Stations

Transmission
Storage
Reciprocating
Compressors
Pneumatic
Controllers
Recordkeeping
and Reporting
Total
2021
0.06
1.1
0.07
0
0
1.2
2022
0.06
1.1
0.07
0
0
1.2
2023
0.12
2.2
0.11
0
0
2.4
2024
0.12
2.2
0.11
0
0
2.4
2025
0.12
2.2
0.11
0
0
2.4
2026
0.12
2.2
0.11
0
0
2.4
2027
0.12
2.2
0.15
0
0
2.5
2028
0.12
2.2
0.15
0
0
2.5
2029
0.12
2.2
0.15
0
0
2.5
2030
0.12
2.2
0.15
0
0
2.5
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Estimates may not
sum due to independent rounding.
Table 2-19 Estimates of the Decrease in Annual Labor Required (in FTEs) under the
Policy Review, 2021-2030





Compressor Stations




Year
Transmission
Storage
Reciprocating
Compressors
Pneumatic
Controllers
Recordkeeping
and Reporting
Total
2021
0.8
28
0.26
0
1.7
30
2022
1.0
31
0.29
0
1.8
35
2023
1.1
35
0.33
0
1.9
39
2024
1.2
39
0.37
0
2.0
43
2025
1.3
43
0.40
0
2.1
47
2026
1.4
47
0.44
0
2.3
51
2027
1.5
51
0.48
0
2.4
56
2028
1.7
55
0.51
0
2.5
60
2029
1.8
59
0.55
0
2.6
64
2030
1.9
63
0.58
0
2.7
68
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Estimates may not
sum due to independent rounding.
The total incremental reductions in up-front labor requirements among entities affected by the
Policy Review are projected to increase from 1.2 FTE in 2021 to 2.5 FTE in 2030. The total
incremental reductions in annual labor requirements are projected to increase from about 30 to
68 FTEs from 2021 to 2030.
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We note that this type of FTE estimate cannot be used to identify the specific number of
employees involved or whether new jobs are created for new employees, versus displacing jobs
from other sectors of the economy. As stated earlier, this rule is expected to result in little change
in oil and natural gas exploration and production and is not expected to result in significant
reductions to employment dedicated to these tasks. For the affected oil and natural gas entities,
some reductions in compliance-related labor may be expected due to the rescission of
requirements for transmission and storage segment under the Policy Review. We did not estimate
any potential changes in labor outside of the affected sector. For example, no estimates of labor
requirements for manufacturing pollution control equipment, or for producing the materials used
in that equipment, are provided as the EPA did not have the information necessary for estimating
broader employment impacts.
2.5 Comparison of Benefits and Costs
2.5.1 Comparison of Benefits and Costs
In this section, we present a comparison of the benefits and costs for the Policy Review. Here,
we refer to the compliance cost reductions as the "benefits" and the forgone benefits as the
"costs" of this action. The net benefits are the benefits (compliance cost reductions) minus the
costs (forgone benefits). All benefits, costs, and net benefits shown in this section are presented
as the PV of the costs and benefits of the Policy Review from 2021 through 2030 discounted
back to 2020 using 7 and 3 discount rates. We also present the associated EAV under each
discount rate.
Table 2-20 shows the projected benefits, costs, and net benefits for the Policy Review. Table 2-
21 provides a summary of the projected forgone emissions reductions for this action.
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Table 2-20 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone
Monetized Benefits, Cost Reductions, and Net Benefits for the Policy Review, 2021-2030
(millions, 2016$)	

7 percent
3 percent

PV
EAV
PV
EAV
Benefits (Total Cost Reductions)
$31
$4.1
$38
$4.3
Cost Reductions
$67
$8.9
$83
$9.4
Forgone Value of Product Recovery
$36
$4.7
$45
$5.1
Costs (Forgone Domestic Climate Benefits)1
$17
$2.2
$63
$7.2
Net Benefits
$14
$1.9
-$25
-$2.9
Note: Estimates may not sum due to independent rounding.
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions.
Table 2-21 Summary of Forgone Emission Reductions for the Policy Review, 2021-2030
Pollutant	Policy Review
Methane (short tons)	400,000
VOC (short tons)	11,000
HAP (short tons) 330
Methane (metric tons)	360,000
Methane (million metric tons CO2 Eq.) 9.0
2.5.2 Uncertainties and Limitations
Throughout the RIA, we considered several sources of uncertainty, both quantitatively and
qualitatively, regarding the forgone emissions reductions, forgone benefits, and cost reductions
estimated for the final Policy Review. We summarize the key elements of our discussions of
uncertainty follow.
Source-level compliance costs and emissions impacts: As discussed in Section 2.2.2, the first
step in the compliance cost analysis is the development of per-facility national-average
representative costs and emissions impacts using a model plant approach. The model plants are
designed based upon the best information available to the Agency at the time of the rulemaking.
By emphasizing facility averages, geographic variability and heterogeneity across producers in
the industry is masked, and regulatory impacts at the facility-level may vary from the model
plant averages.
Projection methods and assumptions: As discussed in Section 2.2.2 and 2.2.3, the second step
in estimating national impacts is the projection of affected facilities. Uncertainties in the
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projections informing this chapter include: 1) choice of projection method; 2) data sources and
drivers; 3) limited information about rate of modification and turnover of sources; 4) behavioral
responses to regulation; and 5) unforeseen changes in industry and economic shocks.
The projection methods significantly impact affected facility projections. For example, some
facility types were projected using extrapolations of historical trends from GHGI data, while
other facility types were changed to be projected based on compliance report information. These
two methods may result in divergent projections. In addition, a given methodology can be
sensitive to regular updates or methodological revisions in the source data; for example, past
updates to the GHGI have resulted in significant changes to the projections.
Some impacts of this rule are based on projections based on historical estimates in the GHGI and
do not account for modifications or turnover, just the estimated number of new sources. To the
extent actual counts of new facilities in transmission and storage diverge from the historical
average annual increases, the regulatory impacts estimated in this document will be inaccurate.
Additionally, some emissions reducing technologies have become common industry practice
under the oil and natural gas sector NSPS, such as the use of dry seals on centrifugal
compressors. However, by removing regulatory requirements, there may be incentives to reduce
use of these technologies, introducing uncertainties in how regulated entities may respond both
directly and indirectly to the removal of NSPS requirements.
The projections do not account for potential changes in technological progress in the oil and gas
industry. Additionally, unforeseen economic shocks may affect the impacts of the rule, such as
unexpected periods of economic growth or recessions. For example, the projections in this RIA
do not account for potential effects of economic shocks arising from the coronavirus pandemic.
Years of analysis: The years of analysis are 2021, to represent the first-year facilities are
affected by this action, through 2030, to represent impacts of the rule over a longer period, as
discussed in Section 2.2.2. While it would be desirable to analyze impacts beyond 2030 in this
RIA, the EPA has chosen not to do this largely because of the limited information available on
the turnover rate of emissions sources and controls. Extending the analysis beyond 2030 would
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introduce substantial and increasing uncertainties in the projected impacts of the final Policy
Review.
State regulations in the baselines for this analysis: As discussed in Section 2.1.1, with the
information currently available, we are unable to determine where newly affected sources in the
transmission and storage segment are expected to locate. Though there may be states with similar
requirements to those of the oil and natural gas NSPS for the transmission and storage segment,
we are unable to account for such situations in this analysis. Applicable facilities in these states
with similar requirements will still be expected to follow state regulations. This analysis likely
overestimates the compliance cost reduction from sources in transmission and storage because it
includes estimates of incrementally affected facilities that would have similar state-level
requirements under the baseline that will continue to apply to these facilities despite this rule.
Wellhead natural gas prices used to estimate forgone revenues from natural gas recovery:
The compliance cost reductions estimates presented in this RIA include the forgone revenue
associated with the decrease in natural gas recovery resulting from the decrease in emissions
reductions. As a result, the national compliance cost reductions depend on the price of natural
gas. As explained in Section 2.2.5, natural gas prices used in this analysis are from the projection
of the Henry Hub price in the 2020 AEO. To the extent actual natural gas prices diverge from the
AEO projections, the actual impacts will diverge from our estimates.
Monetized forgone methane-related climate benefits: The EPA considered the uncertainty
associated with the social cost of methane (SC-CH4) estimates, which were used to calculate the
forgone domestic social benefits of the increase in methane emissions expected as a result of this
action. The potential impacts of some uncertainties are accounted for in the analysis or discussed
quantitatively, while other areas of uncertainty have not yet been quantified in a way that can be
modeled. Section 2.3.3 and Appendix B provide detailed discussions of the ways in which the
modeling underlying the development of the SC-CH4 estimates used in this analysis addresses
quantified sources of uncertainty and presents a sensitivity analysis to show consideration of the
uncertainty surrounding the choice of discount rate over long time horizons.
Non-monetized forgone benefits: Several categories of forgone health, welfare, and climate
benefits are not quantified in this RIA. These unquantified forgone benefits, in addition to the
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forgone benefits from increased emissions of methane, VOCs and HAP, are described in detail in
Section 2.3.
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3, 2019.
U.S. Environmental Protection Agency (U.S. EPA). 201 I c. Regulatory Impact Analysis for the
Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and
Ozone in 27 States; Correction of SIP Approvals for 22 States. Office of Air Quality
Planning and Standards, Research Triangle Park, NC. July. Available at:
. Accessed
April 3, 2019.
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U.S. Environmental Protection Agency (U.S. EPA). 2012a. Residual Risk Assessment for the Oil
and Gas Production and Natural Gas Transmission and Storage Source Categories. Office
of Air Quality Planning and Standards, Research Triangle Park, NC.
U.S. Environmental Protection Agency (U.S. EPA). 2012b. Regulatory Impact Analysis for the
Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. EPA-
452/R-I2-003. Office of Air Quality Planning and Standards, Health and Environmental
Impacts Division. December. Available at: . Accessed April 3, 2019.
U.S. Environmental Protection Agency (U.S. EPA). 2013. Integrated Science Assessment of
Ozone and Related Photochemical Oxidants (Final Report). U.S. Environmental Protection
Agency, Washington, DC, EPA/600/R-10/076F. February. Available at:
. Accessed April
3, 2019.
U.S. Environmental Protection Agency (U.S. EPA). 2014. Regulatory Impact Analysis for the
Proposed Ozone NAAOS. U.S. Environmental Protection Agency, Research Triangle Park,
NC, EPA-452/P-14-006. December. Available at:
. Accessed April 3, 2019.
U.S. Environmental Protection Agency (U.S. EPA). 2016. Guidelines for Preparing Economic
Analyses. Office of the Administrator. Available at: . Accessed January 9, 2020.
U.S. Environmental Protection Agency—Science Advisory Board (U.S. EPA-SAB). 2002.
Workshop on the Benefits of Reductions in Exposure to Hazardous Air Pollutants:
Developing Best Estimates of Dose-Response Functions An S AB Workshop Report of an
EPA/SAB Workshop (Final Report). EPA-SAB-EC-WKSHP-02-001. January. Available at:
. Accessed April 3, 2015.
U.S. Environmental Protection Agency—Science Advisory Board (U.S. EPA-SAB). 2008.
Benefits of Reducing Benzene Emissions in Houston, 1990-2020. EPA-COUNCIL-08-001.
July. Available at:
.
Accessed April 3, 2019.
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U.S. Office of Management and Budget. 2003. "Circular A-4, Regulatory Analysis". Available
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Accessed April 4, 2019.
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Costs of Federal Regulations and Agency Compliance with the Unfunded Mandates Reform
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. Accessed May 8, 2020.
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the Racial and Socio-Economic Characteristics of Communities with Hazardous Waste Sites.
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Incidence of a Carbon Tax across Income Groups." National Tax Journal, 68(1): 195-214.
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3 REGULATORY IMPACT ANALYSIS FOR THE OIL AND NATURAL GAS
SECTOR: THE EMISSION STANDARDS FOR NEW, RECONSTRUCTED,
AND MODIFIED SOURCES RECONSIDERATION
3.1 Introduction
This chapter presents the RIA for the final technical reconsideration of certain aspects of the Oil
and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources
published in the Federal Register on June 3, 2016 ("2016 NSPS OOOOa"), referred to as the
"Technical Reconsideration" in this chapter and document as a whole. In the 2016 NSPS
OOOOa, new source performance standards (NSPS) were established to reduce greenhouse gas
emissions and volatile organic compound (VOC) emissions from the oil and natural gas sector.
The emission sources covered in the 2016 rule include hydraulically fractured oil and natural gas
well completions, centrifugal compressors, reciprocating compressors, pneumatic controllers,
storage vessels, equipment leaks at natural gas processing plants, sweetening units, pneumatic
pumps, and fugitive emissions from well sites and compressor stations. In the action evaluated in
this chapter, the EPA granted reconsideration of three aspects of the 2016 rule: fugitive
emissions monitoring requirements, well site pneumatic pump standards, and requirements for
certification of closed vent system design and capacity by a professional engineer. In addition,
the EPA clarified definitions and reconsidered several issues to streamline implementation and
improve cost-effectiveness of compliance.
In this chapter, we focus on the finalized changes to NSPS OOOOa that result in quantifiable
compliance cost or emissions changes compared to a baseline that includes the Policy Review.58
As described in Chapter 2 of this document, the Policy Review rescinds the requirements of the
2012 NSPS OOOO and the 2016 NSPS OOOOa for oil and natural gas sources in the
transmission and storage segment. The Policy Review also rescinds the methane standards for
sources in the production and processing segments, while leaving VOC requirements in place for
production and processing sources. As a result, the RIA for the Technical Reconsideration
58 The Technical Reconsideration rule was proposed (October 15, 2018) before the Policy Review was proposed
(September 24, 2019). Due to the sequencing of the proposals, the RIA for the proposal of the Technical
Reconsideration estimated impacts relative to a baseline that did not include consideration of elements of the
later Policy Review proposal.
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presented in this Chapter does not evaluate regulatory impacts to previously NSPS-affected
sources in transmission and storage. Sequencing the two actions in this way—with the
conclusions of the Policy Review in the baseline for the Technical Reconsideration—is
consistent with the sequencing applied in the preamble and amended regulatory text for the two
final actions.
The provisions analyzed in this chapter are related to fugitive emissions monitoring and
professional engineer certification requirements. We do not analyze all finalized changes to
NSPS OOOOa that are discussed in the preamble for the Technical Reconsideration because we
either do not have the data to do so or because we have concluded that certain provisions are
unlikely to result in measurable cost reductions or changes in emissions. Section 3.2.1 provides a
basic description of the additional reconsidered provisions that are not quantified in the RIA. For
additional details on these provisions, see the preamble to the Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources Reconsideration, found in
the docket.59
The 2016 NSPS OOOOa required all NSPS-affected well sites to perform semiannual
monitoring and all NSPS-affected compressor stations to perform quarterly monitoring. On
March 1, 2018, the EPA finalized a package containing amendments to the 2016 NSPS OOOOa
(hereon, "Amendments package") to address immediate concerns regarding implementation
issues related to the reliability of emissions monitoring equipment during extended periods of
extreme cold temperatures on the Alaska North Slope.60 The Amendments package reduced
monitoring frequency at NSPS-affected well sites on the Alaska North Slope from semiannual to
annual. In this final action, the EPA is reducing the required monitoring frequency at NSPS-
affected compressor stations on the Alaska North Slope from quarterly to annual. We are unable
to quantify the emissions impacts or cost reductions associated with this change for compressor
stations on the Alaska North Slope due to a lack of data.61
59	Found on http://www.regulations.gov under Docket ID No. EPA-HQ-OAR-2017-0483.
60	83 FR 10628.
61	The Amendments package did not change the fugitive emissions requirements for compressor stations located on
the Alaska North Slope because there were no NSPS-affected compressor stations at the time, and therefore there
was no immediate compliance issue to address (see 83 FR 10635). In this final action, EPA is aligning the
fugitive emissions requirements for compressor stations with the changes made in the 2018 Amendments
package for well sites on the Alaska North Slope. Nevertheless, there is still no indication that there are any
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In the 2016 NSPS OOOOa, the EPA finalized a requirement for closed vent systems (CVS) for
NSPS-affected storage vessels, pneumatic pumps, reciprocating compressors, and centrifugal
compressors to be certified by a professional engineer. In addition, the EPA finalized a
requirement for well site sources claiming that feasibility issues constrain their ability to route
pneumatic pump emissions to a control device. The 2016 NSPS required such sources to obtain a
certification of technical infeasibility from a "qualified professional engineer." The compliance
costs for these engineering certifications were not considered in the rulemaking for the 2016
NSPS OOOOa. For this final action, the EPA estimates and includes those compliance costs in
the updated baseline and assesses the impact of a change being finalized which allows technical
infeasibility certifications and CVS certifications to be performed by either in-house engineers or
professional engineers.
This analysis projects the impacts of the Technical Reconsideration for the years 2021 through
2030. All monetized impacts are presented in 2016 dollars. This analysis also includes a
presentation of the impacts in a present value (PV) framework. All sources affected by the 2016
NSPS OOOOa are referred to as "NSPS-affected sources." The subset of sources whose
requirements are altered by the Technical Reconsideration of the 2016 NSPS OOOOa are
referred to as "reconsideration-impacted sources." Note that the universe of reconsideration-
impacted sources varies across the regulatory options considered in this RIA.
3.1.1 Summary of Changes Since the Final 2016 NSPS RIA
This RIA applied several updates to the data, assumptions, source counts, projections, and
baseline state and local regulations since finalizing the 2016 NSPS OOOOa. The projected
compliance cost and emission impacts of the three options analyzed in this RIA are compared to
an updated baseline that includes the Policy Review. These updates include the incorporation of
information received during the public comment period for the proposal of this Technical
Reconsideration.62 Other than the updates noted below, the baseline used in this RIA was
determined using the same assumptions and methods as the 2016 NSPS RIA. The updated
baseline represents the EPA's best assessment of the current and future state of the industry and
compressor stations on the Alaska North Slope currently subject to the 2016 NSPS OOOOa fugitive emissions
requirements, nor is EPA able to project potential new or modified compressor stations in specific locations.
62 See preamble and response to comments document, which are available in the docket.
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economy. The changes in the following list were included in the RIA for the proposal of this
Technical Reconsideration action. We also indicate the updates in this final RIA made since the
proposal RIA.
•	Annual Energy Outlook: In the 2016 NSPS OOOOa, we used the 2015 Annual Energy
Outlook (AEO). For the proposal of this Technical Reconsideration, we used the
AEO2018. We use the most recent AEO in this RIA, the AE02020, published in January
2020.63 The drilling activity projections in the AE02020 are used to project the number
of NSPS-affected sources over time, and the AE02020 projections for natural gas prices
are used to estimate the value of product recovery in this RIA.
•	Source Projections: Since the promulgation of the 2016 NSPS OOOOa, the U.S.
Greenhouse Gas Inventory (GHGI) has been updated.64 The data from the updated GHGI
was used in the projection of NSPS-affected sources over time. In addition, for a few
sources, we relied on information from 2016 NSPS OOOOa compliance reports to inform
our projections.
•	Drillinglnfo: This RIA uses a more recent version of the Drillinglnfo data, which is used
to characterize oil and natural gas wells and completion activity in the base year, than
was used for the 2016 NSPS OOOOa.65 The version used for this analysis was pulled in
January 2017 and uses 2014 as the base year. The base year was 2012 in the 2016 NSPS
OOOOa RIA.
•	State and Local Regulations: Since the promulgation of the 2016 NSPS OOOOa, state
and local authorities have issued requirements affecting the oil and natural gas sector,
with the most significant changes resulting from new regulations in California and
general permitting requirements in Pennsylvania. In this analysis, we account for updated
requirements in California, Colorado, Ohio, Pennsylvania, Texas,66 and Utah. Updated
requirements for some facilities in these states are expected to result in similar emissions
reductions to those expected from the 2016 NSPS OOOOa and this reconsideration,
though the programs in these states function differently than the 2016 NSPS OOOOa and
this reconsideration. In the RIA for the 2016 NSPS, it was determined that the rule would
not achieve additional emissions reductions in Wyoming relative to those that would
already be achieved by the state program. The requirements in Wyoming were re-
examined and are no longer considered to function in a way that reduces emissions by as
63	AE02020 can be found at https://www.eia.gov/outlooks/aeo/.
64	The updated GHGI data used is from the April 2018 release. For information on the inventory, visit
https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks.
65	Drillinglnfo is a private company that provides information and analysis to the energy sector. More information is
available at http://info.drillinginfo.com.
66	EPA proposed that certain fugitive emissions monitoring-related permits in Texas would be considered
equivalent, but not all types of permits. At proposal, EPA did not have quantitative information on the share of
Texas permits that, as proposed, would be considered equivalent. Information received during the public
comment period for this action provides EPA with a basis to perform quantitative analysis for Texas facilities in
this RIA. EPA also received additional information of the share of facilities in Ohio that whose fugitive
emissions monitoring-related emissions requirements would be considered equivalent to NSPS OOOOa
requirements.
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much as the NSPS requirements, as Wyoming has facility-specific permit requirements,
so requirements are not uniform across the entire state.67
•	Fugitive Emissions Monitoring Requirements: Since the promulgation of the 2016
NSPS OOOOa, the EPA finalized a package amending fugitive emissions monitoring
requirements for NSPS-affected oil and natural gas well sites on the Alaska North Slope.
The updated baseline used in this RIA accounts for the impacts of the Amendments
package, which reduced the frequency of fugitive emissions monitoring requirements for
NSPS-affected well sites on the Alaska North Slope from semiannual to annual.
•	Professional Engineer Certification: The 2016 NSPS OOOOa requires that claims of
technical infeasibility for pneumatic pump control requirements and requires the design
and operation of CVS be certified by a professional engineer. The cost of this
certification requirement was not quantified in the 2016 NSPS RIA. In this analysis, the
baseline includes the cost of complying with the professional engineer certification
requirement.
•	Social Cost of Methane: In the 2016 NSPS OOOOa, the EPA used an estimate of the
global social cost of methane to monetize the climate related benefits associated with
reductions in methane emissions. Since the promulgation of the 2016 NSPS OOOOa,
Executive Order (E.O.) 13783 has been signed, which directs agencies to ensure that
estimates of the social cost of greenhouse gases used in economic analyses are consistent
with the guidance contained in the Office of Management and Budget (OMB) Circular A-
4, "including with respect to the consideration of domestic versus international impacts
and the consideration of appropriate discount rates" (E.O. 13783, Section 5(c)). Thus, for
this reconsideration, we use an interim estimate of the domestic social cost of methane to
quantify the forgone climate benefits resulting from the increase in methane emissions
due to this final action.
•	Model Plants: The EPA uses model plants to estimate emissions from well sites and
emission reductions due to the fugitive emissions monitoring requirements. Some
assumptions used for the model plants have been updated since the 2016 NSPS. The
update includes the addition of fugitive emissions components, namely storage vessels.
By adding storage vessels to the model plant, the estimates of baseline emissions from
well sites are larger, and the reductions attributed to monitoring and repair requirements
are larger than those based on the model plants used in the 2016 NSPS RIA.68
•	Other: In the 2016 NSPS OOOOa, impacts were presented in 2012 dollars. In this RIA
and the RIA for the proposal of the Technical Reconsideration, impacts are presented in
67	For information on additional states that were examined and why they are not considered equivalent, see the TSD
and the memo "Equivalency of State Fugitive Emissions Programs for Well Sites and Compressor Stations to
Standards at 40 CFR Part 60, Subpart OOOOa", both of which are available in the docket.
68	For more information on the model plants, see the TSD. The number and type of fugitive emissions components
located at well sites and compressor stations can consist of a large variety of combinations of process equipment
and other components. Model plants were developed be varying the number and types of components and other
equipment based on data available to the EPA, including the Drillinglnfo database, the 1996 EPA/GRI Study, the
EPA's GHG Inventory for 2017, the EPA's GHG Mandatory Reporting Rule (40 CFR part 98, subpart W), and
information received in public comments. The number and types of components are associated with emissions
factors to estimate uncontrolled emissions for the model plants.
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2016 dollars.69 In the 2016 NSPS RIA, we presented regulatory impacts for the snapshot
years of 2020 and 2025. For this analysis, we estimate cost reductions and emissions
impacts resulting from changes in compliance activities projected to occur in each year
from 2021 through 2030 due to this final action.70 Impacts are discounted to 2020. We
present the PV and equivalent annualized value (EAV) of impacts from this Technical
Reconsideration over the analysis period.71
3.1.1.1 Updated Baseline for the Technical Reconsideration
Table 3-1 below shows the projected number of NSPS-affected sources, methane emission
reductions, VOC emission reductions, and the total annualized compliance costs, including the
value of product recovery, in 2021 and 2025 for the 2016 NSPS OOOOa fugitive emissions
monitoring requirements for sources in the production and processing segment as estimated in
the 2016 NSPS RIA, and under the updated baseline used in this RIA (elsewhere in this
document simply referred to as "the baseline"). We compare the different baseline projections
for years 2021 and 2025 because those are the earliest and latest years in which the 2016 NSPS
RIA analysis horizon and the Technical Reconsideration analysis horizon overlap. We exclude
the impacts of other provisions in the 2016 NSPS OOOOa in order to highlight the differences in
the estimated impacts of the fugitive emissions monitoring requirements between the 2016 RIA
baseline and the updated baseline used in this final RIA. Also, to be consistent with the
presentation of impacts in the 2016 RIA, the updated baseline estimates in Table 3-1 exclude the
compliance costs associated with the professional engineer certification requirement.
69	Costs were adjusted to 2016 dollars using the seasonally adjusted annual Gross Domestic Product: Implicit Price
Deflator released by the Federal Reserve on January 26, 2018.
70	In this analysis, the Drillinglnfo base year was updated from 2012 to 2014. Therefore, the source projection
estimates are based on reconsideration-impacted facilities established starting in 2014 and continuing through
2030.
71	The Technical Reconsideration proposal RIA discounted the PV of impacts to 2016. In this RIA, we discount the
PV to 2020 to improve interpretability.
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Table 3-1 Estimated Compliance Costs and Emission Reductions of the 2016 NSPS
OOOOa Fugitive Emissions Monitoring Requirements in the Production and Processing
Segment: 2016 NSPS RIA and Updated Baseline Comparison	

2016 NSPS RIA
Updated Baseline

2021
2025
2021
2025
Counts of NSPS-Affected Fugitive Emissions
Monitoring Sources1
130,000
210,000
62,000
110,000
Methane Emission Reductions (short tons)
230,000
370,000
100,000
170,000
VOC Emission Reductions (tons)
64,000
100,000
29,000
47,000
Total Annualized Compliance Cost, without
Product Recovery (7%, millions 2016$)2
$330
$530
$150
$260
Total Annualized Compliance Cost, with
Product Recovery (7%, millions 2016$)2
$280
$440
$140
$230
1	The difference in the number of sources is due to updated source count projections based on the GHGI and
compliance reports.
2	Excluding compliance cost of professional engineer certification, as well as other provisions in the 2016 NSPS
OOOOa unrelated to fugitive emissions monitoring requirements.
The difference in the estimates stems from a couple of factors. First, the updated baseline
includes the Amendments package change to the frequency of fugitive emissions monitoring
requirements for well sites on the Alaska North Slope, as explained above. Second, the
assumptions used for the updated baseline have been updated from the 2016 NSPS RIA as
explained above (e.g., the facility-count and natural gas price projections, state and local
regulations, and model plant characteristics). Moreover, the costs associated with the 2016 NSPS
OOOOa in Table 3-1 do not match the compliance cost estimates for the fugitive emissions
monitoring requirements presented in the 2016 NSPS RIA. This is because costs in the 2016
NSPS RIA were in 2012 dollars, and they have been updated to 2016 dollars in this RIA.
3.1.2 Summary of Changes Based on Information Received During Comment Period
The following list summarizes the changes in this RIA made based on information received
during the public comment period for the proposed Technical Reconsideration:
•	Extended final year of analysis from 2025 to 2030: The RIA for the proposal evaluated
impacts from 2019 to 2025. In response to comments, we extend the analysis period in
this RIA to 2030. Since this action is being finalized in 2020, we present impacts from
2021 to 2030, as 2021 is expected to be the first year the rule is implemented.
•	Projection of wells sites transitioning to low production status: In the final rule, the
EPA is allowing an option for well site owners or operators to determine when the total
production for the well site falls to 15 barrels of oil equivalent (boe) per day or lower,
calculated as a rolling 12-month average. If the well site was previously subject to the
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fugitive emissions monitoring requirements and total well site production falls to or
below this threshold, then the owner or operator has the option to stop monitoring and
instead maintain total well site production below this threshold. In order to estimate the
impacts of this provision, we model the transition of a well site to low production using
historical well information. More detail on this is presented in Section 3.2.3.
•	Streamlined recordkeeping and reporting requirements: This final rule amends
recordkeeping and reporting requirements for well completions and fugitive emissions for
well sites and compressor stations. For well completions, the number of data fields
required to be recorded and reported have been reduced. For fugitive emissions, this rule
includes several changes intended to streamline recordkeeping and reporting, including
replacing the sitemap and observation path requirement with other procedures that ensure
that all components are monitored during each survey.72 Based on public comments
received, we revised our estimates of recordkeeping and reporting costs associated with
the fugitive emissions requirements, as well as our estimates of the cost burden associated
with developing and updating the sitemap and observation path.
We do not expect the changes to recordkeeping and reporting requirements to affect
emissions. For some line items, requirements were determined to be redundant. For the
site map and observation path, flexibility is now available for sources to use other
methods of compliance with the primary objective, which is that all components are
monitored during a survey. Details on the costs of recordkeeping and reporting
requirements for fugitive emissions can be found in Section V.B of the preamble.
•	Alternative fugitive emissions standards for sites located in certain states: The final
rule includes alternative fugitive emissions standards for well sites and compressor
stations located in specific states based on the EPA's review of those state programs and
our conclusion that they are equivalent to the fugitive emissions requirements in NSPS
OOOOa. These states are California, Colorado, Ohio, Pennsylvania, Texas, and Utah.73
Alternative fugitive emissions standards may be adopted in lieu of the NSPS fugitive
emissions monitoring and repair requirements at individual well sites or compressor
stations that are regulated under these state programs. A well site or compressor station
regulated under an alternative fugitive emissions standards could comply with state
standards for monitoring, repair, recordkeeping, and reporting in lieu of the requirements
for those activities in the NSPS provided they still follow the monitoring plan
requirements and monitor all fugitive emissions components as defined in the NSPS.
72	See Section IV.I of the preamble for a comprehensive summary of changes to recordkeeping and reporting
requirements.
73	We determined that all well sites and compressor stations in four states (California, Colorado, Pennsylvania, and
Utah) were subject to state requirements at least as effective as the NSPS OOOOa at reducing emissions. As
noted above, at proposal, the EPA did not have quantitative information on the share of Texas permits that, as
proposed, would be considered equivalent. Information received during the public comment period for this
action provided EPA with a basis to perform quantitative analysis for Texas facilities in this RIA. EPA also
received additional information of the share of facilities in Ohio whose fugitive emissions monitoring
requirements would be considered equivalent to NSPS OOOOa requirements. Based on analysis received in
public comment, we assume that 5.5 percent of sites in Texas and 80 percent of sites in Ohio would qualify for
an alternative fugitive emissions standard. All sources in the remaining states listed are assumed to need to
comply with the fugitive emissions monitoring requirements in NSPS OOOOa.
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The compliance cost reductions associated with this flexibility for the states above were
not quantified in the RIA for the proposal of this reconsideration. Based on public
comments and a review of the final provisions in this rule, we estimated compliance cost
reductions for otherwise NSPS-affected sources in the states listed above assuming they
will have reduced annual costs associated with reporting and recordkeeping. The cost
reductions associated with the alternative fugitive emissions standards flexibility are not
applied retroactively since we assume that the recordkeeping and reporting costs
associated with NSPS OOOOa compliance to date have already been incurred.
• Engineering certifications for closed vent systems: The final rule includes changes
from the proposal in the assumptions for the costs and number of certifications required
for closed vent systems. Based on information received in public comments, we revised
the labor costs assumed for both professional and in-house engineers upward.
Commenters noted that the EPA had underestimated the time required to certify closed
vent systems and the had not accounted for the costs associated with obtaining expertise
from a third-party service with region and location-specific knowledge. In addition, based
on our review of compliance reports, the projected number of facilities requiring
certifications decreased compared to the RIA for the proposal.
3.1.3 Regulatory Options
The universe of reconsideration-impacted sources includes sources considered new or modified
starting in 2021, as well as sources that were affected by the 2016 NSPS OOOOa before 2021
which are expected to change compliance activity due to this Technical Reconsideration. As we
assume that engineer certifications only happen once, the only sources affected by the final
changes to the certification requirements are those that are affected starting in 2021, the year this
rule is expected to take effect.
We also examine two more stringent alternative regulatory options that were not finalized. The
universe of reconsideration-impacted sources may change under the different options. Table 3-2
shows the emissions points and regulatory requirements for affected sources under the 2016
NSPS OOOOa, the updated baseline, and the three options analyzed in this RIA.
The 2016 NSPS OOOOa requires semiannual (twice per year) fugitive emissions surveys and
repairs to be performed at NSPS-affected well sites, and quarterly surveys at gathering and
boosting compressor stations.74 Further, as previously stated, the 2016 NSPS OOOOa requires
74 The 2016 NSPS OOOOa requires quarterly monitoring at all NSPS-affected compressor stations (i.e., gathering
and boosting, transmission, and storage compressor stations). For purposes of this analysis, the baseline used
reflects the removal of requirements for transmission and storage compressor stations, therefore, this analysis is
limited to gathering and boosting compressor stations.
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professional engineer certifications of closed vent systems and for any claim that it is technically
infeasible to control pneumatic pump emissions.
Table 3-2 Emissions Sources and Controls Evaluated by Regulatory Alternative
Emissions Point
2016 NSPS
OOOOa
Updated
Baseline
Option 1
Option 2
Option 3
(Finalized)
Fugitive Emissions Monitoring
Natural Gas and Oil Well
Sites
Natural Gas and Oil Well
Sites - Low Production
Compressor Stations in
Gathering and Boosting
The Alaska North Slope
Natural Gas and Oil Well
Sites (Alaska North Slope)
Natural Gas and Oil Well
Sites (Alaska North Slope) -
Low Production
Compressor Stations in
Gathering and Boosting
(Alaska North Slope)1
Alternative Means of
Emission Limitation
Certifications
Closed Vent Systems on
Pneumatic Pumps,
Reciprocating Compressors,
Centrifugal Compressors, and
Storage Vessels; and
Pneumatic Pump Technical
Infeasibility	
Semiannual Semiannual
Semiannual Semiannual
Quarterly Quarterly
Semiannual
Semiannual
Quarterly
None
Annual
Annual
Quarterly
None
Professional
Engineer
Semiannual-
streamlined
Semiannual-
streamlined
Quarterly-
streamlined
Annual-
streamlined
Annual-
streamlined
Annual-
streamlined
Professional
Engineer
In-House
Engineer
Semiannual-
streamlined
No
Monitoring
Quarterly-
streamlined
Annual-
streamlined
No
Monitoring
Annual-
streamlined
Semiannual -
streamlined
No
Monitoring
Semiannual-
streamlined
Annual-
streamlined
No
Monitoring
Annual-
streamlined
Operations Operations Operations in
in Six States in Six States Six States
In-House
Engineer
In-House
Engineer
1 We do not currently have data to estimate the effects of this final action for gathering and boosting stations on the
Alaska North Slope. All other provisions presented in this table are analyzed in this RIA.
The baseline reflects finalized NSPS OOOOa requirements as of 2020, including that fugitive
emissions survey and repair programs are now required to be performed annually at NSPS-
affected well sites in the Alaska North Slope due to the Amendments package, semiannually at
all other NSPS-affected well sites, and quarterly at gathering and boosting stations. Professional
engineer certifications are required for closed vent systems and pneumatic pumps in the baseline.
Option 1 (not selected for promulgation): Option 1 is the most stringent alternative assessed in
this RIA. Option 1 retains annual monitoring and repair frequency for affected well sites on the
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Alaska North Slope and reduces the monitoring frequency for affected compressor stations on
the Alaska North Slope. The semiannual survey and repair requirements are retained for all other
NSPS-affected well sites. Quarterly monitoring is retained at all other NSPS-affected gathering
and boosting compressor stations. Under this option, recording and recordkeeping requirements
at all NSPS-affected sources subject to fugitive emissions monitoring requirements are
streamlined. The certification requirement for closed vent systems and pneumatic pump technical
infeasibility is changed to allow companies the option of using an in-house engineer as opposed
to a professional engineer.75 Also, fugitive emissions monitoring programs in six states are
certified as alternatives, which reduces reporting and recordkeeping burden but does not affect
emissions. In aggregate, unselected Option 1 would likely reduce regulatory compliance costs
while having no quantifiable impacts on the emissions reductions projected for the 2016 rule.76
Option 2 (not selected for promulgation): This option is less stringent than Option 1. Under the
option, monitoring frequencies are semiannual for well sites, excluding well sites with total
combined oil and natural gas production at or below 15 boe per day (i.e., "low production well
sites"), quarterly for gathering and boosting compressor stations, and annual for well sites and
compressor stations located on the Alaska North Slope. The option rule excludes fugitive
emissions monitoring for low production well sites. Instead, low production well sites are
required to maintain total well site production at or below 15 boe per day and maintain records.
Additionally, the option allows fugitive monitoring to stop when all major production and
processing equipment is removed from a well site such that it becomes a wellhead-only well site;
however, the EPA does not have information on the potential number of sites this provision
applies to and, as a result, cannot estimate the associated regulatory impacts. Reporting and
recordkeeping requirements at all NSPS-affected sources subject to fugitive emissions
monitoring requirements are streamlined. The certification requirement for closed vent systems
and pneumatic pump technical infeasibility is changed to allow companies the option of using an
75	Emissions should not be affected by this change in certification requirements to the extent that the use of an in-
house engineer does not result in any change in the closed vent systems being certified or the number of technical
infeasibility determinations for pneumatic pumps. We are not able to estimate the potential, if any, for such technical
changes from allowing in-house engineer certifications.
76	Reducing monitoring frequency for affected compressor stations on the Alaska North Slope results in reduced
regulatory burden related to the reduced monitoring frequency. However, as EPA does not currently have the data to
estimate the effects of the final action pertaining to compressor stations on the Alaska North Slope, this RIA does
not present quantitative estimates of reduced regulatory compliance costs or potential emissions increases associated
with these changes for compressor stations on the Alaska North Slope.
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in-house engineer as opposed to a professional engineer. Also, fugitive emissions monitoring
programs in six states are certified as alternatives, reducing reporting and recordkeeping burden
for some sources.
Option 3 (finalized): Option 3 the least stringent option analyzed in this RIA. The finalized
Option 3 is the same as Option 2 except for the monitoring frequency at gathering and boosting
compressor stations is reduced to semiannual. This results in higher cost reductions relative to
the baseline and increased forgone emissions reductions.
In addition to the requirements listed in Table 3-2, the 2016 NSPS OOOOa contains well
completion requirements for a subset of newly completed oil wells that are hydraulically
fractured or refractured. The 2016 NSPS OOOOa also requires reductions from centrifugal
compressors, reciprocating compressors, pneumatic controllers, storage vessels, equipment leaks
at natural gas processing plants, and sweetening units throughout the crude oil and natural gas
production source category. These requirements are not analyzed in this RIA because they are
not affected by this Technical Reconsideration, and thus the compliance cost and emissions
impacts from these 2016 requirements are not altered due to this reconsideration.
3.1.4 Technical Reconsideration: Summary of Key Results
A summary of the key results is shown below. All estimates are in 2016 dollars. Also, all
compliance costs, emissions changes, and benefits are estimated relative to a baseline that
includes the Policy Review. We estimate that the Technical Reconsideration will potentially
affect up to approximately 537 firms.77
• Emissions Analysis: The Technical Reconsideration is projected to result in forgone
methane emission reductions of 19,000 short tons in 2021 and 75,000 short tons in 2030
and a total of 450,000 short tons from 2021 to 2030. Forgone VOC emission reductions
are projected to be 5,200 short tons in 2021 and 21,000 short tons in 2030 and a total of
120,000 short tons from 2021 to 2030. Forgone HAP emissions are projected to be 200
77 We estimate the number of firms potentially affected firms using information in the Information Collection
Request (ICR) Supporting Statement associated with this rulemaking. Before promulgating the Policy Review,
the EPA estimates that up to 575 firms would be subject to NSPS OOOOa during the 3-year period covered by
the ICR (Table Id of the Supporting Statement). We then estimate that up to 537 respondents per year will be
subject to NSPS OOOOa during the 3-year period covered by the ICR (Section 6(d) of the Supporting
Statement). The estimate of 537 firms potentially affected by the technical reconsideration should be viewed as
an upper bound as some firms affected by NSPS OOOOa may be subject to requirements that are unchanged by
this action.
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short tons in 2021 and 790 short tons in 2030 and a total of 4,700 short tons from 2021 to
2030.
Benefits Analysis: The Technical Reconsideration is projected to result in forgone
climate, health, and welfare benefits. The PV of the domestic forgone climate benefits,
using an interim estimate of the domestic social cost of methane (SC-CH4) and
discounting at a 7 percent rate is $19 million from 2021 to 2030. The EAV is estimated to
be $2.5 million per year. Using the interim SC-CH4 estimate based on the 3 percent rate,
the PV of forgone domestic climate benefits is estimated to be $71 million; the EAV is
estimated to be $8.1 million per year. The EPA expects that forgone VOC emission
reductions will negatively affect air quality and likely affect health and welfare adversely
due to impacts on ozone, PM2.5, and HAP, but we are unable to quantify these effects at
this time. This omission does not imply that these forgone benefits do not exist.
Compliance Cost Analysis: The Technical Reconsideration is projected to result in
compliance cost reductions. The PV of the compliance cost reductions associated with
this final rule over the 2021 to 2030 period is estimated to be $800 million (2016$) using
a 7 percent discount rate and $1 billion using a 3 percent discount rate. The EAV of these
cost reductions is estimated to be $110 million per year using a 7 percent discount rate
and $110 million per year using a 3 percent discount rate. These estimates do not include
the forgone producer revenues associated with a decrease in the recovery of saleable
natural gas due to this final action, as some of the compliance actions required in the
baseline would likely have captured saleable product that would have otherwise been
emitted. Using the 2020 Annual Energy Outlook (AEO) projection of natural gas prices
to estimate the value of the change in the recovered gas at the wellhead expected to result
from this action, the EPA estimated a PV of regulatory compliance cost reductions of the
final rule over the 2021 to 2030 period of $750 million using a 7 percent discount rate
and $950 million using a 3 percent discount rate. The corresponding estimates of the
EAV of cost reductions after accounting for forgone product recovery revenues are $100
million per year using a 7 percent discount rate and $110 million per year using a 3
percent discount rate.
Energy Markets Impacts Analysis: The 2016 NSPS RIA estimated small (less than 1
percent) impacts on energy production and markets. The EPA expects that the
deregulatory Technical Reconsideration will reduce energy market impacts of the NSPS.
Distributional Impacts: The cost reductions and any forgone benefits likely to arise
from the Technical Reconsideration are not expected to be distributed uniformly across
the population, and may not accrue equally to the same individuals, firms, or
communities impacted by the 2016 rule. The EPA did not conduct a quantitative
assessment of the distributional impacts of the final Technical Reconsideration, but we
provide a qualitative discussion of the distributional aspects of the cost reductions and the
forgone health benefits.
Small Entity Impacts Analysis: The EPA expects this final deregulatory action to
reduce the small entity impacts estimated in the RIA for the 2016 NSPS OOOOa. We
therefore find that this final action will relieve regulatory burden for small entities
affected by this final action and thus will not have a Significant Impact on a Substantial
Number of Small Entities (SISNOSE).
Employment Impacts Analysis: The EPA expects reductions in labor associated with
compliance-related activities due to this action. The EPA estimated the labor impacts due
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to the forgone installation, operation, and maintenance of control equipment and control
activities, as well as the reductions in labor associated with reduced reporting and
recordkeeping requirements. The EPA estimated one-time and continual, annual labor
requirements by estimating hours of labor required for compliance and converting this to
full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52
weeks). The reduction in one-time labor needed to comply with the NSPS due to this
action is estimated to be about 42 FTEs in 2021 and 91 FTEs in 2030. The reduction in
annual labor needed to comply with the NSPS due to this action is estimated at about 490
FTEs in 2021 and 1,300 FTEs in 2030. The EPA notes that this type of FTE-estimate
cannot be used to identify the specific number of employees involved or whether new
jobs are created for employees who potentially lose their jobs, versus displacing jobs
from other sectors of the economy.
3.1.5 Organization of the Technical Reconsideration RIA
Section 3.2 describes the estimated compliance cost reductions and forgone emissions reductions
from the Technical Reconsideration, including the PV of the projected cost reductions over the
2021 to 2030 period and the associated EAV. Section 3.3 describes the projected forgone
benefits resulting from this rule, including the PV and EAV over the 2021 to 2030 period.
Section 3.4 describes the economic impacts expected from this action. Section 3.5 compares the
projected forgone benefits and compliance cost reductions of this action, including a summary of
the net benefits.
3.2 Compliance Cost Reductions and Forgone Emissions Reductions
This section describes the emissions and compliance cost analysis for the final Technical
Reconsideration of the 2016 NSPS OOOOa. Projected incremental changes in emissions and
compliance costs resulting from this reconsideration are estimated relative to the baseline, which
is representative of more up-to-date data and projections and current policy. The baseline also
includes the impacts of the final Policy Review, discussed in Chapter 2. Updates to the data and
analytic approach from the 2016 NSPS RIA are described in Section 3.1.1. A detailed discussion
of the updates since the 2016 NSPS RIA to the methodology, data, and assumptions used to
estimate the compliance cost impacts of this reconsideration can be found in the TSD.78 The
methodology, data, and assumptions that are not mentioned are the same as those in the 2016
NSPS RIA and can be found in the 2016 NSPS Final TSD for that action.79
78	The TSD for this final reconsideration can be found in Docket ID No. EPA-HQ-OAR-2017-0483.
79	Docket ID No. EPA-HQ-OAR-2010-0505-7631.
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There are two main steps in the compliance cost analysis. First, representative facilities (also
referred to as model plants) are established for each affected source category.80 The
characteristics of the facilities include equipment inventories, operating characteristics, and
representative factors including baseline emissions and the compliance costs, emissions
reductions, and product recovery resulting from each compliance measure. Second, we project
the number of NSPS-affected facilities in each source category for each type of equipment, and
then estimate the number of reconsideration-impacted sources. The change in emissions and
compliance costs are calculated by multiplying representative factors from the first step by the
number of reconsideration-impacted facilities estimated in the second step for each projection
year. In addition to emissions reductions, some aspects of the regulatory options may result in
natural gas recovery, which can then be combusted by the sources for production purposes or
sold. The compliance cost impacts include the change in estimated revenue from product
recovery, where applicable.
Throughout this section, we present the projected effects of the final Technical Reconsideration
on compliance costs and emissions from 2021 through 2030, under the assumption that 2021 is
the first year the reconsidered requirements will take effect. Comparing the 2016 NSPS RIA
results to this analysis should be done with caution. The baseline of affected sources has been
updated in this analysis, as explained in Section 3.1.1.1, and results in this RIA are presented in
2016 dollars, while the 2016 NSPS RIA results are in 2012 dollars.
3.2.1 Pollution Controls and Emissions Points Assessed
The RIA in this chapter estimates impacts associated with the reconsidered requirements for
fugitive emissions monitoring and certifications of closed vent system design. In addition, the
EPA changed requirements related to pneumatic pumps and oil well completions and provided
additional technical corrections and clarifications; however, this RIA does not quantify any
changes in emissions or costs resulting from these changes. This section provides a basic
80 See Section 2 of the TSD accompanying this final action for more detail on how model plants were developed. As
described in Section 2.3.1 of this TSD, model plants were developed to represent equipment and component counts
at the different site types. These model plants allow for consideration of costs and emission reduction impacts.
While actual sites may be larger than the models, focus was placed on small sites since that is where the impacts are
most likely to be more burdensome. Where impacts are reasonable, we can be certain that they will also be
reasonable for larger sites.
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description of the emissions sources and control requirements affected by the Technical
Reconsideration and indicates which aspects of the final reconsideration we quantify impacts for
in this RIA. For more detailed information on the requirements that were reconsidered, see the
preamble. For information on the emission sources and control measures evaluated for the 2016
NSPS OOOOa, see the 2016 NSPS RIA.
Fugitive Emissions Monitoring Requirements: Fugitive emissions occur when connection
points on equipment are not fitted properly or when seals and gaskets start to deteriorate.
Pressure, changes in pressure, or mechanical stresses can also cause components or equipment to
leak. Potential sources of fugitive emissions include valves, connectors, pressure relief devices,
open-ended lines, flanges, closed vent systems, and thief hatches or other openings on a
controlled storage vessel. For purposes of this rulemaking, fugitive emissions points do not
include devices that vent as part of normal operations. In the 2016 NSPS RIA, the EPA estimated
compliance costs and emission reductions assuming the use of a leak monitoring program where
optical gas imaging (OGI) leak detection was combined with leak correction. In addition, the
2016 RIA considered the following alternative frequencies for fugitive emissions survey
requirements: annual, semiannual, and quarterly. This RIA estimates the impacts from reducing
fugitive emissions monitoring frequency from the frequency required in the 2016 NSPS OOOOa
for some NSPS-affected oil and natural gas facilities. The EPA is also making changes to allow
several fugitive emissions monitoring state programs to be considered equivalent to NSPS
OOOOa in terms of emissions reductions, which will lead to reductions in the NSPS reporting
and recordkeeping burden for some sources regulated under some of the designated state
programs.
Professional Engineer Certifications: Closed vent systems can be used to route emissions from
various equipment at oil and natural gas facilities, including storage vessels, compressors, and
pneumatic pumps, to control devices. Closed vent systems must be designed and tailored to
individual facilities' equipment configuration and process factors, such as flow rates. For the
2016 NSPS OOOOa, the EPA required closed vent systems be certified by a professional
engineer. In addition, the 2016 NSPS OOOOa requires that facilities citing compliance issues
due to technical infeasibility in routing emissions from well site pneumatic pumps to an existing
control device must have a professional engineer certify said technical infeasibility. The
compliance cost impact of the professional engineer certification requirements was not evaluated
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in the 2016 NSPS RIA. For this analysis, the EPA evaluated the cost impacts of the certification
requirements in the 2016 NSPS in order to determine the impact of the reconsidered provision
that allows facilities to choose either a professional engineer or an in-house engineer to perform
the required certification for technical infeasibility.
Additional Reconsideration Topics Not Quantified in this RIA: The preamble and regulatory
text for this final Technical Reconsideration action contain several finalized provisions for which
we do not quantify impacts in this RIA. These include, but are not limited to the following:
Pneumatic Pumps: The EPA is finalizing changes in the circumstances for which it may be
infeasible to control emissions from well site pneumatic pumps by removing the distinctions
between greenfield and non-greenfield sites. These changes are intended to better distinguish the
circumstances where pneumatic pump controls may be infeasible. This provision is not expected
to result in changes in emissions.
Well Completions: The EPA is finalizing changes and adding clarifications related to the
location of separators during flowback operations, recordkeeping requirements for reduced
emission completions, and the definition of flowback (e.g., to exclude screenouts, coil tubing
cleanouts, and plug drill out processes). Some of these changes could reduce compliance costs
(e.g., by decreasing recordkeeping burden) or result in higher emissions relative to the baseline,
but the EPA does not have the necessary data and information to quantify these potential
impacts.
Fugitive Emissions Monitoring: The EPA is finalizing changes to several definitions used in
the fugitive emissions monitoring provisions in NSPS OOOOa, including the definitions for
modification, third party equipment, and underground disposal wells. The EPA is also finalizing
changes to the repair requirements for fugitive emissions components. Some changes may result
in cost reductions (e.g., the exemption of monitoring requirements for third-party equipment and
disposal wells), and may result in increased emissions (e.g., by exempting a small number of
fugitive components downstream of the custody meter from monitoring requirements), but the
EPA does not have the ability to quantify these potential changes due to unavailability of
necessary information and data (e.g., counts for the relevant equipment and components).
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Gas Processing Plants: The EPA is finalizing an exemption of Leak Detection and Repair
(LDAR) requirements for equipment at gas processing plants which is used in VOC service for
less than 300 hours per year and only during emergencies, as backup, or during startup and
shutdown. This exemption may reduce compliance costs related to monitoring such equipment.
This reduces burden related to the scheduling of monitoring when the equipment is in VOC
service, however, any potential leaks from the equipment would be addressed once it is no longer
in VOC service and monitoring is reinstated. The EPA does not have the data on the use of VOC
service equipment needed to quantify potential impacts on costs and emissions from this LDAR
exemption, however, any potential impacts are expected to be small based on the EPA's current
understanding of the use of this type of equipment at gas processing plants.
Storage Vessels: The EPA is amending applicability criteria for NSPS-affected storage vessels.
The final reconsideration clarifies how VOC emissions potential should be calculated for
individual storage vessels and establishes criteria for calculating VOC emissions potential
specifically from individual storage vessels that are part of a controlled tank battery. For
controlled tank battery storage vessels (i.e., two or more storage vessels joined with piping and
sharing vapors in their headspaces, with emissions routed through a closed vent system to a
control device or process with a VOC emissions control efficiency of at least 95.0 percent)
subject to a legally and practicably enforceable limit, VOC emissions may be determined as an
average of emissions per individual storage vessel for the entire tank battery. When VOC
emissions for an individual storage vessel are greater than 6 tons per year, the storage vessel is
affected by the applicable NSPS requirements. If average VOC emissions per storage vessel in a
controlled tank battery are greater than 6 tons per year, each of the battery's storage vessels meet
the criteria for being regulated under NSPS OOOOa.
3.2.2 Source-level Compliance Cost Reductions and Emission Increases
This RIA quantifies the compliance cost and emissions impacts of the changes to requirements
affecting fugitive emissions monitoring, technical infeasibility certifications, and closed vent
systems in the finalized Technical Reconsideration. Volume 1 of the TSD contains the facility-
level compliance costs and emission reductions from the reconsidered fugitive emission
requirements for each model plant. For this reconsideration, the TSD and RIA rely on a larger set
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of model plants to analyze impacts on oil and natural gas well sites than was used for the 2016
NSPS OOOOa RIA. The 2016 analysis used three model plants representing oil, oil with
associated gas, or natural gas well sites, while impacts in this analysis are estimated for six
model plants: non-low production natural gas well sites, non-low production oil-only well sites,
non-low production oil with associated gas well sites, low-production natural gas well sites, low-
production oil-only well sites, and low-production oil with associated gas well sites.
The refinements to the model plants used in this RIA are intended to better reflect the
heterogeneity among well sites in the oil and natural gas sector. The production level distinction
is important because the applicability of certain requirements in the final NSPS reconsideration
depend on site production level. Additionally, the source-level impacts of parts of NSPS OOOOa
are likely dependent on site production level (e.g., compared to low-production natural gas well
sites, non-low production natural gas well sites would be expected to experience greater forgone
revenues associated with lower product recovery due to the monitoring frequency adjustments in
this final rule).
The potential facility-level cost reductions and forgone emissions reductions estimated for the
alternative regulatory options were calculated by subtracting the estimated NSPS-related
compliance costs and emissions for the model plants under the alternative options for the
Technical Reconsideration from the estimated NSPS-related compliance costs and emissions for
the model plants under the baseline. For greater detail on the compliance cost estimates,
including the estimates related to the individual aspects of NSPS OOOOa affected by this
Technical Reconsideration, see Volume 1 of the TSD.
We have also re-evaluated our assumptions regarding equivalent state programs for fugitives that
qualify as alternative standards. In the proposal analysis, if a well site was in a state determined
to have fugitive emissions requirements for well sites effectively equivalent to those of NSPS
OOOOa, even if not located in a state formally identified as equivalent, we assumed the
proposed rule would reduce the NSPS fugitive emissions monitoring requirements. Thus, it was
assumed the proposal would reduce the compliance costs associated with fugitive monitoring
requirements in NSPS OOOOa for those sites, including the recordkeeping and reporting costs.
In this analysis, we refined the assumptions used to quantify those costs to better reflect the
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impacts of state programs on fugitive monitoring and whether an alternative fugitive emissions
standard could be applied in certain states, which should improve our estimates of the
recordkeeping and recording burden reduced by this rule. In this RIA, we limit the cost
reductions of the fugitive monitoring recordkeeping and reporting to certain well sites located in
the states recognized in the rule as having fugitive emissions requirements that can qualify as an
alternative fugitive emissions standard.
The operators with well sites that qualify under an alternative fugitive emissions standard instead
of the NSPS OOOOa requirements for fugitive monitoring benefit from reduced recordkeeping
and reporting burden. Specifically, for well sites under an alternative fugitive emissions standard,
we assume operators save $323 per year per site in reduced recordkeeping and data management
costs (e.g., data QA/QC, tracking repairs, and database management fees as reported by
commenters) and $184 per year per site on annual reporting costs (equivalent to three labor hours
spent preparing an annual report and storing/filing records), resulting in a total yearly cost
reduction of $507 per site. Because many firms operate in multiple states, and sources in only
some states qualify under an alternative fugitive emissions standard, we continue to assume that
operators with sites in non-alternative fugitive emissions standard states will continue to incur
reporting and recordkeeping costs related to reading the rule, developing a fugitive emissions
monitoring plan, and establishing and maintaining a database.
The costs of the professional engineer certification requirement were not included in the analysis
of the 2016 rule. This analysis updates baseline cost estimates to include professional engineer
certification costs, and the relative reduction in costs from the reconsidered provision which
allows certifications to be done by in-house engineers. The cost of a professional engineer
certification is estimated at $4,500, and the cost of the same certification performed by an in-
house engineer is estimated at $2,950. Therefore, the cost reduced by this provision of the
reconsideration is an estimated $1,550 per certification.81
81 At proposal, the EPA estimated the costs of these certifications to be $358 for a certification by an in-house
engineer and $547 for a certification by a professional engineer. Commenters contended that EPA's cost
estimates at proposal were underestimated because the costs did not account for the need to pay for the expertise
of an external third-party with region and location-specific knowledge, the amount of time required to certify a
CVS, or the other costs associated with the certification process. Based on these and other public comments,
EPA revised the estimated cost of a certification by an in-house engineer to $2,950 and to $4,500 per
certification performed by a professional engineer.
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3.2.3 Projection of Affected Facilities
The second step in estimating national costs and emissions impacts of the final Technical
Reconsideration is projecting the number of NSPS and reconsideration-impacted facilities. We
first update the number of NSPS-affected facilities under the baseline. We then project the
number of reconsideration-impacted facilities, which are facilities that would be expected to
change their activities as a result of this reconsideration.
We analyze the effects of this final action on compliance costs and emissions compared to the
baseline. The baseline includes the costs and emissions of the projected NSPS-affected facilities,
after accounting for updated assumptions and data (Section 3.1.1 and 3.1.2). NSPS-affected
facilities include facilities that are new or modified since the 2015 NSPS OOOOa proposal and
were/are expected to change activities as a result of the 2016 NSPS OOOOa, starting from a
baseline without the 2016 NSPS OOOOa. Over time, more facilities are newly established or
modified in each year and, to the extent the facilities remain in operation in future years, the
share of facilities in the sector and the total number of facilities which are subject to the 2016
NSPS OOOOa increase. This analysis assumes that all new equipment and facilities established
from 2015 through 2029 are still in operation in 2030.
The reconsideration-impacted facilities are the subset of the NSPS-affected facilities that are
expected to change activities as a result of this reconsideration. These facilities include sources
that became affected facilities under the 2016 NSPS OOOOa prior to the effective date of this
final action and assumed to still be in operation, as well as those that are projected to become
newly affected sources in the future and are expected to change their compliance activities,
relative to what they would have been otherwise, as a result of this final action. For the finalized
option, these sources include fugitive emissions sources at well sites outside of the Alaska North
Slope and compressor stations both outside of and on the Alaska North Slope.82 For the change to
certification requirements, only the projected newly affected sources that require a certification
are considered reconsideration-affected in reference to the certification provision. Sources that
82 We do not quantify any emissions or cost changes associated with new compressor stations on the Alaska North
Slope.
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have already completed professional engineer certifications are not counted as reconsideration-
impacted sources since they will not need to obtain another certification.
The EPA projected the numbers of affected facilities using a combination of historical data from
the GHGI, 2016 NSPS OOOOa compliance reports, and Drillinglnfo, and projected activity
levels taken from AE02020. Appendix A contains more detailed information on the data sources
and methods used to project reconsideration-impacted facilities. The EPA derived typical counts
for new gathering and boosting stations by averaging the year-to-year changes in total national
station counts in the GHGI.83 Counts for storage vessels, pneumatic pumps, and reciprocating
compressors, which feed into the assumed number of certifications, are based on 2016 NSPS
OOOOa compliance reports.84 New and modified well sites are based on the count of wells in
2014 from Drillinglnfo, and projections and growth rates consistent with the drilling activity in
the AEO. For this RIA, the projections have been updated from the AEO2015 projections used in
the 2016 NSPS RIA to reflect the projection estimates in the AE02020.85 The AE02020 projects
that oil and natural gas well drilling will increase from about 29,000 wells in 2021 to about
32,000 wells in 2030. This projection is lower than the AEO2015 projection of about 43,000
wells in 2020 to about 52,000 wells in 2030 used in the 2016 NSPS RIA.
This RIA includes more detail than previous oil and natural gas NSPS analyses as it includes
year-by-year results over the 2021 to 2030 analysis period and greater disaggregation of facilities
83	The estimates for gathering and boosting stations do not include replacement or modification of existing sources,
and so the impacts may be under-estimated due to the focus on new sources. Counts of newly constructed
gathering and boosting stations are estimated based on averaging the year-to-year changes from 2004 to 2014 in
the activity data in the GHGI. In years when the total count of equipment decreased, it was assumed there were
no newly constructed units. In the GHGI, the EPA used an estimate of stations per quantity of marketed gas
production (as estimated in Marchese et al., 2015) applied to the total quantity of marketed onshore gas
production in a given year. For example, in 2016, the GHGI calculated 5,421 gathering stations in the U.S.,
based on one station per 53,066 standard cubic feet per day of marketed onshore gas production. More detailed
information on how EPA derived these estimates are provided in the Appendix A.
84	Consistent with the Policy Review analysis, we assume there are no centrifugal compressor affected facilities
during our analysis horizon. We maintain our assumption from the 2016 NSPS RIA that 10% of reciprocating
compressors are routed to closed vent systems and thus require certification. The total count of reciprocating
compressors in the production and processing segment is the sum of: 1) the number of reciprocating compressors
at gas processing plants according to 2016 NSPS OOOOa compliance reports; and 2) the number of
reciprocating compressors at gathering and boosting stations, which is the number of reciprocating compressors
at compressor stations according to 2016 NSPS OOOOa compliance reports less the number of reciprocating
compressors at compressor stations in the transmission and storage segment as estimated from the 2004 to 2014
GHGI data.
85	Note that the RIA associated with the proposal of this action used projections of well drilling and natural gas
prices from AEO2018.
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by vintage and production levels. While it would be preferable to analyze impacts beyond 2030,
the EPA has chosen not to largely because of the limited information available to model long-
term dynamics in practices and equipment in the oil and natural gas industry. The EPA has
limited information on how practices, equipment, and emissions at new facilities evolve as they
age and shut down. The current analysis assumes that newly established facilities remain in
operation for the entire analysis period, and this assumption would be less realistic for a longer
analysis period. In addition, in a dynamic industry like oil and natural gas, technological progress
is likely to change control methods to a greater extent over a longer time horizon, creating more
uncertainty about impacts of the NSPS.
The 2016 NSPS RIA assumed that the regulatory programs in the states of Colorado, Utah, Ohio,
and Wyoming were expected to result in broadly similar overall emission reductions as the 2016
NSPS OOOOa requirements. For this action, the EPA reviewed state regulations and permitting
requirements that require mitigation measures for many emission sources in the oil and natural
gas sector. Detailed information is included in the TSD and in the memorandum Equivalency of
State Fugitive Emissions Programs for Well Sites and Compressor Stations to Proposed
Standards at 40 CFR Part 60, Subpart OOOOa ("State memo").86 Resulting from this analysis,
California, Pennsylvania, and Texas have been added as states with programs which are expected
to achieve similar emission reductions as the 2016 NSPS OOOOa because additional
requirements in these states have been finalized since the promulgation of the 2016 NSPS
OOOOa. While the program designs in each of the states differ from the 2016 NSPS OOOOa,
for this RIA, the current requirements in California, Colorado, Pennsylvania, and Utah are
expected to result in similar overall emissions reductions, while a subset of the requirements in
Ohio and Texas are expected to achieve similar emissions reductions. Permit by rule-based
requirements in Texas are not included as broadly equivalent to the NSPS requirements in this
analysis, while general permits (covering roughly 5.5 percent of the relevant facilities) in Texas
are considered equivalent.87 For roughly 80 percent of the relevant facilities in Ohio, emission
reductions from state requirements are considered equivalent. The requirements in Wyoming are
86	For a more detailed explanation of state programs, see the TSD, as well as the memo "Equivalency of State
Fugitive Emissions Programs for Well Sites and Compressor Stations to Proposed Standards at 40 CFR Part 60,
Subpart OOOOa", located at Docket ID No. EPA-HQ-OAR-2017-0483.
87	We do not consider the permit by rule in Texas as equivalent for RIA purposes because these are self-certified
permits and we are uncertain about the level of compliance for these permits.
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no longer considered to be equivalent for purposes of this RIA because they apply facility-
specific permit requirements which do not apply across the entire state. For more information on
the states that were examined and why they are or are not considered equivalent, see the TSD
and the State memo, both of which are available in the docket.
As discussed in Section 3.1, the EPA is amending the inspection frequency requirements for
fugitive emissions components at low production well sites. In the final rule a well site is defined
as "low production" if the total combined oil and natural gas production for the well site is less
than or equal to 15 boe per day. These sites are excluded from fugitive emissions monitoring
requirements but are required to maintain the total well site production at or below 15 boe per
day and maintain records to demonstrate production levels. For well sites that have previously
been determined to be low production and for which operators later take action (e.g., drills a new
well, performs a well workover, etc.) to increase production, the site will again face monitoring
requirements if total well site production during the first 30 days of production following
completion (or other action intended to increase production from the site) exceeds 15 boe per
day.
To estimate the impacts of this provision, it was necessary to estimate the number of well sites
that would transition to low production status. We use historical data to estimate the share of
sites that transition to low production status as a function of well site age using a combination of
Drilling Info data and AE02020 well drilling projections. The transition percentage is an
estimate of the proportion of well sites that transition to low production status as a function of
the number of years since completion. The transition percentage also accounts for sites that
transitioned from low production status to non-low production status.88 The low production
transition analysis is based on a cross-section of producing wells in 2014 (the base year for the
RIA analysis). While it would preferable to perform a time-series analysis of well production
decline over a longer period, this population was chosen based on readily available data.
We first estimate the percentage of sites that meet the low production threshold during the first
30 days of production using well-level Drilling Info data for wells completed in 2014. In
88 As a hypothetical example, if 15 percent of wells transitioned into a low production status and 1 percent
transitioned from a low production status into a not-low production status within a given year, the transition
percentage would equal 14 percent in that year.
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accordance with the model plant analysis presented in the preamble and the TSD, we assume
sites have two wells per site. Assuming each of the two wells per model site produces identical
quantities of oil and natural gas boe, we approximate the proportion of sites that are initially low
production in 2014 (the base year used for well site projections in the RIA) by the proportion of
wells producing less than 7.5 boe per day (equivalent to two model plant wells producing fewer
than 15 boe per day combined). Using this method, we estimate that about 13 percent of sites
would be considered low production based upon the first 30 days of production.89
We use the well-level Drilling Info data to estimate the proportion of well sites that change
production status in subsequent years as a function of age, accounting for potential transitions
from low production status to non-low production status. To this end, for all producing wells in
2014, we characterize each well's initial production status (i.e., during the first 30 days of
production) and the well's production status in 2014. Specifically, we categorize a well to be in
low production status if production was less than 7.5 boe per day on average in all months of
2014. We cross-tabulate the 2014 production status with the initial production status and the
completion year field in the Drilling Info data to estimate the proportion of sites (based on the 2
wells per site assumption) in each of the two categories as a function of age. This cross-
tabulation yields information that approximates a decline curve as applied to model well sites.
We include completion years from 1999 to 2013 to produce transition proportions for well ages
from 1 to 15 years. Figure 3-1 shows the proportion of well sites estimated to have low
production status for ages 1 to 15 years.
89 It is important to note that, under the final rule, production levels are evaluated against the low production
threshold at the site level, where sites may have more than one well. While there are comprehensive data available
on individual wells, there are no national-level datasets that we are aware of that identify the well sites to which
individual wells belong. In addition, we did not receive information in the comment period on the rate at which well
sites transition between not-low and low production status. The equal production assumption for model two-well site
is the best assumption EPA can come up with to approximate the impacts of the finalized regulatory option.
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c
•- 10%
0%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
Age (Years Since Completion)
Figure 3-1 Estimated Percent of Well Sites in Low Production Status by Age of Site
We apply these transition percentages to the projected counts of wells sites affected by this final
reconsideration. The compliance cost and emissions impacts for sites transitioning into low
production status and being relieved of fugitive monitoring requirements are lagged one year due
to the 12-month averaging period needed to establish low production status. During the transition
year, sites are treated as low production sites for the purposes of assigning compliance costs and
emissions impacts, and as non-low production sites for the purposes of assigning a regulatory
regime. For example, in the finalized option, if the average daily production of a site in a non-
alternative fugitive emissions standard state falls below 15 boe per day during 2020, the site is
assumed to incur the cost and emissions impacts associated with a low production site of the
monitoring level of a non-low production site (semiannual) in 2020. In 2021, the site is no longer
subject to fugitive monitoring requirements.
This analysis relies on a series of assumptions that introduce substantial uncertainties. These
uncertainties include the assumption that past production patterns are predictive of future
production and the assumption of two wells per site with identical production profiles. The
dataset used to estimate the transition proportions excludes wells that were shut-in since
completion, which tend to bias estimates of compliance cost and emissions impacts upwards.
Lastly, the projection does not separately identify well sites which are wellhead-only, either at
the time of completion or later if equipment is removed from the site, and thus not subject to
fugitive emissions requirements.
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Below, we provide projected source counts in a series of tables. Table 3-3 presents the number of
incremental reconsideration-impacted sources for each year of the analysis, broken out by source
type. Table 3-4 includes the same information for all reconsideration-impacted sources over the
whole period. The total source counts for well sites each year reflect both incrementally affected
sources and those affected due to transitions from non-low production to low production status.
For example, of the 18,000 low production well sites in 2021, 1,800 are incremental low
production sites (see Table 3-3) projected to begin production in 2021. The remainder are non-
low production sites that are assumed to have started production between 2015 and 2019 before
transitioning to low production status according to the schedule illustrated in Figure 3-1. Finally,
Table 3-5 shows the distribution of well sites by production level and alternative fugitive
emissions standard status for each year of the analysis.
Table 3-3 Incremental Reconsideration-impacted Source Counts for Finalized Option
3, 2021-2030	
Year
Non-Low
Production
Wellsites
Low Production
Wellsites
Gathering and
Boosting Stations
Certifications
Total
2021
8,400
1,800
210
1,600
12,000
2022
8,800
1,900
210
1,600
12,000
2023
9,000
1,900
210
1,700
13,000
2024
9,200
2,000
210
1,700
13,000
2025
9,300
2,000
210
1,700
13,000
2026
9,400
2,000
210
1,700
13,000
2027
9,400
2,000
210
1,700
13,000
2028
9,500
2,000
210
1,700
13,000
2029
9,500
2,000
210
1,700
14,000
2030
9,500
2,000
210
1,700
13,000
Note: Incrementally reconsideration-impacted sources include sources that are newly affected in each year.
Estimates may not sum due to independent rounding.
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Table 3-4 Total Reconsideration-impacted Source Counts for Finalized Option 3, 2021-
2030
Year
Non-Low Production
Wellsites
Low Production
Wellsites
Gathering and
Boosting Stations
Certifications
Total
2021
42,000
18,000
1,500
1,600
63,000
2022
48,000
23,000
1,700
1,600
74,000
2023
54,000
28,000
1,900
1,700
85,000
2024
59,000
33,000
2,100
1,700
97,000
2025
65,000
39,000
2,300
1,700
110,000
2026
70,000
46,000
2,500
1,700
120,000
2027
75,000
52,000
2,800
1,700
130,000
2028
80,000
59,000
3,000
1,700
140,000
2029
84,000
66,000
3,200
1,700
150,000
2030
88,000
73,000
3,400
1,700
170,000
Note: Total reconsideration-impacted sources include sources that are projected to change their activity as a result of
the reconsideration in each year. These include sources that are newly affected in each year plus the sources from
previous years that experience a change in their compliance activity as a result of this final action compared to the
baseline. The table does not include estimated counts of NSPS-affected facilities whose controls are unaffected by
the reconsideration. Estimates may not sum due to independent rounding.
Table 3-5 Reconsideration-impacted Well Site Counts by Alternative Fugitive
Emissions Standards Status for Finalized Option 3, 2021-2030	

Non-Alternative Fugitive Emissions
Standard State
Alternative Fugitive Emissions
Standard State
Year
Non-Low Production
Wellsites
Low Production
Wellsites
Non-Low Production
Wellsites
Low Production
Wellsites
2021
34,000
14,000
7,800
4,600
2022
39,000
17,000
8,900
5,600
2023
44,000
21,000
9,900
6,800
2024
48,000
25,000
11,000
8,000
2025
53,000
30,000
12,000
9,400
2026
57,000
35,000
13,000
11,000
2027
61,000
40,000
14,000
12,000
2028
65,000
45,000
15,000
14,000
2029
68,000
51,000
16,000
15,000
2030
72,000
57,000
16,000
17,000
Note: Projected sources under alternative fugitive emissions standard include all reconsideration-impacted well sites
in California, Colorado, Pennsylvania, and Utah; 80 percent of well sites in Ohio; and 5.5 percent of well sites in
Texas.
3.2.4 Forgone Emissions Reductions
Table 3-6 summarizes the estimated forgone emissions reductions associated with the finalized
Option 3 compared to the baseline. Increases in emissions are estimated by multiplying the
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source-level increases in emissions from the updated baseline by the corresponding projected
number of reconsideration-affected facilities. In the analysis, streamlined elements of the fugitive
emissions monitoring requirements and closed vent system and technical infeasibility
certification requirements are not associated with any direct emissions changes.90 Therefore, all
forgone emissions reductions are attributed to the frequency changes in the fugitive emissions
monitoring program.91 This does not include projected impacts on emissions from this final
action resulting from reducing the monitoring frequency for affected compressor stations on the
Alaska North Slope because, as noted, the EPA does not sufficient information on compressor
stations there. Also, as noted in Section 3.2.1, some additional provisions included in the
preamble are not analyzed because we either do not have the data to do so or because we do not
think the provision will lead to measurable cost reductions or emission changes.
Table 3-6 Forgone Emissions Reductions under Finalized Option 3, 2021-2030	
Emission Changes

Methane
(short tons)
voc
(short tons)
HAP
(short tons)
ivicinanc
(metric tons CO2
Eq.)
2021
19,000
5,200
200
430,000
2022
23,000
6,500
250
530,000
2023
28,000
7,900
300
650,000
2024
34,000
9,500
360
780,000
2025
40,000
11,000
420
910,000
2026
47,000
13,000
490
1,100,000
2027
53,000
15,000
560
1,200,000
2028
60,000
17,000
630
1,400,000
2029
68,000
19,000
710
1,500,000
2030
75,000
21,000
790
1,700,000
Total
450,000
120,000
4,700
10,000,000
Note: Estimates may not sum due to independent rounding.
90	Streamlined elements of the fugitive emissions monitoring requirements include the removal of site map and
observation path requirements in the monitoring plan and a reduction in the information required to be recorded
and reported. After review of the specific requirements, for reasons explained in the Section V of the preamble to
the final rule, several elements of the existing program were deemed redundant or not critical to demonstrating
compliance with the rule. Emissions should not be affected by the change in certification requirements to the
extent that the use of an in-house engineer does not result in any change in the quality of closed vent systems
being certified or the number of pneumatic pump technical infeasibility determinations. We do not have the
information needed to estimate the potential for emissions impacts, if any, when moving from professional
engineer certifications to in-house engineer certifications.
91	Note that we estimate no change in emissions for well sites projected to be covered under equivalent state
programs as discussed in Section 3.2.2.
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3.2.5 Forgone Product Recovery
Fugitive emissions monitoring is assumed to increase the capture of methane and VOC
emissions that would otherwise be vented to the atmosphere with no fugitive emissions
monitoring program, and we assume that a large proportion of the averted methane emissions
can be directed into natural gas production streams and sold. In this analysis, we estimate the
forgone revenue associated with the decrease in natural gas recovery due to this final action.
Reducing the frequency of the monitoring program leads to a reduction in the amount of natural
gas that is assumed to be captured and sold, leading to forgone revenue as compared to the
baseline.
When including the decrease in natural gas recovery in the cost reductions analysis, we use the
projections of natural gas prices provided in the EIA's AE02020 reference case. The AEO
projects Henry Hub natural gas prices rising from $2.49/MMBtu in 2021 to $3.29/MMBtu in
2030 in 2019 dollars.92 To be consistent with other financial estimates in the RIA, we adjust the
projected prices from AE02020 from 2019 to 2016 dollars using the GDP-Implicit Price
Deflator. We also adjust to reflect an estimate of prices at the wellhead using an EIA study result
that indicated that the Henry Hub price is, on average, about 11 percent higher than the wellhead
price and using the conversion of 1.036 MMBtu equals 1 Mcf.93 After these adjustments, the
wellhead natural gas prices are assumed to rise from $2.20/Mcf in 2021 to $2.89/Mcf in 2030.
Table 3-7 summarizes the decrease in natural gas recovery and the associated forgone revenue
included in the cost reductions calculations for the finalized Option 3. Option 3, which reduces
the frequency of the fugitive monitoring program for compressor stations and eliminates
monitoring requirements entirely for low-production well sites, leads to a projected reduction in
the amount of natural gas that is assumed to be captured and sold ranging from 1.1 in 2021 to 4.4
Tcf in 2030; in turn, this leads to forgone revenue ranging from $2.4 million in 2021 to $13
92	Available at: http://www.eia.gov/forecasts/aeo/tables_ref.cfm.
93	See:
https://www.researchgate.net/publication/265155970_US_Natural_Gas_Markets_Relationship_Between_Henry
Hub_Spot_Prices_and_US_Wellhead_Prices. Accessed 04/26/2020.
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million in 2030.94 Detailed results for forgone revenues for natural gas recovery associated with
all options are presented in Section 3.2.8.
Table 3-7
Decrease in Natural Gas Recovery for Finalized Option 3, 2021-2030
Year
Decrease in Gas Recovery (Tcf)
Forgone Revenue (millions 2016$)
2021
1.1
$2.4
2022
1.4
$3.0
2023
1.7
$3.7
2024
2.0
$4.6
2025
2.3
$5.8
2026
2.7
$7.3
2027
3.1
$8.8
2028
3.5
$10
2029
3.9
$11
2030
4.4
$13
3.2.6 Compliance Cost Reductions
Table 3-8 summarizes the cost reductions and forgone revenue from product recovery for the
evaluated emissions sources and points. The annual operating and maintenance cost reductions
are all attributed to the fugitives monitoring requirement and include the cost of performing the
surveys, as well as the costs associated with repairs. The planning cost reductions in Table 3-8
represent reductions in the total planning cost expenditures for affected sources, including the
change in planning costs for sources affected prior to the analysis year. The cost reductions are
estimated by multiplying the source-level cost reductions relative to the updated baseline
associated with applicable control and facility type, discussed in Section 3.2.2, by the number of
incrementally affected sources of that facility type, discussed in Section 3.2.3. The cost
94 Operators in the gathering and boosting part of the industry do not typically own the natural gas they transport;
rather, the operators receive payment for the transportation service they provide. As a result, the source-level cost
and emission reduction analyses supporting best system of emission reduction (BSER) decisions presented in
Volume 1 of the TSD do not include estimates of revenue from natural gas recovery as offsets to compliance
costs. From a social perspective, however, the increased financial returns from natural gas recovery accrues to
entities somewhere along the natural gas supply chain and should be accounted for in the national impacts
analysis. An economic argument can be made that, in the long run, no single entity is going to bear the entire
burden of the compliance costs or fully receive the financial gain of the additional revenues associated with
natural gas recovery. The change in economic surplus resulting from natural gas recovery is going to be spread
out among different agents via price mechanisms. Therefore, the most simple and transparent option for
allocating these revenues would be to keep the compliance costs and associated revenues together in a given
source category and not add assumptions regarding the allocation of revenues across agents. Also, see the
discussion regarding opportunity costs associated investing in pollution abatement capital vs. productive capital
in Chapter 2.
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reductions from the streamlining of recordkeeping and reporting are included in the annualized
cost reductions totals.95 These cost reductions are described more below.
Table 3-8 Estimated Cost Reductions for Finalized Option 3, 2021-2030 (millions
2016$)	
Year
Planning Cost
Reductions1
Operating and
Maintenance
Cost
Reductions
Annualized Cost
Reductions (w/o
Forgone
Revenue)2
Forgone
Revenue from
Product
Recovery
Annualized Cost
Reductions (with
Forgone Revenue)
2021
$6.9
$52
$59
$2.4
$57
2022
$7.2
$62
$71
$3.0
$68
2023
$15
$74
$84
$3.7
$80
2024
$11
$87
$98
$4.6
$93
2025
$12
$100
$110
$5.8
$110
2026
$14
$110
$130
$7.3
$120
2027
$14
$130
$140
$8.8
$130
2028
$14
$140
$160
$10
$150
2029
$15
$160
$180
$11
$160
2030
$15
$170
$190
$13
$180
Note: Estimates may not sum due to independent rounding.
1	The planning cost reductions include the cost reductions incurred by the newly affected sources for both fugitive
emissions monitoring and certifications in each year, as well as the cost reductions of fugitive emissions sources that
renew survey monitoring plans after 8 years.
2	These cost reductions include the planning cost reductions for all fugitive emissions monitoring requirements
annualized over 8 years at an interest rate of 7 percent, plus the annual operating and maintenance cost reductions
for fugitive emissions monitoring, plus the certification cost reductions, plus the cost reductions from streamlined
recordkeeping and reporting.
The cost of designing, or redesigning, the fugitive emissions monitoring program occurs every 8
years to comply with the 2016 NSPS OOOOa requirements. The lifetime of the monitoring
program is not changed by this reconsideration. The reduction in planning costs in each year
outlined in Table 3-8 includes the estimated reduction in the costs of designing a fugitive
emissions monitoring program for the new reconsideration-impacted sources in that year, plus
the reduction in the cost of redesigning an existing program for sources that were affected by the
reconsideration previously. The first year a redesign cost is included in the planning cost
reduction calculation is 2023, as we assume the first NSPS-affected sources completed
monitoring plans in 2016, the first year the 2016 NSPS OOOOa affected sources completed
compliance activities. The decrease in these program design costs were added to the cost
95 See the preamble of the final reconsideration for details on the changes to the recordkeeping and reporting
requirements.
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reductions associated with closed vent system design and technical infeasibility certifications in
each year to get the total planning cost reductions for each year.
The fugitive emissions monitoring planning cost reductions, annualized over the expected
lifetime of 8 years at an interest rate of 7 percent, are added to the annual cost reductions of
associated with fugitive emissions monitoring, the cost reductions associated with certifications,
and the cost reductions from streamlined recordkeeping and reporting to get the annualized cost
reductions in each year compared to the baseline. The value of forgone product recovery is also
subtracted out to estimate the total annualized cost impacts in each year.
Table 3-9 illustrates the sensitivity of the compliance cost and emissions results of the finalized
Option 3 to changes in the interest rate. We present costs using interest rates of 7 percent and 3
percent. Table 3-9 shows that the interest rate has minor effects on the nationwide annualized
cost reductions of the Technical Reconsideration.
Table 3-9 Estimated Cost Reductions for Finalized Option 3 at 3 and 7 Percent Interest
Rates, 2021-2030 (millions 2016$)	


7 Percent


3 Percent

Year
Annualized
Cost
Reductions
(w/o Forgone
Revenue)
Forgone
Revenue
from
Product
Recovery
Annualized
Cost
Reductions
(with
Forgone
Revenue)
Annualized
Cost
Reductions
(w/o Forgone
Revenue)
Forgone
Revenue
from
Product
Recovery
Annualized
Cost
Reductions
(with Forgone
Revenue)
2021
$59
$2.4
$57
$58
$2.4
$56
2022
$71
$3.0
$68
$70
$3.0
$67
2023
$84
$3.7
$80
$83
$3.7
$79
2024
$98
$4.6
$93
$97
$4.6
$92
2025
$110
$5.8
$110
$110
$5.8
$110
2026
$130
$7.3
$120
$130
$7.3
$120
2027
$140
$8.8
$130
$140
$8.8
$130
2028
$160
$10
$150
$160
$10
$150
2029
$180
$11
$160
$170
$11
$160
2030
$190
$13
$180
$190
$13
$180
Note: Estimates may not sum due to independent rounding.
3.2.7 Comparison of Regulatory Alternatives
Table 3-10 presents a comparison of projected emissions and compliance cost impacts of the
regulatory alternatives in 2021 and 2030. The most stringent option, Option 1, would not change
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the fugitive emissions monitoring frequency requirements in the 2016 NSPS OOOOa. As a
result, there are no changes in projected emissions compared to the baseline for Option 1.
However, there are cost reductions from streamlining fugitive emissions monitoring, certifying
several state programs as having an alternative fugitive emissions standard, and allowing the use
of in-house engineers for certifications. For Option 2, in addition to the changes in requirements
captured in Option 1, fugitive emissions monitoring requirements are removed for low
production well sites (semiannual under the baseline). We assume 60 percent emissions
reductions for semiannual fugitive monitoring.96 Compliance costs and natural gas recovery vary
by survey frequency. The finalized Option 3 is the same as Option 2 but decreases the fugitive
emissions monitoring frequency at gathering and boosting stations from quarterly to semiannual.
We assume 80 percent emissions reductions for a quarterly fugitive emissions monitoring
requirement.
Table 3-10 Comparison of Regulatory Alternatives in 2021 and 2030	
Option 1
Regulatory Alternative
Option 2
Option 3
(Finalized)
Forgone emissions reductions
Methane Emissions (short tons/year)
VOC Emissions (short tons/year)
Decrease in Natural Gas Recovery (Tcf)
Total Impacts, 2021
0
0
0
14,000
3,900
0.8
19,000
5,200
1.1
Cost Reductions
Planning Cost Reductions
Annualized Cost Reductions w/o Forgone
Revenue (7 percent)
Annualized Cost Reductions with Forgone
Revenue (7 percent)	
$5.7
$30
$30
$6.9
$52
$51
$6.9
$59
$57
Forgone emissions reductions
Methane Emissions (short tons/year)
VOC Emissions (short tons/year)
Decrease in Natural Gas Recovery (Tcf)
Total Impacts, 2030
0
0
0
64,000
18,000
3.7
75,000
21,000
4.4
Cost Reductions
Planning Cost Reductions
Annualized Cost Reductions w/o Forgone
Revenue (7 percent)
Annualized Cost Reductions with Forgone
Revenue (7 percent)	
$76
$76
$15
$180
$170
$15
$190
$180
96 See the TSD for more details on the emission reductions assumptions across fugitive monitoring survey
frequencies at well sites and compressor stations.
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As shown in Table 3-10, Option 1 is projected to result in no changes in emissions and
annualized cost reductions are projected to be $30 million in 2021 and $76 million in 2030.
Option 2 is projected to result in a decrease in annualized compliance costs of $51 million in
2021 and $170 million in 2030 after accounting for decreased product recovery. Emissions are
projected to increase by 14,000 short tons of methane and 3,900 short tons of VOC in 2021 and
64,000 short tons of methane and 18,000 short tons of VOC in 2030. The finalized Option 3 is
projected to result in the largest cost reductions and forgone emissions reductions. Option 3 is
projected to decrease annualized costs by $57 million in 2021 and $180 million in 2030 after
accounting for the value of forgone product recovery. Option 3 is projected to increase emissions
by 19,000 short tons of methane and 5,200 short tons of VOC in 2021 and 75,000 short tons of
methane and 21,000 short tons of VOC in 2030.
3.2.8 Detailed Impact Tables
The following tables show the full details of the cost reductions and forgone emissions
reductions by emissions source for each regulatory option in the years 2021 and 2030.
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Table 3-11 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Option 1, 2021
Forgone Emissions Reductions	Compliance Cost Reductions (millions $2016)
Source/Emissions Point
Projected No. of
Reconsideration-
impacted
Sources
Methane
(short
tons)
voc
(short
tons)
HAP
(short
tons)
Methane
(metric
tons CO2
Eq.)
Annualized
Planning
Cost
Reductions
Operating
and
Maintenance
Forgone
Product
Recovery
Total Annualized
Cost Reductions
with Forgone
Revenues
Fugitive Emissions
Non-Low Production Well Sites
42,000
0
0
0
0
$2.3
$16
$0
$18
Low Production Well Sites
18,000
0
0
0
0
$0.90
$7.1
$0
$8.0
Gathering and Boosting Stations
1,500
0
0
0
0
$0,099
$1.0
$0
$1.1
Certifications
CVS and Technical Infeasibility
1,600
0
0
0
0
$2.5
$0
$0
$2.5
TOTAL
63,000
0
0
0
0
$5.7
$24
$0
$30
Note: Estimates may not sum due to independent rounding.








Table 3-12 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Option 1, 2030



Forgone Emissions Reductions
Compliance Cost Reductions (millions $2016)
Source/Emissions Point
Projected No. of
Reconsideration-
impacted
Sources
Methane
(short
tons)
voc
(short
tons)
HAP
(short
tons)
Methane
(metric
tons CO2
Eq.)
Annualized
Planning
Cost
Reductions
Operating
and
Maintenance
Forgone
Product
Recovery
Total Annualized
Cost Reductions
with Forgone
Revenues
Fugitive Emissions
Non-Low Production Well Sites
88,000
0
0
0
0
$4.8
$34
$0
$38
Low Production Well Sites
73,000
0
0
0
0
$3.8
$28
$0
$32
Gathering and Boosting Stations
3,400
0
0
0
0
$0.23
$2.2
$0
$2.4
Certifications
CVS and Technical Infeasibility
1,700
0
0
0
0
$2.7
$0
$0
$2.7
TOTAL
170,000
0
0
0
0
$11
$64
$0
$76
Note: Estimates may not sum due to independent rounding.
3-36
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Table 3-13 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Option 2, 2021


Forgone Emissions Reductions
Compliance Cost Reductions (millions $2016)

Projected No. of



Methane
Annualized


Total Annualized

Reconsideration-
Methane
voc
HAP
(metric
Planning
Operating
Forgone
Cost Reductions

impacted
(short
(short
(short
tons CO2
Cost
and
Product
with Forgone
Source/Emissions Point
Sources
tons)
tons)
tons)
Eq.)
Reductions
Maintenance
Recovery
Revenues
Fugitive Emissions









Non-Low Production Well Sites
42,000
0
0
0
0
$2.3
$16
$0
$18
Low Production Well Sites
18,000
14,000
3,900
150
320,000
$2.8
$28
$1.8
$29
Gathering and Boosting Stations
1,500
0
0
0
0
$0,099
$1.0
$0
$1.1
Certifications









CVS and Technical Infeasibility
1,600
0
0
0
0
$2.5
$0
$0
$2.5
TOTAL
63,000
14,000
3,900
150
320,000
$7.6
$45
$1.8
$51
Note: Estimates may not sum due to independent rounding.








Table 3-14 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Option 2, 2030



Forgone Emissions Reductions
Compliance Cost Reductions (millions $2016)

Projected No. of



Methane
Annualized


Total Annualized

Reconsideration-
Methane
VOC
HAP
(metric
Planning
Operating
Forgone
Cost Reductions

impacted
(short
(short
(short
tons CO2
Cost
and
Product
with Forgone
Source/Emissions Point
Sources
tons)
tons)
tons)
Eq.)
Reductions
Maintenance
Recovery
Revenues
Fugitive Emissions









Non-Low Production Well Sites
88,000
0
0
0
0
$4.8
$34
$0
$38
Low Production Well Sites
73,000
64,000
18,000
670
1,500,000
$12
$120
$11
$120
Gathering and Boosting Stations
3,400
0
0
0
0
$0.23
$2.2
$0
$2.4
Certifications
CVS and Technical Infeasibility	1,700	0	0	0	0	$2.7	$0	$0	$2.7
TOTAL	170,000	64,000 18,000 670 1,500,000	$20	$160	$11	$170
Note: Estimates may not sum due to independent rounding.
3-37
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Table 3-15 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Finalized Option 3, 2021


Forgone Emissions Reductions
Compliance Cost Reductions (millions $2016)

Projected No. of



Methane



Total Annualized

Reconsideration-
Methane
voc
HAP
(metric
Planning
Operating
Forgone
Cost Reductions

impacted
(short
(short
(short
tons CO2
Cost
and
Product
with Forgone
Source/Emissions Point
Sources
tons)
tons)
tons)
Eq.)
Reductions
Maintenance
Recovery
Revenues
Fugitive Emissions









Non-Low Production Well Sites
42,000
0
0
0
0
$2.3
$16
$0
$18
Low Production Well Sites
18,000
14,000
3,900
150
320,000
$2.8
$28
$1.8
$29
Gathering and Boosting Stations
1,500
4,900
1,400
52
110,000
$0.10
$7.8
$0.63
$7.3
Certifications









CVS and Technical Infeasibility
1,600
0
0
0
0
$2.5
$0
$0
$2.5
TOTAL
63,000
19,000
5,200
200
430,000
$7.6
$52
$2.4
$57
Note: Estimates may not sum due to independent rounding.








Table 3-16 Incrementally Affected Sources, Forgone Emissions Reductions, and Cost Reductions, Finalized Option 3, 2030


Forgone Emissions Reductions
Compliance Cost Reductions (millions $2016)

Projected No. of



Methane



Total Annualized

Reconsideration-
Methane
VOC
HAP
(metric
Planning
Operating
Forgone
Cost Reductions

impacted
(short
(short
(short
tons CO2
Cost
and
Product
with Forgone
Source/Emissions Point
Sources
tons)
tons)
tons)
Eq.)
Reductions
Maintenance
Recovery
Revenues
Fugitive Emissions









Non-Low Production Well Sites
88,000
0
0
0
0
$4.8
$34
$0
$38
Low Production Well Sites
73,000
64,000
18,000
670
1,500,000
$12
$120
$11
$120
Gathering and Boosting Stations
3,400
11,000
3,100
120
260,000
$0.23
$18
$1.9
$16
Certifications
CVS and Technical Infeasibility	1,700	0	0	0	0	$2.7	$0	$0	$2.7
TOTAL	170,000	75,000 21,000 790 1,700,000 $20	$170	$13	$180
Note: Estimates may not sum due to independent rounding.
3-38
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3.2.9 Present Value and Equivalent Annualized Value of Cost Reductions
This section presents the cost reductions for this final action in a present value (PV) framework.
The stream of estimated cost reductions for each year from 2021 through 2030 is discounted to
2020	using 7 and 3 percent discount rates and summed to estimate the PV of the cost reductions.
This PV represents the sum of the annual cost reductions from 2021 to 2030. The PV is used to
estimate the equivalent annualized value (EAV) of the cost reductions. The EAV is the single
annual value which, if summed in PV terms across years in the analytical time frame, equals the
PV of the original {i.e., likely time-varying) stream of cost reductions. In other words, the EAV
takes the potentially "lumpy" stream of cost reductions and converts them into a single value
that, when discounted and added together over each period in the analysis time frame, equals the
original stream of values in PV terms.
The cost reductions are presented as the change in costs compared to the baseline in 2016
dollars. We evaluate the change in costs for each year where reconsideration-impacted sources
are expected to change their compliance activities from the 2016 NSPS OOOOa as a result of
this reconsideration, through 2030. For this final action, the change in compliance activities is
expected to lead to cost reductions. We have chosen not to evaluate impacts beyond 2030 in part
due to the limited information available to model long-term changes in practices and equipment
use in the oil and natural gas sector. Technological progress in control technology and other
economy-wide factors are likely to change the industry significantly over a longer time horizon.
Table 3-17 shows the unannualized, undiscounted stream of cost reductions for each year from
2021	to 2030. Planning cost reductions are estimated as the sum of the difference in costs of the
design of fugitive emissions monitoring plans for new reconsideration-impacted facilities, the
difference in costs of the redesign of fugitive emissions monitoring plans for reconsideration-
impacted facilities that were affected by the 2016 NSPS OOOOa 8 years prior, and the difference
in costs of certification for closed vent system design and pneumatic pump technical infeasibility
for new reconsideration-impacted sources compared to the updated baseline. Total cost
reductions are the sum of the planning cost reductions and annual operating cost reductions.
Over time, as the number of new reconsideration-affected sources increases, the planning cost
reductions and annual operating cost reductions also increase.
3-39
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Table 3-17 Estimated Cost Reductions for Finalized Option 3, 2021-2030 (millions
2016$)	
Year
Planning Cost
Reductions1
Operating and
Maintenance
Cost
Reductions
Total Cost
Reductions (w/o
Forgone Revenue)2
Forgone
Revenue from
Product
Recovery
Total Cost
Reductions
(with Forgone
Revenue)
2021
$6.9
$52
$59
$2.4
$56
2022
$7.2
$62
$70
$3.0
$67
2023
$15
$74
$89
$3.7
$85
2024
$11
$87
$98
$4.6
$93
2025
$12
$100
$110
$5.8
$110
2026
$14
$110
$130
$7.3
$120
2027
$14
$130
$140
$8.8
$130
2028
$14
$140
$160
$10
$150
2029
$15
$160
$170
$11
$160
2030
$15
$170
$190
$13
$180
Note: Estimates may not sum due to independent rounding.
1	The planning cost reductions include the cost reductions incurred by the newly affected sources for both fugitive
emissions monitoring and certifications, as well as the cost reductions of emissions sources that renew survey
monitoring plans after 8 years.
2	Total cost reductions include the planning cost reductions for all fugitive emissions monitoring, plus the annual
operating and maintenance cost reductions for the fugitive emissions monitoring requirements every year, plus the
cost reductions of certifications in each year, plus the cost reductions from streamlined recordkeeping and reporting.
Table 3-18 shows the stream of cost reductions discounted to 2020 using a 7 percent discount
rate for the finalized Option 3. Table 3-18 also shows the PV and the EAV of planning cost
reductions, annual operating cost reductions, forgone revenue from decreased product recovery
and the total cost reductions (after accounting for the forgone product recovery). The PV of total
cost reductions is $750 million, and the EAV of total cost reductions is about $100 million per
year.
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Table 3-18 Discounted Cost Reductions Estimates for Finalized Option 3, 7 Percent
Discount Rate (millions 2016$)	
Year
Planning Cost
Reductions1
Operating and
Maintenance
Cost
Reductions
Total Cost
Reductions (w/o
Forgone
Revenue)2
Forgone
Revenue from
Product
Recovery
Total Cost
Reductions
(with Forgone
Revenue)
2021
$6.5
$48
$55
$2.2
$52
2022
$6.3
$55
$61
$2.6
$58
2023
$12
$61
$73
$3.0
$70
2024
$8.5
$66
$75
$3.5
$71
2025
$8.7
$71
$80
$4.2
$76
2026
$9.2
$76
$85
$4.9
$80
2027
$8.7
$80
$88
$5.5
$83
2028
$8.4
$83
$91
$5.9
$85
2029
$8.0
$85
$93
$6.2
$87
2030
$7.7
$88
$95
$6.4
$89
PV
$84
$710
$800
$44
$750
EAV
$11
$95
$110
$5.9
$100
Note: Cost reductions and forgone revenue in each year are discounted to 2020. Estimates may not sum due to
independent rounding.
1	The planning cost reductions include the cost reductions incurred by the newly affected sources for both fugitive
emissions monitoring and certifications in each year, as well as the fugitive monitoring cost reductions for sources
that renew their monitoring plans after 8 years.
2	Total cost reductions include the planning cost reductions for all fugitive emissions monitoring, plus the annual
operating and maintenance cost reductions for the fugitive emissions monitoring requirements every year, plus the
cost reductions of certifications in each year, plus the cost reductions from streamlined recordkeeping and reporting
discounted to 2020.
Table 3-19 shows the discounted cost reductions for the finalized Option 3, as well as the
alternative options, for the 2021 to 2030 period compared to the baseline, along with the PV and
EAV of the cost reductions, using a 7 percent discount rate. We estimate that Option 1 results in
a PV of cost reductions of $350 million, corresponding to an EAV of $46 million. For Option 2,
we estimate a PV of cost reductions of $680 million, after accounting for the forgone value of the
decrease in product recovery, and a corresponding EAV of $91 million. For the finalized Option
3, we estimate a PV of $750 million in cost reductions after accounting for forgone product
recovery, and about $100 million per year in EAV terms.
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Table 3-19 Comparison of Regulatory Alternatives, 7 Percent Discount Rate
Option 1
Option 2
Option 3
(Finalized)
Present Value of Cost Reductions
Cost Reductions (millions 2016$)
Planning Cost Reductions
Total Cost Reductions w/o Forgone Revenue
Total Cost Reductions with Forgone Revenue
$58
$350
$350
$84
$720
$680
$84
$800
$750
EAV of Cost Reductions
Cost Reductions (millions 2016$)
Planning Cost Reductions
Total Cost Reductions w/o Forgone Revenue
Total Cost Reductions with Forgone Revenue
$7.8
$46
$46
$11
$96
$91
$11
$110
$100
Table 3-20 shows how the choice of discount rate affects the PVs and EAVs. A lower discount
rate means that higher cost reductions in later years have a greater impact on PV and EAV.
Therefore, the PV and EAV of the cost reductions are higher using a 3 percent discount rate than
a 7 percent discount rate. Using a 3 percent discount rate increases the PV of the cost reductions
by 27 percent compared to the 7 percent rate. For the EAV, using a 3 percent discount rate
increases the annualized cost reductions by about 15 percent compared to the 7 percent rate.
Table 3-20 Cost Reductions for the Finalized Option 3 Discounted at 7 and 3 Percent
Rates (millions 2016$)	


7 Percent


3 Percent

Year
Total Annual
Cost Reductions
(without
forgone
revenue)
Forgone
Revenue from
Product
Recovery
Total Cost
Reductions
(with forgone
revenue)1
Total Annual
Cost Reductions
(without
forgone
revenue)
Forgone
Revenue from
Product
Recovery
Total Cost
Reductions
(with forgone
revenue)1
2021
$55
$2.2
$52
$57
$2.3
$55
2022
$61
$2.6
$58
$66
$2.8
$63
2023
$73
$3.0
$70
$81
$3.4
$78
2024
$75
$3.5
$71
$87
$4.0
$83
2025
$80
$4.2
$76
$97
$5.0
$92
2026
$85
$4.9
$80
$110
$6.1
$100
2027
$88
$5.5
$83
$120
$7.2
$110
2028
$91
$5.9
$85
$120
$8.1
$120
2029
$93
$6.2
$87
$130
$8.8
$120
2030
$95
$6.4
$89
$140
$9.4
$130
PV
$800
$44
$750
$1,000
$57
$950
EAV
$110
$5.9
$100
$110
$6.5
$110
Note: Cost reductions in each year are discounted to 2020. Estimates may not sum due to independent rounding.
1 Total cost reductions include the planning cost reductions for all fugitive emissions monitoring, plus the annual
operating and maintenance cost reductions for the fugitive emissions monitoring requirements every year, plus the
3-42
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cost reductions of certifications in each year, plus the cost reductions from streamlined recordkeeping and reporting
requirements discounted to 2020.
The Technical Reconsideration is considered a deregulatory action under E.O. 13771, Reducing
Regulation and Controlling Regulatory Costs. The PV of the projected cost reductions from the
Technical Reconsideration calculated in accordance with E.O. 13771 accounting standards are
$1.1 billion over an infinite time horizon (in 2016$, discounted to 2016 at 7 percent). The EAV
of the cost reductions over an infinite time horizon are $76 million per year (in 2016$,
discounted to 2016 at 7 percent).
3.3 Forgone Benefits of the Technical Reconsideration
The 2016 NSPS OOOOa regulated methane and VOC emissions in the oil and natural gas sector.
For the 2016 NSPS OOOOa, the EPA projected climate and ozone benefits from methane
reductions, ozone and fine particulate matter (PM2.5) health benefits from VOC reductions, and
health benefits from ancillary HAP emissions reduction. These benefits were expected because
compliance with the standards would simultaneously reduce methane, VOC, and HAP
emissions.97
As in the 2016 NSPS RIA, methane is the only pollutant with monetized impacts in this RIA.
The finalized Option 3 is estimated to increase emissions relative to the baseline. The total
forgone emissions reductions from 2021 to 2030 is estimated to be about 450,000 short tons of
methane, 120,000 short tons of VOC and 4,700 short tons of HAP. The methane emissions are
10 million metric tons in CO2 Eq. The PV of the forgone domestic methane-related climate
benefits is $19 million from 2021 to 2030 using an interim estimate of the domestic social cost of
methane (SC-CH4) and discounting at a 7 percent rate. The associated EAV is an estimated $3.2
million per year. Using the interim SC-CH4 estimate and discounting at a 3 percent rate, the PV
of the forgone domestic climate benefits is estimated to be $71 million and the EAV is estimated
to be $11 million per year.
97 The specific control techniques required for the 2016 NSPS OOOOa were also anticipated to have minor
disbenefits resulting from secondary emissions of carbon dioxide (CO2), nitrogen oxides (NOx), PM, carbon
monoxide (CO), and total hydrocarbons (THC), and emission changes associated with the energy markets
impacts. This final action is anticipated to reduce these minor secondary emissions.
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Under the final action, the EPA expects that the forgone VOC emission reductions will worsen
air quality and adversely affect health and welfare due to the contribution of VOCs to ozone,
PM2.5, and HAP, but we are unable to quantify these impacts at this time. This omission should
not imply that these forgone benefits do not exist, and to the extent that the EPA were to quantify
the ozone and PM impacts, it would estimate the number and value of avoided premature deaths
and illnesses using the approach detailed in the PM National Ambient Air Quality Standards
(NAAQS) and Ozone NAAQS RIAs (U.S. EPA, 2012; U.S. EPA, 2014).98
For much of Section 3.3, we direct readers to refer to the forgone benefits presentation in
Chapter 2 (Section 2.3), as the forgone benefits analysis for the Technical Reconsideration
mirrors the one for the Policy Review. For a summary of the climate and human health-related
impacts associated with the forgone emissions reductions of the pollutants affected by this rule,
see Table 2-12 in Section 2.3.1. Section 2.3 provides further reasoning for not quantifying the
impacts of the forgone VOC emissions reductions in this RIA.
3.3.1 Forgone Emissions Reductions
Table 3-21 shows the total increase in direct emissions for 2021 to 2030, compared to the
baseline, anticipated for this final action for the regulatory options examined. It is important to
note that the impacts of these emissions accrue at different spatial scales. HAP emissions
increase exposure to carcinogens and other toxic pollutants primarily near the emission source.
VOC emissions are precursors to the formation of PM2.5 and ozone on a broader regional scale.
Climate effects associated with long-lived greenhouse gases like methane generally do not
depend on the location of the emissions and have global impacts. Methane is also a precursor to
global background concentrations of ozone (Sarofim, 2015).
98 The Technical Reconsideration may result in forgone reductions in ambient PM2 5 and ozone concentrations in
areas attaining and not attaining the NAAQS. Due to the high degree of variability in the responsiveness of
ozone and PM2 5 formation to VOC emission reductions, we are unable to determine how this rule might affect
attainment status without modeling air quality changes. Because the NAAQS RIAs also calculate ozone and
PM2 5 benefits, there are important differences worth noting in the design and analytical objectives of each
impact analysis. The NAAQS RIAs illustrate the potential costs and benefits of attaining new nationwide air
quality standards based on an array of emission control strategies for different sources. By contrast, the emission
reductions for implementation rules, including this rule, are generally from a specific class of well-characterized
sources. In general, the EPA is more confident in the magnitude and location of the emission reductions for
implementation rules rather than illustrative NAAQS analyses. Emission changes realized under these and other
promulgated rules will ultimately be reflected in the baseline of future NAAQS analyses, which would affect the
incremental costs and benefits associated with attaining future NAAQS.
3-44
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Table 3-21 Total Direct Increases in Emissions, 2021-2030
Pollutant
Option 1
Option 2
Option 3
(Finalized)
Methane (short tons)
0
370,000
450,000
VOC (short tons)
0
100,000
120,000
HAP (short tons)
0
3,800
4,700
Methane (metric tons)
0
330,000
410,000
Methane (million metric tons CO2 Eq.)
0
8.3
10
Table 3-22 shows the direct increases in emissions of methane, VOC, and HAP for Option 2 and
Option 3 for each year, compared to the baseline. Option 1 is not included in this table, as there
are no estimated changes in emissions under Option 1.
Table 3-22 Annual Direct Increases in Methane, VOC and HAP Emissions, 2021-2030
Option 2	Option 3 (Finalized)
Year
Methane
(metric tons)
VOC
(short tons)
HAP
(short tons)
Methane
(metric tons)
VOC
(short tons)
HAP
(short tons)
2021
13,000
3,900
150
17,000
5,200
200
2022
16,000
4,900
190
21,000
6,500
250
2023
20,000
6,200
230
26,000
7,900
300
2024
25,000
7,500
280
31,000
9,500
360
2025
29,000
9,000
340
36,000
11,000
420
2026
35,000
11,000
400
42,000
13,000
490
2027
40,000
12,000
460
48,000
15,000
560
2028
46,000
14,000
530
55,000
17,000
630
2029
52,000
16,000
600
61,000
19,000
710
2030
58,000
18,000
670
68,000
21,000
790
Total
330,000
100,000
3,800
410,000
120,000
4,700
Note: Estimates may not sum due to independent rounding.
3.3.2 Methane Climate Effects and Valuation
The 2016 NSPS OOOOa was expected to result in climate-related benefits by reducing methane
emissions. This action reduces the climate-related benefits associated with the emissions
reductions from the 2016 NSPS OOOOa. We estimate the forgone climate benefits under the
finalized and alternative options for the Technical Reconsideration using an interim measure of
the domestic social cost of methane (SC-CH4). See Section 2.3.3 for discussion of the climate
effects associated with methane emissions and the valuation approach (i.e., SC-CH4) used in this
RIA to estimate the impacts of forgone methane emissions reductions.
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For the finalized Option 3 (presented in Table 2-4), the forgone methane reductions estimated for
2021 (0.43 million metric tons CO2 Eq.) are equivalent to about 0.2 percent of the methane
emissions for this sector reported in the GHGI in 2017 (about 197 million metric tons CO2 Eq.
are from petroleum and natural gas production and gas processing, transmission, and storage).
Expected forgone emission reductions in 2030 (about 1.7 million metric tons CO2 Eq.) are
equivalent to around 0.9 percent of 2017 methane emissions.
As with the global SC-CH4 estimates, the domestic SC-CH4 increases over time because future
emissions are expected to produce greater marginal damages and because GDP generally grows
over time and many damage categories are modeled in proportion to gross GDP. To monetize the
forgone domestic climate benefits, the projected increases in methane emissions due to this
regulatory action each year are multiplied by the SC-CH4 estimate for that year. See Table 2-15
in Section 2.3.3 for the average interim domestic SC-CH4 estimates developed under E.O. 13783
for emissions occurring in 2021 to 2030 and Section 2.3.3 and Appendix B for discussion of the
limitations and uncertainties associated with the SC-CH4 estimates. Appendix B also presents the
forgone global climate benefits from the finalized option using global SC-CH4 estimates based
on both 3 and 7 percent discount rates.
Table 3-23 presents the monetized forgone domestic climate benefits for the finalized Option 3,
both undiscounted and discounted. It shows the annual forgone benefits discounted back to 2020
and the PV and the EAV for 2021 to 2030 under each discount rate. Regardless of whether they
are discounted, the annual forgone benefits increase between 2021 and 2030 as the number of
sources impacted by this Technical Reconsideration grows over time.
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Table 3-23 Estimated Forgone Domestic Climate Benefits of Option 3, 2021-2030
(millions, 2016$)	
Undiscounted
Discounted to 2020
Year
7 percent
3 Percent
7 percent
3 Percent
2021
$1.0
$3.1
$0.9
$3.0
2022
$1.3
$4.0
$1.1
$3.7
2023
$1.6
$5.0
$1.3
$4.6
2024
$2.0
$6.1
$1.5
$5.5
2025
$2.5
$7.4
$1.8
$6.4
2026
$3.0
$8.9
$2.0
$7.4
2027
$3.5
$10
$2.2
$8.5
2028
$4.1
$12
$2.4
$9.5
2029
$4.8
$14
$2.6
$11
2030
$5.5
$16
$2.8
$12
PV


$19
$71
EAV


$2.5
$8.1
Note: Estimates may not sum due to independent rounding.
Table 3-24 shows the total forgone emissions reductions over the time horizon as well as the PV
and EAV of the forgone domestic climate benefits using 3 percent and 7 percent discount rates.
The forgone climate benefits are highly sensitive to the choice of the discount rate, as climate
impacts accrue over long time horizons and models project increasing marginal damages
associated with greenhouse gas emissions over time. The PV of forgone benefits under a 7
percent discount rate is about $19 million, with an EAV of about $2.5 million per year. The PV
of forgone benefits under a 3 percent discount rate is $71 million, with an EAV of about $8.1
million per year.
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Table 3-24 Total Estimated Forgone Domestic Climate Benefits (millions, 2016$)

Option 1
Option 2
Option 3
(Finalized)
Total Increase in Emission, 2021-2030



Forgone CH4 reductions (metric tons)
0
330,000
410,000
Forgone CH4 reductions (million
metric tons of CO2 Eq.)
0
8.3
10
Forgone Domestic Climate Benefits (millions 2016$)


PV



3% (average)
$0
$58
$71
7% (average)
$0
$15
$19
EAV



3% (average)
$0
$6.6
$8.1
7% (average)
$0
$2.0
$2.5
The SC-CH4 values are dollar-year and emissions-year specific. SC-CH4 values represent only a partial accounting
of climate impacts.
3.3.3	VOC as an Ozone Precursor
This final action is expected to result in forgone VOC emission reductions, which are a precursor
to ozone. The impacts of forgone VOC emission reductions are not monetized in this RIA. See
Section 2.3.4 for a qualitative discussion of the forgone ozone benefits associated with forgone
VOC emission reductions. Sections 2.3.4.1, 2.3.4.2, and 2.3.4.3 discuss the health, vegetation,
and climate effects of ozone, respectively.
3.3.4	VOC as a PM2.5 Precursor
This final action is expected to result in forgone emission reductions of VOC, a precursor to
PM2.5, which is associated with impacts on human health. We have not quantified the forgone
PM2.5-related benefits due to this rule. See Sections 2.3.5.1, 2.3.5.2, and 2.3.5.3 for qualitative
discussions of the health, welfare, and visibility effects, respectively, associated with PM2.5.
3.3.5	Hazardous Air Pollutants (HAP)
This rulemaking is expected to result in forgone emission reductions of HAP, or air toxics.
Available emissions data show that several different HAP are emitted from oil and natural gas
operations, from equipment leaks, processing, compressing, transmission and distribution, and
storage tanks. The main air toxics emitted by the source category include benzene, toluene,
carbonyl sulfide, ethylbenzene, mixed xylenes, and n-hexane. This rule is anticipated to result in
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a total of 3,800 short tons of forgone HAP emissions reductions over 2021 to 2030, although it
was not possible to estimate the changes in emissions of individual HAP due to data limitations.
Non-cancer health problems can result from chronic, subchronic, or acute inhalation exposure to
air toxics, and include neurological, cardiovascular, liver, kidney, and respiratory effects as well
as effects on the immune and reproductive systems. Section 2.3.6 discusses the EPA's
assessment (i.e., the National Air Toxics Assessment, or NATA) of the cancer and non-cancer
health effects associated with exposure to air toxics. In the subsections within Section 2.3.6, we
provide greater detail on the health effects associated with the main HAP of concern for the oil
and natural gas sector: benzene, toluene, carbonyl sulfide, ethylbenzene, mixed xylenes, n-
hexane, and several other air toxics.
3.4 Economic Impacts and Distributional Assessments
The EPA evaluated the following economic impact categories for this final Technical
Reconsideration: energy market impacts, distributional impacts, small business impacts, and
employment impacts. For much of this section, we direct readers to refer to the presentation of
economic impacts in Chapter 2 (Section 2.5), as the methods used and several of the findings of
the economic impact analysis for the Technical Reconsideration mirror those of the Policy
Review.
3.4.1	Energy Markets Impacts
The RIA for the 2016 NSPS OOOOa concluded that the rule may have impacts on energy
production and markets. Like the Policy Review, the Technical Reconsideration is expected to
reduce compliance costs incurred by oil and natural gas sources. Thus, the finalized Option 3 for
the Technical Reconsideration, like the Policy Review, is expected to reduce the energy market
impacts associated with the 2016 NSPS OOOOa. See Section 2.4.1 for a summary of the energy
market impact analysis conducted in the RIA for the 2016 NSPS OOOOa.
3.4.2	Distributional Impacts
The cost reductions and forgone health benefits associated with the Technical Reconsideration
may be distributed unevenly across the U.S. population. The EPA did not conduct a quantitative
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assessment of distributional impacts for the Technical Reconsideration, but we provide a
qualitative discussion of the types of distributional impacts that could result from this final action
in the Policy Review. See Section 2.4.2 and subsection 2.4.2.1 for details.
3.4.3 Small Business Impacts
The Regulatory Flexibility Act (RFA; 5 U.S.C. ง601 et seq.), as amended by the Small Business
Regulatory Enforcement Fairness Act (Public Law No. 104121), provides that whenever an
agency publishes a proposed rule, it must prepare and make available an initial regulatory
flexibility analysis (IRFA), unless it certifies that the rule, if promulgated, will not have a
significant economic impact on a substantial number of small entities (5 U.S.C. ง605[b]). Small
entities include small businesses, small organizations, and small governmental jurisdictions. An
IRFA describes the economic impact of the rule on small entities and any significant alternatives
to the rule that would accomplish the objectives of the rule while minimizing significant
economic impacts on small entities.
An agency may certify that a rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no net burden, or otherwise
has a positive economic effect on small entities subject to the rule. Like the Policy Review
described in Chapter 2 of this RIA, this reconsideration reduces the stringency of the
requirements on a substantial portion of the sources affected by the 2016 NSPS OOOOa, and
thus reduces the impacts of NSPS OOOOa. In addition, the three options being analyzed in this
RIA would result in neutral or beneficial effects on the affected facilities. The Technical
Reconsideration decreases the burden on affected sources through direct changes in the
requirements, increased clarity of requirements (for example, through more robust definitions),
finalizing alternative fugitive emissions standards, and the streamlining of recordkeeping and
reporting requirements. We have therefore concluded that this final action will relieve regulatory
burden on small entities affected by the reconsidered provisions.
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3.4.4 Employment Impacts
In addition to addressing the costs and emissions reductions estimated for the final
reconsideration, the EPA has analyzed the impacts of this rulemaking on employment." Using
detailed engineering information on labor requirements for the reconsidered provisions, we
estimate partial employment impacts for affected entities in the oil and natural gas industry.
These bottom-up, engineering-based estimates represent only one portion of potential
employment impacts within the regulated industry and do not represent estimates of the net
employment impacts of this rule. Due to data and methodology limitations, other potential
employment impacts in the affected industry and impacts in related industries are not estimated.
For an overview of the various ways that environmental regulation can affect employment, see
Section 2.4.4 and subsection 2.4.4.1.
We estimate the impacts of the Technical Reconsideration on the labor required to comply with
the 2016 NSPS OOOOa. We estimate the incremental change due to the reconsideration, as
compared to the baseline, in labor required to satisfy environmental mitigation requirements as
well as reporting and recordkeeping requirements. Most of the estimated change in labor
requirements relative to the baseline come from the changes to the fugitive emissions program.
The labor estimates include labor associated with company-level activities and activities at field
sites. Company-level activities included one-time "up-front" activities such as planning the
company's fugitive emissions program and annual requirements such as reporting and
recordkeeping. Field-level activities included inspection and repair of leaks. The labor
information is based upon the cost analysis presented in the TSD that supports this rule.
Table 3-25 presents the incremental change in labor required to comply with the NSPS due to the
final amendments at the facility level in hours per facility per year. The change in estimates for
each of the facility types reflect the following changes from the baseline:
99 The employment analysis in this RIA is part of the 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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•	Well sites: change from semiannual fugitives monitoring requirements to streamlined
requirements for semiannual monitoring and alternative fugitive emissions standards in
relevant areas.100
•	Well sites (low production): change from semiannual fugitives monitoring requirements
to no monitoring requirements.
•	Gathering and Boosting Stations: change from quarterly fugitives monitoring
requirements to streamlined requirements for quarterly monitoring.101
•	Certifications: change from requirement that professional engineer perform certification
to an in-house engineer performing certifications.
Table 3-25 Facility-level Changes in Labor Required to Comply with NSPS OOOOa
(hours per facility per year)	
Upfront Annual Labor Estimate	Annual Labor Estimate
(hours per facility per year)	(hours per facility per year)
Recon- Incremental	Recon- Incremental
	Facility	Baseline sideration Change Baseline sideration Change
Well Sites
Annual monitoring
8.5
2
-6.5
12.5
10
-2.5
Semiannual monitoring
8.5
2
-6.5
18.6
14.6
-4
Well Sites (Low Production)






Annual monitoring
8.5
0
-8.5
10.3
0
-10.3
Semiannual monitoring
8.5
0
-8.5
14.2
0
-14.2
Compressor Stations






Gathering and Boosting
10.6
4.1
-6.5
65.7
37.5
-28.2
Certifications
6
5
-1
0
0
0
Tables 3-26 and 3-27 present estimates of the decrease in upfront labor requirements for
compliance requirements for non-low production well sites, low production well sites, gathering
and boosting stations, and certifications, respectively. The estimates are presented in terms of
FTE in these tables; in this analysis we assume one FTE equals 2,080 hours (the product of 40
100	Since the 2018 Amendment package reduced monitoring frequency at NSPS-affected well sites on the Alaska
North Slope from semiannual to annual frequency, Alaska well sites change from annual fugitives monitoring
requirements to streamlined annual requirements.
101	EPA is reducing the required monitoring frequency at NSPS-affected gathering and boosting stations from
quarterly to annual for those on the Alaska North Slope. We are unable to quantify the potential compliance-
related labor impacts associated with this provision.
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hours per week over 52 weeks). Reductions in labor increase from 2021 to 2030 as the number of
sites affected by the Technical Reconsideration accumulates.
Table 3-26 Estimates of the Decrease in Upfront Labor Required (in FTE), 2021-2030
Year
Well Sites
Well Sites (Low
Production)
Gathering and
Boosting
Stations
Certifications
Total
2021
33
7.3
0.66
0.76
42
2022
35
7.6
0.66
0.79
44
2023
55
32
1.3
0.80
90
2024
46
19
1.3
0.81
67
2025
49
23
1.3
0.82
74
2026
53
28
1.3
0.82
83
2027
54
29
1.3
0.83
85
2028
55
30
1.3
0.83
87
2029
56
31
1.3
0.83
89
2030
57
32
1.3
0.83
91
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Estimates may not
sum due to independent rounding.
Table 3-27 Estimates of the Decrease in Annual Labor Required (in FTE), 2021-2030
Year
Well Sites
Well Sites (Low
Production)
Gathering and
Boosting
Stations
Certifications
Total
2021
340
120
20
0
490
2022
390
160
23
0
570
2023
440
190
26
0
660
2024
490
230
29
0
740
2025
530
270
32
0
830
2026
570
310
34
0
920
2027
610
360
37
0
1,000
2028
650
400
40
0
1,100
2029
690
450
43
0
1,200
2030
720
500
46
0
1,300
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Estimates may not
sum due to independent rounding.
The total incremental reductions in up-front labor requirements for the affected industry to
comply with the final reconsideration are estimated to increase from 42 FTE in 2021 to 91 FTE
in 2030. The total incremental reductions in annual labor requirements for the affected industry
to comply with the final reconsideration are estimated to increase from about 490 FTE in 2021 to
1,300 FTE in 2030.
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We note that this type of FTE estimate cannot be used to identify the specific number of
employees involved or whether new jobs are created for new employees, versus displacing jobs
from other sectors of the economy. As stated earlier, this rule is expected to result in little change
in oil and natural gas exploration and production and is not expected to result in significant
reductions to the labor dedicated to these tasks. For impacted oil and natural gas entities affected,
some reductions in labor from 2016 NSPS OOOOa-related requirements may be expected under
the final reconsideration. We did not estimate any potential impacts on labor outside of the
affected sector. For example, no estimates of labor requirements for manufacturing pollution
control equipment, or for producing the materials used in that equipment, are provided as the
EPA did not have the necessary information.
3.5 Comparison of Benefits and Costs
3.5.1 Comparison of Benefits and Costs
In this section, we present a comparison of the benefits and costs of this final Technical
Reconsideration across regulatory options. We refer to the cost reductions as the "benefits" of
this final action and the forgone benefits as the "costs" of this final action. The net benefits are
the benefits (cost reductions) minus the costs (forgone benefits). All costs and benefits in this
RIA are estimated relative to the baseline. The benefits, costs, and net benefits shown in this
section are presented in PV terms for 2021 to 2030 discounted to 2020 using 7 percent and 3
percent discount rates, along with the associated EAVs.
Table 3-28 shows the estimated benefits, costs and net benefits for Option 1, the most stringent
option. In this option, we estimate the impact of streamlined fugitive emissions monitoring
reporting and recordkeeping, certifying several state fugitive emissions monitoring programs as
alternative fugitive emissions standards, and in-house certifications. As there are no projected
changes in emissions under this unselected option, there are no costs (forgone benefits). For
option 1, at a 7 percent discount rate, the PV of net benefits is estimated to be $350 million with
an EAV of $46 million. At a 3 percent discount rate, the PV of net benefits is estimated to be
$440 million with an EAV of $50 million.
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Table 3-28 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone
Monetized Benefits, Cost Reductions, and Net Benefits for Unselected Option 1 from 2021
to 2030 (millions, 2016$)	


7%
3%

PV
EAV
PV
EAV
Benefits (Total Cost Reductions)
$350
$46
$440
$50
Cost Reductions
$350
$46
$440
$50
Forgone Value of Product Recovery
$0
$0
$0
$0
Costs (Forgone Domestic Climate Benefits)
$0
$0
$0
$0
Net Benefits
$350
$46
$440
$50
Note: Estimates may not sum due to independent rounding.
Table 3-29 shows the estimated benefits, costs and net benefits for Option 2. Option 2 results in
net benefits greater than those of Option 1, but less than those of Option 3. In this option, we
estimate the impact of removing of the fugitive emissions monitoring requirement for low
production well sites, streamlining fugitive emissions monitoring reporting and recordkeeping at
non-low production well sites and gathering and boosting stations, certifying several state
fugitive emissions monitoring programs as alternative fugitive emissions standards, and allowing
in-house engineering certifications for closed vent systems and infeasibility . For the finalized
Option 3, at a 7 percent discount rate, the PV of net benefits is estimated to be $670 million with
an EAV of $89 million. At a 3 percent discount rate, the PV of net benefits is estimated to be
$810 million with an EAV of $92 million.
Table 3-29 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone
Monetized Benefits, Cost Reductions, and Net Benefits for Unselected Option 2 from 2021
to 2030 (millions, 2016$)	
7%
3%

PV
EAV
PV
EAV
Benefits (Total Cost Reductions)
$680
$91
$860
$98
Cost Reductions
$720
$96
$910
$100
Forgone Value of Product Recovery
$36
$4.8
$47
$5.3
Costs (Forgone Domestic Climate Benefits)
$15
$2.0
$58
$6.6
Net Benefits
$670
$89
$810
$92
Note: Estimates may not sum due to independent rounding.
Table 3-30 shows the estimated benefits, costs and net benefits for the finalized Option 3. Option
3 is estimated to have the greatest cost reductions, forgone benefits, and net benefits of the three
options analyzed. The finalized Option 3 is identical to Option 2 with the exception that fugitive
emissions monitoring and repair frequency at gathering and boosting stations is reduced from
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quarterly to semiannual. For Option 3, the PV of net benefits is estimated to be $730 million with
an EAV of $97 million at a 7 percent discount rate. The PV of net benefits is estimated to be
$880 million with an EAV of $100 million at a 3 percent discount rate.
Table 3-30 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone
Monetized Benefits, Cost Reductions, and Net Benefits for Finalized Option 3 from 2021 to
2030 (millions, 2016$)	
7%
3%

PV
EAV
PV
EAV
Benefits (Total Cost Reductions)
$750
$100
$950
$110
Cost Reductions
$800
$110
$1,000
$110
Forgone Value of Product Recovery
$44
$5.9
$57
$6.5
Costs (Forgone Domestic Climate Benefits)1
$19
$2.5
$71
$8.1
Net Benefits2
$730
$97
$880
$100
Note: Estimates may not sum due to independent rounding.
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions. See Section 2.3 for
more discussion.
Table 3-31 provides a summary of the forgone emissions reductions for each regulatory option.
There are no changes in emissions estimated as a result of Option 1. Option 3 results in the
greatest forgone emissions reductions compared to the baseline.
Table 3-31 Summary of Total Forgone Emissions Reductions across Options, 2021-2030
Pollutant
Option 1
Option 2
Option 3
(Finalized)
Methane (short tons)
0
370,000
450,000
VOC (short tons)
0
100,000
120,000
HAP (short tons)
0
3,800
4,700
Methane (metric tons)
0
330,000
410,000
Methane (million metric tons CO2 Eq.)
0
8.3
10
3.5.2 Uncertainties and Limitations
There are several sources of uncertainty regarding the forgone emissions reductions, forgone
benefits, and cost reductions estimated in this RIA for the Technical Reconsideration. We
summarize the key uncertainties and limitations here:
Source-level compliance costs and emissions impacts: As discussed in Section 3.2.2, the first
step in the compliance cost analysis is the development of per-facility national-average
representative costs and emissions impacts using a model plant approach. The model plants are
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designed based upon the best information available to the Agency at the time of the rulemaking.
By emphasizing facility averages, geographic variability and heterogeneity across producers in
the industry may be masked, and regulatory impacts at the facility-level may vary from the
model plant averages.
Projection methods and assumptions: As discussed in Section 3.2.3, the second step in
estimating national impacts is the projection of affected facilities. Uncertainty in the projections
informing this chapter include uncertainties such as: 1) choice of projection method; 2) data
sources and drivers; 3) limited information about rate of modification and turnover of sources; 4)
behavioral responses to regulation; and 5) unforeseen changes in industry and economic shocks.
Over time, more facilities are 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 NSPS OOOOa
accumulates. The impacts of this rule are highly influenced by projections and growth rates for
drilling activity in the AE02020. To the extent actual drilling activities diverge from the AEO
projections, the regulatory impacts will diverge from those shown in this RIA. The projection of
low production well sites also relies on a series of assumptions that introduce substantial
uncertainties, which are discussed in Section 3.2.3. These uncertainties include the assumption
that past production levels can be used to predict future production and the assumption that there
are two wells per site with identical production profiles. The dataset used to estimate the
transition proportions may also exclude wells that were shut-in since completion, which would
lead to over-estimates of compliance cost and emissions impacts.
Additionally, some emissions reducing technologies have become common industry practice
under the oil and natural gas sector NSPS. However, by removing regulatory requirements, there
may be incentives to reduce use of these technologies, introducing uncertainties in how regulated
entities may respond both directly and indirectly to the removal of NSPS requirements.
The projections do not account for potential changes in technological progress in the oil and gas
industry. Additionally, unforeseen economic shocks may affect the rule's impacts, such as
unexpected economic growth or recessions. For example, the projections in this RIA do not
account for potential effects of economic shocks arising from the coronavirus pandemic.
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Years of analysis: The years of analysis are 2021, to represent the first-year facilities are
affected by this Technical Reconsideration, through 2030, to represent impacts of the rule over a
longer period. While it is desirable to analyze impacts beyond 2030, the EPA has chosen not to
do so largely because of the limited information available on the turnover rate of emissions
sources and controls. Extending the analysis beyond 2030 would introduce increasing
uncertainties in projected impacts of the final reconsideration.
Fugitive emissions monitoring requirements and alternative fugitive emissions standards:
The EPA reviewed state regulations and permitting requirements. Emissions reductions from
applicable facilities under state requirements that are considered equivalent to the NSPS are
included in the baseline for this analysis. We also estimate cost reductions from deeming
programs in six states as equivalent to NSPS OOOOa, which reduces reporting and
recordkeeping burden for sources regulated under those programs. We made simplifying
assumptions to estimate the cost reductions associated with the reduced recordkeeping for
affected facilities regulated under the state programs deemed equivalent to NSPS OOOOa.102
Due to uncertainty regarding these assumptions, there is uncertainty in the assumed cost
reductions from reduced federal reporting and recordkeeping requirements for facilities under
alternative fugitive emissions standards.
Wellhead natural gas prices used to estimate forgone revenues from natural gas recovery:
The cost reductions estimated in this RIA include the forgone revenue associated with the
decrease in natural gas recovery resulting from forgone emissions reductions. As a result, the
forgone revenues in the cost reduction estimates depend on the price of natural gas. The natural
gas prices used in this analysis are from the projection of the Henry Hub price in the AE02020.
As with any modeling of prices, many assumptions regarding future economic activity and
several of the data sources used to inform the AEO in projecting natural gas prices are subject to
uncertainty. To the extent actual natural gas prices diverge from the AEO projections, the
impacts estimated in this RIA will diverge from actual impacts.
102 For example, we assume that operators in equivalent states will continue to incur company-level reporting and
recordkeeping costs related to reading the rule, developing a fugitive emissions monitoring plan, and establishing
and maintaining a database. If an affected entity operates solely within an equivalent area, the entity would not
incur any of these costs due to federal requirements, and thus cost reductions for such an entity's facilities would
be understated in the impact estimates in this RIA.
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Monetized forgone methane-related climate benefits: The EPA considered the uncertainty
associated with the social cost of methane (SC-CH4) estimates, which were used to estimate the
forgone domestic benefits associated with the increase in methane emissions projected under the
regulatory options examined in this RIA. Several sources of uncertainty cannot be quantified.
Section 2.3.3 and Appendix B provide detailed discussions of the ways in which the modeling
underlying the development of the SC-CH4 estimates used in this analysis addresses quantifiable
sources of uncertainty, and presents a sensitivity analysis to show how the choice of discount rate
affects the SC-CH4 estimates over long time horizons.
Non-monetized forgone benefits: Several categories of forgone health, welfare, and climate
benefits are not quantified and monetized in this RIA. These unquantified forgone benefits are
associated with increased emissions of methane, VOCs, and HAP. Section 3.3 describes the
unquantified forgone benefits associated with these emissions.
3.6 References
Marchese, A. J., et al. 2015. "Methane Emissions from United States Natural Gas Gathering and
Processing." Environmental Science & Technology 49( 17): 10718-10727.
National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages:
Updating Estimation of the Social Cost of Carbon Dioxide. Washington, DC: The National
Academies Press. Available at: . Accessed December 16,
2019.
Sarofim, M.C., S T. Waldhoff, and S C. Anenberg. 2015. "Valuing the Ozone-Related Health
Benefits of Methane Emission Controls." Environmental and Resource Economics 66( I ):45-
63.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis for the
Final Revisions to the National Ambient Air Quality Standards for Particulate Matter. EPA-
452/R-I2-003. Office of Air Quality Planning and Standards, Health and Environmental
Impacts Division. December. Available at: < https://wvvw3.epa.gov/ttn/ecas/docs/ria/naaqs-
pm_ria_final_2012-12.pdf >. Accessed April 3, 2019.
U.S. Environmental Protection Agency (U.S. EPA). 2014. Regulatory Impact Analysis for the
Proposed Ozone NAAOS. U.S. Environmental Protection Agency, Research Triangle Park,
NC, EPA-452/P-14-006. December. Available at:
. Accessed April 3, 2019.
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U.S. Environmental Protection Agency (U.S. EPA). 2016. Guidelines for Preparing Economic
Analyses. Office of the Administrator. Available at: .
Accessed April 4, 2019.
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4 ANALYSIS OF THE COMBINED REGULATORY IMPACTS OF THE
POLICY REVIEW AND TECHNICAL RECONSIDERATION
4.1 Introduction
To better inform the public on the aggregate regulatory impacts of the two final actions discussed
in this document, this chapter presents the analysis of the combined regulatory impacts of the
two actions. The combined impacts are projected relative to a baseline representing the
regulatory landscape in the absence of either action, /.e., the same baseline used in the Policy
Review analysis.
As a reminder, Chapter 2 in this document presents the regulatory impacts of the final
amendments referred to in this document as the Policy Review, while Chapter 3 presents the
regulatory impacts of the final amendments which we refer to in this document at the Technical
Reconsideration. The Policy Review removes sources in the transmission and storage segment
from the source category, rescinds the NSPS (including both the volatile organic compounds and
methane requirements) applicable to those sources, and rescinds the methane-specific
requirements of the NSPS applicable to sources in the production and processing segments. The
Technical Reconsideration finalizes amendments to the 2016 OOOOa NSPS fugitive emissions
requirements, well site pneumatic pump standards, requirements for certification of closed vent
systems (CVS) by a professional engineer, and the provisions which outline the use of alternative
fugitive emissions standards for several state programs.
To avoid redundant descriptions of the methods, assumptions, and data used to estimate the
impacts presented in this chapter, we refer readers back to Chapters 2 and 3 and focus this
chapter on presenting the results of the analysis for the combined final actions. Readers can also
find tables with more detailed results for the individual actions in Chapters 2 and 3.
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4.2 Compliance Cost Reductions and Forgone emissions reductions
4.2.1	Pollution Controls and Emissions Points Assessed in this RIA
The analysis presented in this chapter reflects the emissions points and controls assessed in the
preceding chapters. This includes fugitive emissions monitoring requirements at well sites and
gathering and boosting stations (Technical Reconsideration), and transmission and storage
compressor stations (Policy Review); replacement of high-bleed pneumatic controllers with low-
bleed controllers in the transmission and storage segment (Policy Review); rod-packing
replacement at reciprocating compressors in the transmission and storage segment (Policy
Review); and certification of closed vent systems or technical infeasibility at storage vessels,
compressors, and pneumatic pumps (Technical Reconsideration). See Sections 2.2.1 and 3.2.1
for more details.
4.2.2	Projection of Affected Facilities
The projected affected facility counts for this analysis are identical to the projected counts used
in the analyses underlying the preceding chapters. See Sections 2.2.2 and 3.2.2 and the
associated tables for details.
4.2.3	Forgone Emissions Reductions
Table 4-1 presents the projected forgone emissions reductions associated with the combined
rulemakings compared to the baseline (i.e., where neither rule has been promulgated). Increases
in emissions are estimated by multiplying the source-level increases in emissions from the
updated baseline by the corresponding projected number of affected facilities. The projected
forgone emissions reductions in Table 4-1 are equivalent to the sum of the forgone emissions
reductions in Table 2-4 and Table 3-6. As noted in previous chapters of this document, some
provisions included in the Policy Review and Technical Reconsideration are not analyzed
because we either do not have the data to do so or because the provision is not expected to result
in cost reductions or emission changes.
4-2
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Table 4-1 Projected Forgone Emissions Reductions from the Combined Policy Review
and Technical Reconsideration, 2021-2030	


Emission Changes

Year
Methane
(short tons)
VOC
(short tons)
HAP
(short tons)
Methane
(metric tons CO2
Eq.)
2021
41,000
5,800
220
930,000
2022
49,000
7,200
270
1,100,000
2023
58,000
8,800
320
1,300,000
2024
68,000
10,000
390
1,500,000
2025
78,000
12,000
450
1,800,000
2026
88,000
14,000
520
2,000,000
2027
99,000
16,000
600
2,200,000
2028
110,000
18,000
670
2,500,000
2029
120,000
20,000
750
2,700,000
2030
130,000
23,000
840
3,000,000
Total
850,000
140,000
5,000
19,000,000
Note: Estimates may not sum due to independent rounding.
4.2.4	Forgone Product Recovery
Some emissions control requirements in the baseline capture methane and VOC emissions that
would otherwise be emitted in absence of such requirements {i.e., the fugitive emissions
monitoring program requirements), and we assume that a large proportion of these averted
methane emissions in the baseline can be directed into natural gas production streams and sold.
When including the decrease in natural gas recovery in the cost reductions analysis, we use the
projections of natural gas prices provided in the EIA's AE02020 reference case. See Section
2.2.5	for details on natural gas price assumptions.
Table 4-2 summarizes the projected decrease in natural gas recovery and the associated forgone
revenues included in the cost reductions calculations for the combined Policy Review and
Technical Reconsideration. The projected decrease in natural gas recovery and the associated
forgone revenue reductions in each row of Table 4-2 is equivalent to the sum of the values in the
corresponding rows from Table 2-5 and Table 3-7.
4-3
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Table 4-2 Projected Decrease in Natural Gas Recovery from the Combined Policy
Review and Technical Reconsideration, 2021-2030	
Year
Decrease in Gas Recovery (Tcf)
Forgone Revenue
(millions 2016$)
2021
2.4
$4.9
2022
2.9
$5.9
2023
3.4
$7.1
2024
3.9
$8.6
2025
4.5
$11
2026
5.1
$13
2027
5.7
$16
2028
6.4
$18
2029
7.0
$20
2030
7.7
$21
4.2.5 Compliance Cost Reductions
Table 4-3 summarizes the projected cost reductions and forgone revenue from product recovery
for the combined Policy Review and Technical Reconsideration. Annualized cost reductions are
estimated by applying a capital recovery factor, based on a 7 percent interest rate and the
assumed equipment lifetime, to capital cost reductions. The projected cost reductions and
forgone revenue in Table 4-3 are equivalent to the sum of projected cost reductions and forgone
revenues in Table 2-6 and Table 3-8.
4-4
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Table 4-3 Estimated Cost Reductions from the Combined Policy Review and Technical
Reconsideration, 2021-2030 (millions 2016$)	
Compliance Cost Reductions
Year
Capital Cost
Reductions1
Operating and
Maintenance
Cost Reductions
Annualized
Cost Reductions
(w/o Forgone
Revenue)2
Forgone
Revenue from
Product
Recovery
Annualized Cost
Reductions (with
Forgone
Revenue)
2021
$8.8
$56
$65
$4.9
$61
2022
$9.1
$67
$78
$5.9
$72
2023
$18
$79
$92
$7.1
$85
2024
$14
$93
$110
$8.6
$98
2025
$15
$110
$120
$11
$110
2026
$17
$120
$140
$13
$120
2027
$18
$140
$150
$16
$140
2028
$18
$150
$170
$18
$150
2029
$18
$170
$190
$20
$170
2030
$19
$180
$210
$21
$190
Note: Estimates may not sum due to independent rounding.
1	The capital cost reductions include the planning cost reductions for newly affected sources for fugitive emissions
monitoring and capital cost reductions for newly affected controllers and compressors, as well as the cost reductions
for sources that would renew survey monitoring plans and purchase new capital at the end of its useful life.
2	These cost reductions include the capital cost reductions annualized over the requisite equipment lifetimes at an
interest rate of 7 percent, plus the annual operating and maintenance cost reductions for every year, plus the cost
reductions from streamlined recordkeeping and reporting.
Table 4-4 illustrates the sensitivity of the estimated cost reductions to the interest rate used to
annualize capital costs. We present cost reductions using interest rates of 7 percent and 3 percent.
The results in Table 4-4 are equivalent to the sum of projected cost reductions and forgone
revenue in Table 2-7 and Table 3-9.
4-5
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Table 4-4 Estimated Cost Reductions from the Combined Policy Review and Technical
Reconsideration, 2021-2030 (millions 2016$)	
7 percent
3 percent
Year
Annualized
Cost
Reductions (w/o
Forgone
Revenue)
Forgone
Revenue from
Product
Recovery
Annualized Cost
Reductions
(with Forgone
Revenue)
Annualized
Cost
Reductions
(w/o Forgone
Revenue)
Forgone
Revenue
from
Product
Recovery
Annualized
Cost Reductions
(with Forgone
Revenue)
2021
$65
$4.9
$61
$64
$4.9
$60
2022
$78
$5.9
$72
$77
$5.9
$71
2023
$92
$7.1
$85
$91
$7.1
$84
2024
$110
$8.6
$98
$110
$8.6
$97
2025
$120
$11
$110
$120
$11
$110
2026
$140
$13
$120
$140
$13
$120
2027
$150
$16
$140
$150
$16
$140
2028
$170
$18
$150
$170
$18
$150
2029
$190
$20
$170
$190
$20
$170
2030
$210
$21
$190
$200
$21
$180
Note: Estimates may not sum due to independent rounding.
4.2.6 Present Value and Equivalent Annualized Value of Cost Reductions
This section presents the cost reductions for the combined Policy Review and Technical
Reconsideration in a present value (PV) framework. Table 4-5 shows the unannualized,
undiscounted stream of cost reductions for each year from 2021 to 2030. Table 4-6 then shows
the stream of discounted cost reductions for each year from 2021 to 2030. The stream of
estimated cost reductions for each year from 2021 through 2030 is discounted to 2020 using 7
and 3 percent discount rates and summed to estimate the PV of the cost reductions from 2021 to
2030. Table 4-6 also shows the equivalent annualized value (EAV) associated with the PV of the
cost reductions. The EAV is a single annual value which, when discounted and summed across
years in the analysis time frame, equals the PV of the original stream of values. In other words,
the sum of the EAV across years in PV terms yields the PV of the (generally) time-varying
stream of values.
4-6
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Table 4-5 Undiscounted Projected Compliance Cost Reductions from the Combined
Policy Review and Technical Reconsideration, 2021-2030 (millions 2016$)	
Year
Capital Cost
Reductions
Annual
Operating Cost
Reductions
Total Cost
Reductions (w/o
Forgone
Forgone
Revenue from
Product
Total Cost
Reductions
(with Forgone
2021
$8.8
$56
$65
$4.9
$60
2022
$9.1
$67
$76
$5.9
$70
2023
$18
$79
$98
$7.1
$90
2024
$14
$93
$110
$8.6
$98
2025
$15
$110
$120
$11
$110
2026
$17
$120
$140
$13
$120
2027
$18
$140
$150
$16
$140
2028
$18
$150
$170
$18
$150
2029
$18
$170
$180
$20
$160
2030
$19
$180
$200
$21
$180
Note: Estimates may not sum due to independent rounding.



Table 4-6 Discounted Cost Reductions from the Combined Policy Review and
Technical Reconsideration, using 7 and 3 Percent Discount Rates (millions 2016S)1
7 Percent
3 Percent
Year
Total Annual
Cost
Reductions
w/o Forgone
Revenue)
Forgone Total Cost
Revenue Reductions
Total Annual
Cost
Reductions
(w/o Forgone
Revenue)
Forgone
Revenue
Total Cost
Reductions
from Product (with Forgone
Recovery Revenue)
from Product
Recovery
(with Forgone
Revenue)
2021
$60
$4.6 $56
$63
$4.8
$58
2022
$67
$5.2 $62
$72
$5.6
$66
2023
$80
$5.8 $74
$89
$6.5
$83
2024
$82
$6.6 $75
$95
$7.6
$87
2025
$87
$7.6 $79
$100
$9.2
$96
2026
$92
$8.8 $83
$120
$11
$100
2027
$95
$9.7 $86
$120
$13
$110
2028
$98
$10 $88
$130
$14
$120
2029
$100
$11 $90
$140
$15
$130
2030
$100
$11 $91
$150
$16
$130
PV
$860
$80 $780
$1,100
$100
$990
EAV
$110
$11 $100
$120
$12
$110
Note: Estimates may not sum due to independent rounding.
1 Cost reductions and forgone revenue in each year are discounted to 2020.
The Policy Review and Technical Reconsideration are considered deregulatory actions under
E.O. 13771, Reducing Regulation and Controlling Regulatory Costs. The PV of the combined
projected cost reductions from the two final rules calculated in accordance with E.O. 13771
4-7
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accounting standards are $1.1 billion over an infinite time horizon (in 2016$, discounted to 2016
at 7 percent). The EAV of the cost reductions over an infinite time horizon are $79 million per
year (in 2016$, discounted to 2016 at 7 percent).
4.3 Forgone Benefits
For the 2012 NSPS OOOO and 2016 NSPS OOOOa, the EPA projected climate and ozone
benefits from methane reductions, ozone and fine particulate matter (PM2.5) health benefits from
VOC reductions, and health benefits from ancillary HAP emissions reduction. Compliance with
these standards was projected to yield benefits due to reductions in methane, VOC, and HAP
emissions.
Under the Policy Review and Technical Reconsideration, the EPA expects that the forgone VOC
emission reductions will worsen air quality and adversely affect health and welfare due to the
contribution of VOCs to ozone, PM2.5, and HAP, but we are unable to quantify these impacts at
this time. This omission does not imply that these forgone benefits do not exist.
We estimate the forgone climate benefits under the combined Policy Review and Technical
Reconsideration using an interim measure of the domestic social cost of methane (SC-CH4). The
SC-CH4 is an estimate of the monetary value of impacts associated with marginal changes in
CH4 emissions in a given year. It includes a wide range of anticipated climate impacts, including
those on agricultural productivity and human health, property damage due to increased flood
risk, and energy system costs, (e.g., reduced costs for heating and increased costs for air
conditioning). It is typically used to assess the avoided damages as a result of regulatory actions
(i.e., the benefits associated with incremental reductions in cumulative CH4 emissions due to
regulation). The SC-CH4 estimates used in this analysis focus on the direct impacts of climate
change that are anticipated to occur within U.S. borders. See Section 2.2.3 and Appendix B for
more detailed discussion of the SC-CH4.
Table 4-7 presents the projected monetized forgone domestic climate benefits associated with the
combined Policy Review and Technical Reconsideration. The results in Table 4-7 are equal to
the sum of the projected monetized forgone domestic climate benefits presented in Table 2-16
and Table 3-23.
4-8
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Table 4-7 Projected Forgone Domestic Climate Benefits Reductions from the
Combined Policy Review and Technical Reconsideration, 2021-2030 (millions, 2016$)
Undiscounted
Discounted back to 2020
Year
7 percent
3 Percent
7 percent
3 Percent
2021
$2.1
$6.7
$2.0
$6.5
2022
$2.7
$8.4
$2.4
$7.9
2023
$3.3
$10
$2.7
$9.3
2024
$4.0
$12
$3.1
$11
2025
$4.8
$14
$3.4
$12
2026
$5.6
$17
$3.8
$14
2027
$6.5
$19
$4.1
$16
2028
$7.5
$22
$4.4
$17
2029
$8.6
$25
$4.7
$19
2030
&
vo
bฉ
$28
$5.0
$21
PV


$35
$130
EAV


$4.7
$15
Note: Estimates may not sum due to independent rounding.
4.4 Economic Impacts and Distributional Assessments
As in the preceding chapters, we discuss but do not quantify energy market, distributional, or
small business impacts associated with the combined Policy Review and Technical
Reconsideration. We expect that the combined final actions will reduce the energy market
impacts associated with the 2016 NSPS OOOOa, may have unevenly distributed impacts across
the U.S. population, and will have neutral or beneficial impacts on small businesses (i.e., no
SISNOSE). See Sections 2.4.1, 2.4.2, and 2.4.3 for more detailed discussion.
We estimated partial employment impacts for entities in the oil and natural gas industry
projected to be affected by the Policy Review and Technical Reconsideration. Table 4-8 presents
estimates of the decrease in upfront and annual labor requirements associated with compliance
activities resulting from the combined final actions. In total, we estimate decreases in
compliance-related labor ranging from 550 full-time equivalents (FTE) in 2021 to 1,400 FTE in
2030, mostly driven by decreases in annual labor requirements. We did not estimate changes in
labor in the oil and natural gas sector beyond the labor related to the compliance activities
directly affected by these actions, nor did we estimate changes in labor in other sectors that may
result from these final actions. See Section 2.4.4 for a broader discussion of the labor impacts,
including a qualitative overview of regulatory impacts on employment.
4-9
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Table 4-8 Estimates of the Decrease in Labor Required for Compliance (in FTEs),
2021-2030
Year
Upfront
Annual
Total
2021
43
520
560
2022
45
610
650
2023
92
700
790
2024
70
790
860
2025
76
880
960
2026
86
970
1,100
2027
87
1,100
1,100
2028
90
1,200
1,200
2029
92
1,200
1,300
2030
94
1,300
1,400
Note: Estimates may not sum due to independent rounding.
4.5 Comparison of Benefits and Costs
4.5.1 Comparison of Benefits and Costs
In this section, we present a comparison of the benefits and costs of the combined Policy Review
and Technical Reconsideration (Table 4-9). Here, we refer to the cost reductions as the
"benefits" of this combined actions and the forgone benefits as the "costs" of the combined
actions. The net benefits are the benefits (cost reductions) minus the costs (forgone benefits). All
costs and benefits in this RIA are estimated relative to a baseline in which neither action has
been implemented. The benefits, costs, and net benefits shown in this section are presented in PV
terms for 2021 to 2030 discounted to 2020 using 7 percent and 3 percent discount rates, along
with the associated EAVs. Table 4-10 provides a summary of the projected forgone emissions
reductions for this action. Both Table 4-9 and Table 4-10 are equivalent to the sum of the values
in their respective tables in Sections 2.5.1 and 3.5.1.
4-10
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Table 4-9 Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone
Monetized Benefits, Cost Reductions, and Net Benefits from the Combined Policy Review
and Technical Reconsideration, 2021-2030 (millions, 2016$)	

7 percent
3 percent

PV
EAV
PV
EAV
Benefits (Total Cost Reductions)
$780
$100
$990
$110
Cost Reductions
$860
$110
$1,100
$120
Forgone Value of Product Recovery
$80
$11
$100
$12
Costs (Forgone Domestic Climate Benefits)1
$35
$4.7
$130
$15
Net Benefits
$750
$99
$850
$97
Note: Estimates may not sum due to independent rounding.
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions.
Table 4-10 Summary of Forgone Emission Reductions from the Combined Policy
Review and Technical Reconsideration, 2021-2030	
Pollutant
Policy Review
Methane (short tons)
850,000
VOC (short tons)
140,000
HAP (short tons)
5,000
Methane (metric tons)
770,000
Methane (million metric tons CO2 Eq.)
19
4.5.2 Uncertainties and Limitations
The results of the combined analysis presented in this Chapter are subject to the uncertainties
discussed in Sections 2.5.2 and 3.5.2. While the reader is referred to those sections for more
detail, we list the main sources of uncertainties here:
•	Source-level compliance costs and emissions impacts
•	Projection methods and assumptions
•	Years of analysis
•	State regulations in the baselines for this analysis
•	Wellhead natural gas prices used to estimate forgone revenues from natural gas recovery
•	Monetized forgone methane-related climate benefits
•	Non-monetized forgone benefits
4-11
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APPENDIX A ADDITIONAL INFORMATION ON ACTIVITY COUNT
PROJECTIONS
A.l Updated Baseline
The baseline used in this analysis represents our estimate of the present and future state of the oil
and natural gas industry as of this final action. This includes an estimate of the number of
sources that are subject to the 2016 NSPS OOOOa using the same methods as were used in the
2016 NSPS analysis. A description of these methods is in the 2016 NSPS Final TSD and 2016
RIA. Where possible, we updated the information used, including sources of information, as
described below. For well sites, we used a base year, in this case 2014, estimate of the number of
oil and natural gas wells, along with a year-by-year rate of change in the number of new oil and
natural gas wells, to project the number of affected oil and natural gas wells through 2030. For
gathering and boosting stations and transmission and storage facilities, we estimated an average
number of new facilities per year.
A.2 Data Sources
Data from oil and natural gas technical documents and inventories, including previous TSDs for
oil and gas actions, were used to estimate the number of new sources for each of the oil and
natural gas segments. Information from the Drillinglnfo database and the GHGI were updated
from the 2016 NSPS OOOOa analysis. Drillinglnfo was used to estimate the number of new well
sites in 2014, and AE02020 was used to project the number of new well sites through 2030. The
GHGI was used to update the equipment counts for well sites and gathering and boosting
stations, while equipment counts for the transmission and storage compressor stations were not
updated for the model plants. We used the GHGI to estimate the number of new gathering and
boosting, transmission, and storage compressor stations, and other equipment in the transmission
and storage segment, such as reciprocating compressors and pneumatic controllers. Finally, we
relied on data submitted in compliance reports for the 2016 NSPS OOOOa to inform our
projections for a few sources, such as storage vessels, pneumatic pumps, and centrifugal
compressors.
A-l
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A.3 Number of Well Sites
The Drillinglnfo database provided the information on the total number of oil and natural gas
wells completed or recompleted in 2014 in the U.S. The base year of 2014 was chosen because
2014 predated the proposal for the 2016 NSPS OOOOa, and therefore activity in that year was
not affected by those requirements. The Drillinglnfo data includes information on GOR,
location, and production. The EPA used this data to calculate the number of affected sources for
each sub-type of model plant based on the GOR and initial production information, which
characterized completion status, use of hydraulic fracturing, and location of the well. The GOR
categories are gas wells (GOR greater than 100,000), oil with associated gas wells (GOR less
than 100,000 and greater than 300), and heavy oil wells (GOR less than 300). Wells are
categorized by GOR based on the total production in the base year (2014).
For newly completed or recompleted well sites, the EPA evaluated the emission reductions and
cost of control for low production well sites, defined as sites in which the combined oil and
natural gas production is less than 15 boe per day averaged over the first 30 days of production,
separately from that of non-low production well sites. We used production information from the
Drillinglnfo data to estimate the proportion of well sites that would be classified as low
production (less than 15 boe per day production) or non-low production (greater than 15 boe per
day production) by calculating the proportion of wells in the dataset producing less than 7.5 boe
per day, which is equivalent to the model plant, which is assumed to have two wells per site,
producing fewer than 15 boe per day combined. These production levels were based on the initial
production reported in Drillinglnfo. The Drillinglnfo field 'PRAC IP BOE' was used, which
includes both liquid and gas production and is based on the second month production recorded
for the well. The second month was used to represent practical initial production because the first
month record may be a partial month depending on when production started. After estimating the
number of new wells based on each subcategory and subtype that are subject to the 2016 NSPS
OOOOa, we applied the same assumption of two wells per well site as used in the model plant
analysis to obtain the number of each well site subject to the 2016 NSPS OOOOa. A discussion
of how EPA estimated the transitions to and from low production status in later periods in
presented in Section 3.2.3 above.
A-2
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Additionally, the EPA published final amendments to the 2016 OOOOa rule on March 12, 2018
that created separate fugitives monitoring and repair requirements for well sites on the Alaska
North Slope.103 In summary, these amendments granted additional time for initial monitoring
during cold weather months and required annual monitoring for these well sites. We used the
location information from Drillinglnfo to identify these well sites, and those in the states subject
to fugitive emissions standards under state regulations.
Table A-l shows the count of well sites in the base year (2014) for each model plant. In this
table, wells are broken out into states of interest, including Alaska, California, Colorado and
Texas.
Table A-1 Well Completions in 2014 by Production Level and Well Type	
Non-low production wells	Low production wells
Location
Natural
Oil (GOR
Oil (GOR
Natural
Oil (GOR
Oil (GOR
Gas
>300)
<300)
Gas
>300)
<300)
Alaska/North-Slope
2
59
2
0
4
0
Alaska/Other
14
6
1
6
1
0
California
9
298
575
2
133
581
Colorado
284
1,035
44
33
20
16
Louisiana
231
281
111
23
50
407
North Dakota
0
2,081
138
0
48
17
New Mexico
43
950
55
12
116
27
Ohio
169
290
10
71
97
134
Oklahoma
341
1,383
421
63
71
231
Pennsylvania
605
103
6
64
408
337
Texas
973
10,302
1,397
141
1,176
1,459
Utah
122
558
42
12
131
9
Wyoming
255
549
113
55
20
65
Other states
954
484
780
335
169
1,058
Source: Drillinglnfo database extracted January 2018.104
We used the AE02020 projection of wells drilled in the contiguous 48 states to estimate a year-
by-year rate of change from 2014 through 2030. We applied that year by year rate of change to
the estimated number of wells in 2014 from Drillinglnfo, regardless of well type, to project the
estimated number of new well sites through 2030, scaled to the AEO oil and natural gas drilling
103	83 FR 10628.
104	Memorandum to Jameel Alsalam, EPA, Elizabeth Miller, EPA, and Melissa Weitz, EPA from Casey Pickering,
ERG and Robyn Reid, ERG titled, DI Desktop Data Processing Overview for OAP/OAQPS located at Docket ID
No. EPA-HQ-OAR-2017-0473. February 6, 2018.
A-3
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activity projections. The estimated number of new or modified facilities using this well drilling-
based approach varies across projection years depending on projected oil and natural gas drilling
activity from the AEO.
In the process of estimating fugitive emissions controls at well sites in the baseline and
regulatory options, the EPA accounted for wells that were assumed to be covered by state
regulations. In cases where state regulations would achieve equal or greater controls as the 2016
NSPS OOOOa controls, the regulatory options in this reconsideration do not result in a change in
applied controls. Based on EPA's analysis, programs in six states have enacted regulations we
believe meet or exceed the 2016 NSPS OOOOa standard for fugitive emissions monitoring:
California, Colorado, Ohio, Pennsylvania, Texas and Utah.105 These states are broken out in
Table A-l above. In this analysis, we take the requirements from California, Colorado, Ohio,
Pennsylvania, Texas, and Utah into account.106
A.4 Gathering and Boosting Stations and Transmission and Storage Compressor
Stations
In addition to well sites, the fugitive emissions requirements apply to gathering and boosting
stations, transmission compressor stations, and storage compressor stations. The GHGI is used to
estimate the count of newly affected compressor stations in each year. The GHGI uses a variety
of data sources and studies to estimate equipment counts and emissions. Many equipment counts
are based on the data reported under the GHGRP, scaled up to reflect the total population
including both GHGRP-reporting and non-reporting oil and natural gas facilities.
We estimated the number of new compressor stations, by type, by averaging the increases in the
year-to-year changes in total national counts of equipment over the 10-year period from 2004
105	For information on additional states that were examined and why they are not considered equivalent, see the TSD
and the memo "Equivalency of State Fugitive Emissions Programs for Well Sites and Compressor Stations to
Standards at 40 CFR Part 60, Subpart OOOOa", both of which are available in the docket.
106	EPA proposed that certain fugitive emissions monitoring-related permits in Texas would be considered
equivalent, but not all types of permits. At proposal, EPA did not have quantitative information on the share of
Texas permits that, as proposed, would be considered equivalent. Information received during the public
comment period for this action provides EPA with a basis to perform quantitative analysis for Texas facilities in
this RIA. EPA also received additional information of the share of facilities in Utah that whose fugitive
emissions monitoring-related emissions requirements would be considered equivalent to NSPS OOOOa
requirements.
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through 2014. Year-to-year increases were assumed to represent newly constructed facilities.
Decreases in total counts were represented as zeros for that year, and average together with the
annual increases. This approach results in the same number of new compressor stations in each
projected year, regardless of increases or decreases in AEO projected drilling or production.
These values reflect that construction of compressor stations and transmission pipelines are
longer-term investments not necessarily correlated with short-term fluctuations in production. In
addition, this approach may result in fewer total new and modified compressor stations for two
reasons: (1) modifications of existing compressor stations are not captured, and (2) if existing
compressor stations are closed and replaced with new facilities, those would not be reflected in
the net increase in the year-to-year total. The national equipment counts estimated in the GHG
Inventory are not disaggregated by state, therefore, activity data using this approach is only
estimated at the national level. The average year-to-year increase for compressor stations is
summarized in Table A-2.
Table A- 2 Average Year-to-Year Increases in Compressor Station Counts	
Location
Average Year-to-Year Increase
Gathering and Boosting Stations
212
Transmission Compressor Stations
36
Storage Compressor Stations
2
A.5 Nationwide Activity Data for Other Equipment
Nationwide impacts of certifications for closed vent system design and technical infeasibility of
routing pneumatic pumps to an existing control device, rod-packing replacements at
reciprocating compressors, route-to-control measures for wet-seal centrifugal compressors, and
use of low-bleed pneumatic controllers were calculated by estimating the count of affected
facilities installed in a typical year and then using that typical year estimate to estimate the
number of new affected facilities for each of the years in the study period, 2021 through 2030.
Closed vent system and technical infeasibility certifications impact pneumatic pumps, centrifugal
compressors, reciprocating compressors, and storage vessels. The other measures only generate
impacts for sources in the transmission and storage segment in this final action.
The basis for the counts of affected facilities that would require closed vent system and technical
infeasibility certifications in a typical year was information from 2016 NSPS OOOOa
compliance information for 2017. The total number of new pneumatic pumps, centrifugal
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compressors, reciprocating compressors, and storage vessel affected facilities reported for 2017
are shown in Table A-3. These represent the number of new affected facilities in a "typical year."
The GHGI was used to generate counts of reciprocating compressors and pneumatic controllers
in transmission and storage only; those values are also included in the table.
Table A- 3 Nationwide Number of New Affected Facilities Reported in Compliance
Reports for Year 2017
Type of Affected Facility
Total Count
Pneumatic Pumps
663
Reciprocating Compressors
180
Production and Processing
104
Transmission and Storage
76
Centrifugal Compressors
0
Storage Vessels
697
Pneumatic Controllers (Transmission and Storage Only)
308
A. 5.1 Pneumatic Pumps
As shown in Table A-3, there were 663 pneumatic pump affected facilities reported in 2017. Per
the definition of pneumatic pump affected facility in ง60.5365a(h), the only pneumatic pumps
subject to the 2016 NSPS OOOOa are natural gas-driven diaphragm pumps. It is therefore
assumed that all the pneumatic pumps reported in 2017 were diaphragm pumps. The compliance
information did not specify the number of pneumatic pumps at sites with a control device.
Therefore, the percent of pneumatic pumps assumed to be controlled retains the assumption from
the Final NSPS 2016 TSD and the 2018 NSPS Proposal TSD that 75 percent of the new pumps
are at sites with a control device or a process to which the pump discharge could be routed. For
these pumps, the owner or operator would either need a certification of the closed vent system or
a certification that it is infeasible to route the pump discharge emissions to a control
device/process. Therefore, an estimated 497 pneumatic pumps will need certifications in a
typical year. No information was available to determine differences in the number of new
pneumatic pumps year-by-year, so the estimate of 497 was assumed for each of the study years
of 2021 through 2030.
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A. 5.2 Compressors
No centrifugal compressor affected facilities appeared in the 2017 compliance reports.
Therefore, we assume that there will be no new wet-sealed centrifugal compressors for any of the
study years.
As shown in Table A-3, there were 180 new reciprocating compressor affected facilities reported
in 2017. Of those, 32 were located at gas processing plants (in the production and processing
segment) and 148 were located at compressor stations. Because the reports did not distinguish
between reciprocating compressors at gathering and boosting versus transmission and storage
stations, we assumed that 76 were located at the latter (72 in transmission and 4 in storage) based
on the average change in reciprocating compressors in the transmission and storage segment in
the GHGI from 2004 to 2014 (censoring yearly changes below by zero). The remaining 72
compressors were assigned to gathering and boosting stations, and so 104 compressors in total
were assumed to be in the production and processing segment.
Not all new reciprocating compressors require engineering certification. If an owner or operator
complies via the rod packing replacement compliance option provided in the rule, there is no
requirement to obtain a certification of a closed vent system. However, if an owner or operator of
a reciprocating compressor complies with the rule by routing the rod packing emissions through
a closed vent system to a process, they would be required to obtain a certification of the closed
vent system. The compliance information did not contain information regarding the number of
reciprocating compressors complying with each of these options, but it is anticipated that the
majority of the owners and operators of reciprocating compressors will comply via the rod
packing changeout option. In the absence of specific information, the assumption that 10 percent
of the reciprocating compressor affected facilities in the production and processing segment (an
estimated 10 reciprocating compressor affected facilities) would comply by routing the
emissions through a closed vent system to a process and thus require a certification. No
information was available to determine differences in the number of new reciprocating
compressor affected facilities year-by-year, so the estimated 10 reciprocating compressor
affected facilities was assumed for each of the analysis years of 2021 through 2030.
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A. 5.3 Storage Vessels
There were 697 new storage vessel affected facilities reported in the 2017 compliance reports.
Each of these storage vessels are required to route emissions through a closed vent system to a
control device and are therefore required to obtain a closed vent system certification. This
number is considerably lower than the estimate assumed in the 2018 NSPS Proposal TSD. The
reason EPA believes that the estimate assumed in the 2018 NSPS Proposal TSD and the number
of reporting new storage vessel affected facilities differ is attributed to the fact that the majority
of new storage vessels are subject to legally and practicable enforceable limits in operating
permits or regulations that result in VOC emissions below the 6 tons per year applicability
threshold and are therefore not be subject to the 2016 NSPS OOOOa rule. In order to estimate
the year-by-year number of storage vessel affected facilities, the 2017 number of 697 new
storage vessel affected facilities was adjusted proportionally based on the number of projected
wells drilled in a given year, according to AE02020 projections.
A. 5.4 Pneumatic Controllers
The annual count of new high-bleed pneumatic controllers in transmission and storage is 308.
This estimate was generated by calculating the average annual change in high-bleed controllers
in transmission and storage from 2011 to 2014 in the GHGI. In years in which the number of
controllers decreased, we assume that the number of new controllers was zero.
A. 5.5 Summary of Affected Facilities Requiring Certification
Table A-4 summarizes the projected number of the facilities in the years 2021 through 2030 that
are affected by this reconsideration that require certification under the 2016 NSPS OOOOa rule.
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Table A- 4
Estimated Number of Affected Facilities Requiring Certifications, 2021-2030
Type of
Affected
Facility
Pneumatic
Pumps
Centrifugal
Compressors
Reciprocating
Compressors
Storage Vessels
Total
2021
497
0
10
1,074
1,589
2022
497
0
10
1,127
1,642
2023
497
0
10
1,162
1,677
2024
497
0
10
1,182
1,697
2025
497
0
10
1,194
1,709
2026
497
0
10
1,205
1,720
2027
497
0
10
1,209
1,724
2028
497
0
10
1,216
1,731
2029
497
0
10
1,226
1,741
2030
497
0
10
1,219
1,734
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APPENDIX B	UNCERTAINTY ASSOCIATED WITH ESTIMATING THE
SOCIAL COST OF METHANE
B.l Overview of Methodology Used to Develop Interim Domestic SC-CH4 Estimates
The domestic SC-CH4 estimates rely on the same ensemble of three integrated assessment
models (IAMs) that were used to develop the IWG global SC-CH4 (and SC-CO2) estimates:
DICE 2010, FUND 3.8, and PAGE 2009.107 The three IAMs translate emissions into changes in
atmospheric greenhouse concentrations, atmospheric concentrations into changes in temperature,
and changes in temperature into economic damages. The emissions projections used in the
models are based on specified socio-economic (GDP and population) pathways. These emissions
are translated into atmospheric concentrations, and concentrations are translated into warming
based on each model's simplified representation of the climate and a key parameter, equilibrium
climate sensitivity. The effect of these Earth system changes is then translated into consumption-
equivalent economic damages. As in the IWG exercise, these key inputs were harmonized across
the three models: a probability distribution for equilibrium climate sensitivity; five scenarios for
economic, population, and emissions growth; and discount rates.108 All other model features were
left unchanged. Future damages are discounted using constant discount rates of both 3 and 7
percent, as recommended by OMB Circular A-4.
The domestic share of the global SC-CH4— i.e., an approximation of the climate change impacts
that occur within U.S. borders109 — is calculated directly in both FUND and PAGE. However,
DICE 2010 generates only global estimates. Therefore, the EPA approximates U.S. damages as
10 percent of the global values from the DICE model runs, based on the results from a
regionalized version of the model (RICE 2010) reported in Table 2 of Nordhaus (2017).110
Although the regional shares reported in Nordhaus (2017) are specific to SC-CO2, they still
107	The models' full names are as follows: Dynamic Integrated Climate and Economy (DICE); Climate Framework
for Uncertainty, Negotiation, and Distribution (FUND); and Policy Analysis of the Greenhouse Gas Effect
(PAGE).
108	See the IWG's summary of its methodology in the docket, document ID number EPA-HQ-OAR-2015-0827-
5886, "Addendum to Technical Support Document on Social Cost of Carbon for Regulatory Impact Analysis
under Executive Order 12866: Application of the Methodology to Estimate the Social Cost of Methane and the
Social Cost of Nitrous Oxide (August 2016)". See also National Academies (2017) for a detailed discussion of
each of these modeling assumptions.
109	Note that inside the U.S. borders is not the same as accruing to U.S. citizens, which may be higher or lower.
110	Nordhaus, William D. 2017. Revisiting the social cost of carbon. Proceedings of the National Academy of
Sciences of the United States, 114(7): 1518-1523.
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provide a reasonable interim approach for approximating the U.S. share of marginal damages
from methane emissions. Direct transfer of the domestic share from the SC-CO2 may understate
the U.S. share of the IWG global SC-CH4 estimates based on DICE due to the combination of
three factors: a) regional damage estimates are known to be highly correlated with output shares
(Nordhaus 2017, 2014), b) the U.S. share of global output decreases over time in all five EMF-22
based socioeconomic scenarios used for the model runs, and c) the bulk of the temperature
anomaly (and hence, resulting damages) from a perturbation in emissions in a given year will be
experienced earlier for CH4 than CO2 due to the shorter lifetime of CH4 relative to CO2.
The steps involved in estimating the social cost of CH4 are like those used for CO2. The three
integrated assessment models (FUND, DICE, and PAGE) are run using the harmonized
equilibrium climate sensitivity distribution, five socioeconomic and emissions scenarios,
constant discount rates described above. Because the climate sensitivity parameter is modeled
probabilistically, and because PAGE and FUND incorporate uncertainty in other model
parameters, the final output from each model run is a distribution over the SC-CH4 in year l
based on a Monte Carlo simulation of 10,000 runs. For each of the IAMs, the basic
computational steps for calculating the social cost estimate in a particular year t are: 1.) calculate
the temperature effects and (consumption-equivalent) damages in each year resulting from the
baseline path of emissions; 2.) adjust the model to reflect an additional unit of emissions in year
t.; 3.) recalculate the temperature effects and damages expected in all years beyond t resulting
from this adjusted path of emissions, as in step 1; and 4.) subtract the damages computed in step
1 from those in step 3 in each model period and discount the resulting path of marginal damages
back to the year of emissions. In PAGE and FUND, step 4 focuses on the damages attributed to
the US region in the models. As noted above, DICE does not explicitly include a separate US
region in the model and therefore, the EPA approximates U.S. damages in step 4 as 10 percent of
the global values based on the results of Nordhaus (2017). This exercise produces 30 separate
distributions of the SC-CH4 for a given year, the product of 3 models, 2 discount rates, and 5
socioeconomic scenarios. Following the approach used by the IWG, the estimates are equally
weighted across models and socioeconomic scenarios in order to consolidate the results into one
distribution for each discount rate.
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B.2 Treatment of Uncertainty in Interim Domestic SC-CH4 Estimates
There are various sources of uncertainty in the SC-CH4 estimates used in this analysis. Some
uncertainties pertain to aspects of the natural world, such as quantifying the physical effects of
greenhouse gas emissions on Earth systems. Other sources of uncertainty are associated with
current and future human behavior and well-being, such as population and economic growth,
GHG emissions, the translation of Earth system changes to economic damages, and the role of
adaptation. It is important to note that even in the presence of uncertainty, scientific and
economic analysis can provide valuable information to the public and decision makers, though
the uncertainty should be acknowledged and when possible taken into account in the analysis
(National Academies 2013).111 OMB Circular A-4 also requires a thorough discussion of key
sources of uncertainty in the calculation of benefits and costs, including more rigorous
quantitative approaches for higher consequence rules. This section summarizes the sources of
uncertainty considered in a quantitative manner in the domestic SC-CH4 estimates.
The domestic SC-CH4 estimates consider various sources of uncertainty through a combination
of a multi-model ensemble, probabilistic analysis, and scenario analysis. We provide a summary
of this analysis here; more detailed discussion of each model and the harmonized input
assumptions can be found in the 2017 National Academies report. For example, the three IAMs
used collectively span a wide range of Earth system and economic outcomes to help reflect the
uncertainty in the literature and in the underlying dynamics being modeled. The use of an
ensemble of three different models at least partially addresses the fact that no single model
includes all the quantified economic damages. It also helps to reflect structural uncertainty across
the models, which stems from uncertainty about the underlying relationships among GHG
emissions, Earth systems, and economic damages that are included in the models. Bearing in
mind the different limitations of each model and lacking an objective basis upon which to
differentially weight the models, the three integrated assessment models are given equal weight
in the analysis.
111 Institute of Medicine of the National Academies. 2013. Environmental Decisions in the Face of Uncertainty. The
National Academies Press.
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Monte Carlo techniques were used to run the IAMs many times. In each simulation the uncertain
parameters are represented by random draws from their defined probability distributions. In all
three models the equilibrium climate sensitivity is treated probabilistically based on the
probability distribution from Roe and Baker (2007) calibrated to the IPCC AR4 consensus
statement about this key parameter.112 The equilibrium climate sensitivity is a key parameter in
this analysis because it helps define the strength of the climate response to increasing GHG
concentrations in the atmosphere. In addition, the FUND and PAGE models define many of their
parameters with probability distributions instead of point estimates. For these two models, the
model developers' default probability distributions are maintained for all parameters other than
those superseded by the harmonized inputs {i.e., equilibrium climate sensitivity, socioeconomic
and emissions scenarios, and discount rates). More information on the uncertain parameters in
PAGE and FUND is available upon request.
For the socioeconomic and emissions scenarios, uncertainty is included in the analysis by
considering a range of scenarios selected from the Stanford Energy Modeling Forum exercise,
EMF-22. Given the dearth of information on the likelihood of a full range of future
socioeconomic pathways at the time the original modeling was conducted, and without a basis
for assigning differential weights to scenarios, the range of uncertainty was reflected by simply
weighting each of the five scenarios equally for the consolidated estimates. To better understand
how the results vary across scenarios, results of each model run are available in the docket.
The outcome of accounting for various sources of uncertainty using the approaches described
above is a frequency distribution of the SC-CH4 estimates for emissions occurring in each year
for each discount rate. Unlike the approach taken for consolidating results across models and
socioeconomic and emissions scenarios, the SC-CH4 estimates are not pooled across different
discount rates because the range of discount rates reflects both uncertainty and, at least in part,
different policy or value judgements; uncertainty regarding this key assumption is discussed in
more detail below. The frequency distributions reflect the uncertainty around the input
parameters for which probability distributions were defined, as well as from the multi-model
ensemble and socioeconomic and emissions scenarios where probabilities were implied by the
112 Specifically, the Roe and Baker distribution for the climate sensitivity parameter was bounded between 0 and 10
with a median of 3 ฐC and a cumulative probability between 2 and 4.5 ฐC of two-thirds.
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equal weighting assumption. It is important to note that the set of SC-CH4 estimates obtained
from this analysis does not yield a probability distribution that fully characterizes uncertainty
about the SC-CH4 due to impact categories omitted from the models and sources of uncertainty
that have not been fully characterized due to data limitations.
Figure B-l presents the frequency distribution of the domestic SC-CH4 estimates for emissions
in 2020 for each discount rate. Each distribution represents 150,000 estimates based on 10,000
simulations for each combination of the three models and five socioeconomic and emissions
scenarios.113 In general, the distributions are skewed to the right and have long right tails, which
tend to be longer for lower discount rates. To highlight the difference between the impact of the
discount rate on the SC-CH4 and other quantified sources of uncertainty, the bars below the
frequency distributions provide a symmetric representation of quantified variability in the SC-
CH4 estimates conditioned on each discount rate. The full set of SC-CH4 results through 2050 is
available as part of the RIA analysis materials.
113 Although the distributions in Figure 1 are based on the full set of model results (150,000 estimates for each
discount rate), for display purposes the horizontal axis is truncated with 0.001 to 0.013 percent of the estimates
lying below the lowest bin displayed and 0.471 to 3.356 percent of the estimates lying above the highest bin
displayed, depending on the discount rate.
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w
c
o
to
13
CO
c
_o
o
co
o
o
CO
to
CSJ
o
CM
O
lO
O
lO
O
o
o
o
7% Average = $55
3% Average = $180
Jlf
fell
IT
1
Discount Rate
7%
n 3%
5tn - 95tn Percentile
of Simulations
0	100	200	300	400	500	600	700	800
Interim U.S. Domestic Social Cost of Methane in 2020 [2016S / metric ton CH4]
Figure B-l Frequency Distribution of Interim Domestic SC-CH4 Estimates for 2020 (in
2016$ per metric ton CH4)
As illustrated by the frequency distributions in Figure B-l, the assumed discount rate plays a
critical role in the ultimate estimate of the social cost of methane. This is because CH4 emissions
today continue to impact society far out into the future,114 so with a higher discount rate, costs
that accrue to future generations are weighted less, resulting in a lower estimate. Circular A-4
recommends that costs and benefits be discounted using the rates of 3 percent and 7 percent to
reflect the opportunity cost of consumption and capital, respectively. Circular A-4 also
recommends quantitative sensitivity analysis of key assumptions,115 and offers guidance on what
sensitivity analysis can be conducted in cases where a rule will have important intergenerational
benefits or costs. To account for ethical considerations of future generations and potential
114	Although the atmospheric lifetime of CH4 is notably shorter than that of CO2, the impacts of changes in
contemporary CH4 emissions are also expected to occur over long time horizons that cover multiple generations.
For more discussion, see document ID number EPA-HQ-OAR-2015-0827-5886, "Addendum to Technical
Support Document on Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866:
Application of the Methodology to Estimate the Social Cost of Methane and the Social Cost of Nitrous Oxide
(August 2016)".
115	"If benefit or cost estimates depend heavily on certain assumptions, you should make those assumptions explicit
and carry out sensitivity analyses using plausible alternative assumptions." (OMB 2003, page 42).
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uncertainty in the discount rate over long time horizons, Circular A-4 suggests "further
sensitivity analysis using a lower but positive discount rate in addition to calculating net benefit
using discount rates of 3 and 7 percent" (page 36) and notes that research from the 1990s
suggests intergenerational rates "from 1 to 3 percent per annum" (OMB 2003). We consider the
uncertainty in this key assumption by calculating the domestic SC-CH4 based on a 2.5 percent
discount rate, in addition to the 3 and 7 percent used in the main analysis.
Using a 2.5 percent discount rate, the average domestic SC-CH4 estimate across all the model
runs for emissions occurring in 2021 is $230 per metric ton of CH4 (2016$).116 For the Policy
Review, the projected undiscounted forgone domestic climate benefits are $4.6 million in
2021.117 By 2030, the average domestic SC-CH4 using a 2.5 percent discount rate is $290 per
metric ton of CH4 (2016$), and the corresponding projected undiscounted forgone domestic
climate benefits of the action increase to $15 million. The PV of the forgone domestic climate
benefits under a 2.5 percent discount rate for the SC-CH4 estimate and the stream of forgone
benefits is $81 million, with a corresponding EAV of $9 million per year.
For the Technical Reconsideration, the projected undiscounted forgone domestic climate benefits
are $3.9 million in 2021.118 By 2030, the corresponding undiscounted forgone domestic climate
benefits of the action increase to $20 million. The PV of the forgone domestic climate benefits
under a 2.5 percent discount rate for the SC-CH4 estimate and the stream of forgone benefits is
$91 million, with a corresponding EAV of $10 million per year.
In addition to the approach to accounting for the quantifiable uncertainty described above, the
scientific and economics literature has further explored known sources of uncertainty related to
estimates of the social cost of carbon and other greenhouse gases. For example, researchers have
examined the sensitivity of IAMs and the resulting estimates to different assumptions embedded
116	The estimates are adjusted for inflation using the GDP implicit price deflator and then rounded to two significant
digits.
117	We make a distinction between the discounting used to generate the SC-CH4 estimate, and the discounting
applied to the stream of forgone climate benefits. Here, the former is based on a 2.5 percent discount rate, while
the latter is undiscounted, i.e., for each year, it is the product of the year-specific SC-CH4 estimate and the
estimated forgone methane reductions.
118	We make a distinction between the discounting used to generate the SC-CH4 estimate, and the discounting
applied to the stream of forgone climate benefits. Here, the former is based on a 2.5 percent discount rate, while
the latter is undiscounted, i.e., for each year, it is the product of the year-specific SC-CH4 estimate and the
estimated forgone methane reductions.
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in the models (see, e.g., Hope 2013, Anthoff and Tol 2013, Nordhaus 2014, and Waldhoff et al.
2011, 2014). However, there remain additional sources of uncertainty that have not been fully
characterized and explored due to remaining data limitations. Additional research is needed to
expand the quantification of various sources of uncertainty in estimates of the social cost of
carbon and other greenhouse gases (e.g., developing explicit probability distributions for more
inputs pertaining to climate impacts and their valuation). On the issue of intergenerational
discounting, some experts have argued that a declining discount rate would be appropriate to
analyze impacts that occur far into the future (Arrow et al., 2013). However, additional research
and analysis is still needed to develop a methodology for implementing a declining discount rate
and to understand the implications of applying these theoretical lessons in practice. The 2017
National Academies report also provides recommendations pertaining to discounting,
emphasizing the need to more explicitly model the uncertainty surrounding discount rates over
long time horizons, its connection to uncertainty in economic growth, and, in turn, to climate
damages using a Ramsey-like formula (National Academies 2017). These and other research
needs are discussed in detail in the 2017 National Academies' recommendations for a
comprehensive update to the current methodology, including a more robust incorporation of
uncertainty.
B.3 Forgone Global Climate Benefits
In addition to requiring reporting of impacts at a domestic level, OMB Circular A-4 states that
when an agency "evaluate[s] a regulation that is likely to have effects beyond the borders of the
United States, these effects should be reported separately" (page 15).119 This guidance is relevant
to the valuation of damages from GHGs, given that most GHGs (including CH4) contribute to
damages around the world independent of the country in which they are emitted. Therefore, in
this section we present the forgone global climate benefits from this rulemaking using the global
119 While Circular A-4 does not elaborate on this guidance, the basic argument for adopting a domestic only
perspective for the central benefit-cost analysis of domestic policies is based on the fact that the authority to
regulate only extends to a nation's own residents who have consented to adhere to the same set of rules and
values for collective decision-making, as well as the assumption that most domestic policies will have negligible
effects on the welfare of other countries' residents (EPA 2010; Kopp et al. 1997; Whittington et al. 1986). In the
context of policies that are expected to result in substantial effects outside of U.S. borders, an active literature has
emerged discussing how to appropriately treat these impacts for purposes of domestic policymaking (e.g., Gayer
and Viscusi 2016, 2017; Anthoff and Tol, 2010; Fraas et al. 2016; Revesz et al. 2017). This discourse has been
primarily focused on the regulation of greenhouse gases (GHGs), for which domestic policies may result in
impacts outside of U.S. borders due to the global nature of the pollutants.
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SC-CH4 estimates — i.e., reflecting quantified impacts occurring in both the U.S. and other
countries — corresponding to the model runs that generated the domestic SC-CH4 estimates used
in the main analysis. The average global SC-CH4 estimate across all the model runs for
emissions occurring over the years analyzed in this RIA (2021-2030) range from $380 to $530
per metric ton of CH4 emissions (in 2016 dollars) using a 7 percent discount rate, and $1,400 to
$1,800 per metric ton of CH4 using a 3 percent discount rate.120 The domestic SC-CH4 estimates
presented above are approximately 15 percent and 13 percent of these global SC-CH4 estimates
for the 7 percent and 3 percent discount rates, respectively.
Forgone Global Climate Benefits for Policy Review: Applying these estimates to the forgone
CH4 emission reductions under the Policy Review results in estimated undiscounted forgone
global climate benefits ranging from $7.6 million in 2021 to $28 million in 2030, using a 7
percent discount rate for the SC-CH4 estimate. The PV of the forgone global climate benefits
using a 7 percent discount rate for the SC-CH4 estimate and the stream of forgone benefits is
$110 million, with an associated EAV of $15 million per year.
The estimated undiscounted forgone global climate benefits under the Policy Review are $29
million in 2021 and increase to $96 million in 2030 using a 3 percent rate for the SC-CH4
estimate. The PV of the forgone global climate benefits using a 3 percent discount rate for the
SC-CH4 estimate and the stream of forgone benefits is $500 million, with an associated EAV of
$56 million per year.
Under the sensitivity analysis considered above using a 2.5 percent discount rate, the average
global SC-CH4 estimate across all the model runs for emissions occurring in 2021-2030 ranges
from $1,900 to $2,300 per metric ton of CH4 (2016$). The undiscounted forgone global climate
benefits under the Policy Review are estimated to be $38 million in 2021 and $120 million in
2030 using a 2.5 percent discount rate for the SC-CH4 estimate. The PV of the forgone global
climate benefits using a 2.5 percent discount rate for the SC-CH4 estimate and the stream of
forgone benefits is $660 million, with an associated EAV of $74 million per year. All estimates
are reported in 2016 dollars.
120 The estimates are adjusted for inflation using the GDP implicit price deflator and then rounded to two significant
digits.
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Forgone Global Climate Benefits for Technical Reconsideration: Applying these estimates to the
forgone CH4 emission reductions under the Technical Reconsideration results in estimated
undiscounted forgone global climate benefits ranging from $6.5 million in 2021 to $36 million in
2030, using a 7 percent discount rate for the SC-CH4 estimate. The PV of the forgone global
climate benefits using a 7 percent discount rate for the SC-CH4 estimate and the stream of
forgone benefits is $123 million, with an associated EAV of $16 million per year.
The estimated undiscounted forgone global climate benefits under the Technical Reconsideration
are $24 million in 2021 and increase to $124 million in 2030 using a 3 percent rate for the SC-
CH4 estimate. The PV of the forgone global climate benefits using a 3 percent discount rate for
the SC-CH4 estimate and the stream of forgone benefits is $560 million, with an associated EAV
of $64 million per year.
Under the sensitivity analysis considered above using a 2.5 percent discount rate, the
undiscounted forgone global climate benefits under the Technical Reconsideration are estimated
to be $32 million in 2021 and $160 million in 2030. The PV of the forgone global climate
benefits using a 2.5 percent discount rate for the SC-CH4 estimate and the stream of forgone
benefits is $750 million, with an associated EAV of $83 million per year. All estimates are
reported in 2016 dollars.
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Environmental Protection	Health and Environmental Impacts Division	July 2020
Agency	Research Triangle Park, NC
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