Regulatory Impact Analysis for the Proposed
Reconsideration of the Oil and Natural Gas
Sector Emission Standards for New,
Reconstructed, and Modified Sources
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EPA-452/R-18-001
September 2018
Regulatory Impact Analysis for the Proposed 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
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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 Dr.
Beth Miller, U.S. Environmental Protection Agency, Office of Air and Radiation, Research
Triangle Park, North Carolina 27711 (email: miller.elizabeth@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.
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TABLE OF CONTENTS
Table of Contents v
List of Tables vn
List of Figures ix
1 Executive Summary 1-1
1.1 Background 1-1
1.2 Summary of Updates from the Final 2016 NSPS RIA 1-3
1.3 Regulatory Options Analyzed in this RIA 1-6
1.4 Summary of Results 1-9
1.5 Organization of this Report 1-13
2 COMPLIANCE COST SAVINGS AND FORGONE EMISSION REDUCTIONS 2-1
2.1 Introduction 2-1
2.2 Emissions Points and Pollution Controls assessed in the RIA 2-1
2.3 Compliance Cost Analysis 2-4
2.3.1 Regulatory Options 2-5
2.3.2 Unit Level Cost Savings and Emission Increases 2-6
2.3.3 Projection of Affected Facilities 2-7
2.3.4 Emissions Increases 2-11
2.3.5 Forgone Product Recovery 2-12
2.3.6 Compliance Cost Savings 2-14
2.3.7 Comparison of Regulatory Alternatives 2-17
2.4 Detailed Impacts Tables 2-19
2.5 Analysis of the Present Value of Cost Savings 2-23
2.5.1 Present Value and Equivalent Annualized Value of the Cost Savings 2-23
2.5.2 Sensitivity of Cost Savings to Fugitive Emissions Monitoring Frequency at Compressor Stations 2-27
3 Estimated Forgone Benefits 3-1
3.1 Introduction 3-1
3.2 Forgone Emissions Reductions 3-4
3.3 Methane Climate Effects and Valuation 3-6
3.4 VOC as an Ozone Precursor 3-14
3.4.1 Ozone Health Effects 3-15
3.4.2 Ozone Vegetation Effects 3-15
3.4.3 Ozone Climate Effects 3-16
3.5 VOC as aPM25 Precursor 3-16
3.5.1 PM2 5 Health Effects 3-17
3.5.2 Organic PM Welfare Effects 3-18
3.5.3 Visibility Effects 3-19
3.6 Hazardous Air Pollutants (HAP) 3-20
3.6.1 Benzene 3-25
3.6.2 Toluene 3-26
3.6.3 Carbonyl Sulfide 3-27
3.6.4 Ethylbenzene 3-27
3.6.5 Mixed Xylenes 3-28
3.6.6 n-Hexane 3-29
3.6.7 Other Air Toxics 3-29
3.7 References 3-29
4 Economic Impact Analysis and Distributional Assessments 4-36
4.1 Introduction 4-36
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4.2 Energy Markets Impacts 4-36
4.3 Distributional Impacts 4-37
4.3.1 Distributional Aspects of Compliance Cost Savings 4-37
4.3.2 Distributional Aspects of the Forgone Health Benefits 4-39
4.4 Small Business Impacts 4-39
4.5 Employment Impacts 4-40
5 Comparison of Benefits and Costs 5-1
5.1 Comparison of Benefits and Costs Across Regulatory Options 5-1
5.2 Uncertainties and Limitations 5-4
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LIST OF TABLES
Table
1-1
Table
1-2
Table
1-3
Table
1-4
Table
1-5
Table
1-6
Table
2-1
Table
2-2
Table
2-3
Table
2-4
Table
2-5
Table
2-6
Table
2-7
Table
2-8
Table
2-9
Table
2-10
Table
2-11
Table
2-12
Table
2-13
Table
2-14
Table
2-15
Table
2-16
Table
2-17
Table
2-18
Table
3-1
Table
3-2
Table
3-3
Table
3-4
Table
3-5
Table
3-6
Table
3-7
Table
5-1
Table
5-2
Estimated Cost and Emission Reductions of the 2016 NSPS OOOOa Fugitive Emissions
Requirements: 2016 NSPS RIA and Updated 2018 Baseline Comparison 1-6
Emissions Sources and Controls Evaluated for the Regulatory Alternatives 1-7
Costs and Emissions Reductions of the 2016 NSPS OOOOa under the Updated 2018 Baseline and the
Regulatory Alternatives Evaluated in the RIA 1-11
Cost Savings, Forgone Benefits and Increase in Emissions of Option 1 Compared to the 2018
Baseline, 2019 through 2025 (millions 2016$) 1-12
Cost Savings, Forgone Benefits and Increase in Emissions of Option 2 Compared to the 2018
Baseline, 2019 through 2025 (millions 2016$) 1-13
Cost Savings, Forgone Benefits and Increase in Emissions of the Proposed Option 3 Compared to the
2018 Baseline, 2019 through 2025 (millions 2016$) 1-13
Emissions Sources and Controls Evaluated for the Regulatory Alternatives 2-6
Reconsideration Affected Source Counts of the Proposed Option 3 Compared to the 2018 Baseline. 2-
11
Increase in Emissions under the Proposed Option 3 Compared to the 2018 Baseline, by year 2-12
Estimated Decrease in Natural Gas Recovery (Mcf) for the Proposed Option 3 Compared to the 2018
Baseline (millions 2016$) 2-14
Compliance Cost Savings Estimates for Proposed Option 3 Compared to the 2018 Baseline (millions
2016$) 2-15
Estimated Cost Savings of the Proposed Option 3, 2019-2025, using 3 and 7 Percent Discount Rates
(millions 2016$) 2-16
Comparison of Regulatory Alternatives to 2018 Baseline, 2020 and 2025 2-18
Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 1, 2020 2-20
Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 1, 2025 2-20
Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 2, 2020 2-21
Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 2, 2025 2-21
Incrementally Affected Sources, Emissions Increases and Cost Savings, Proposed Option 3, 20202-22
Incrementally Affected Sources, Emissions Increases and Cost Savings, Proposed Option 3, 2025 2-22
Estimated Cost Savings for the Proposed Option 3, 2019-2025 (millions 2016$) 2-24
Discounted Cost Savings Estimates for Proposed Option 3 Compared to the 2018 Baseline Using a 7
Percent Discount Rate (millions 2016$) 2-25
Comparison of Regulatory Alternatives to 2018 Baseline Using a 7 Percent Discount Rate 2-26
Discounted Cost Savings for the Proposed Option 3 using 7 and 3 Percent Discount Rates Compared
to the 2018 Baseline (millions 2016$) 2-27
Total Cost Savings and Increase in Emissions of the Proposed Option Under Alternative Monitoring
Frequencies at Compressor Stations 2-28
Climate and Human Health Effects of Forgone Emission Reductions from this Proposed Rule 3-2
Total Direct Increases in Emissions Compared to the 2018 Baseline across Regulatory Options, 2019
through 2025 3-5
Annual Direct Increases in Methane, VOC and HAP Emissions Compared to the 2018 Baseline,
Options 2 and 3, 2019 through 2025 3-6
Interim Domestic Social Cost of CH4, 2019-2025 (in2016$ per metric ton CH4)* 3-9
Estimated Forgone Domestic Climate Benefits of the Proposed Option 3, 2019-2025 (millions,
2016$) 3-10
Discounted Forgone Domestic Climate Benefits of the Proposed Option 3, PV and EAV (millions,
2016$) 3-10
Estimated Forgone Domestic Climate Benefits Across the Regulatory Options (millions, 2016$). 3-11
Summary of the Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone Monetized
Benefits, Cost Savings, and Net Benefits for Option 1 from 2019 through 2025 (millions, 2016$).. 5-2
Summary of the Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone Monetized
Benefits, Cost Savings, and Net Benefits for Option 2 from 2019 through 2025 (millions, 2016$).. 5-2
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Table 5-3 Summary of the Present Value (PV) and Equivalent Annualized Value (EAV) of Forgone Monetized
Benefits, Cost Savings, and Net Benefits for the Proposed Option 3 from 2019 through 2025
(millions, 2016$) 5-3
Table 5-4 Summary of Total Emissions Increases across Options, 2019 through 2025 5-3
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LIST OF FIGURES
Figure 3-1 2011 NATA Model Estimated Census Tract Carcinogenic Risk from HAP Exposure from All
Outdoor Sources based on the 2011 National Emissions Inventory 3-22
Figure 3-2 2011 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk from HAP Exposure from
All Outdoor Sources based on the 2011 National Emissions Inventory 3-23
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1 EXECUTIVE SUMMARY
1.1 Background
The action analyzed in this regulatory impact analysis (RIA) accompanies the proposed
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"). 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 rule include
hydraulically fractured oil and natural gas well completions and fugitive emissions from well
sites and compressor stations, and pneumatic pumps. EPA has granted reconsideration of three
requirements: the fugitive emissions requirements, well site pneumatic pump standards, and
requirements for certification of closed vent system design and capacity by a professional
engineer. In addition, EPA is reconsidering additional issues to streamline implementation and
cost-effectiveness of compliance, including clarifying definitions.
For purposes of this RIA, we focus on the proposed amendments that result in
quantifiable cost or emissions changes compared to an updated baseline. These provisions are
those related to the fugitive emissions requirements and certification by a professional engineer.
For details on the other provisions included in this proposed reconsideration that are not analyzed
in this RIA, see the preamble to the Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Reconsideration, found in the docket.1 We do not analyze
all provisions included in the preamble because we either do not have the data to do so (for
example, we do not have the data to analyze how the proposed exemption for fugitive
components including and downstream of the custody meter assembly will increase emissions),
or because we do not think the provision will lead to meaningful cost savings or emission
changes (for example, clarifying the circumstances for pneumatic pump infeasibility
determinations).
One of the requirements EPA is proposing to amend is monitoring frequency for fugitive
emissions requirements at certain well sites and at compressor stations. Under the proposed
1 Found on http://www.regulations.gov under Docket ID No. EPA-HQ-OAR-2017-0483
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amendments, the monitoring frequency for a specific well site or compressor station will depend
on the production of the well site or on the location of the well site or compressor station. In the
2016 NSPS OOOOa, all NSPS affected well sites are required to perform semiannual
monitoring, and all NSPS affected compressor stations are required to perform quarterly
monitoring. On March 12, 2018, EPA finalized a package containing amendments to the 2016
NSPS OOOOa ("Amendments package") to address immediate concerns regarding
implementation challenges related to the reliability of emission monitoring equipment during
extended periods of extreme cold temperatures on the Alaskan North Slope.2 These amendments
reduce monitoring frequency at NSPS affected well sites on the Alaskan North Slope from
semiannual to annual. In this reconsideration, EPA is proposing to change monitoring frequency
at NSPS affected low production well sites (well sites with less than 15 barrels of oil equivalent
(BOE) per well per day) to biennial (every other year), and proposing to change monitoring
frequency at all other NSPS affected well sites to annual. EPA is also proposing to reduce
monitoring frequency at NSPS affected compressor stations from quarterly to annual for those on
the Alaskan North Slope and co-proposing to reduce fugitive emissions monitoring frequency at
all other compressor stations to either semiannual or annual. The results in this RIA focus on the
estimates assuming semiannual fugitive emissions monitoring at compressor stations. For the
cost savings and emission increases under the co-proposed option assuming annual fugitive
emissions monitoring at compressor stations, see section 2.5.2.
In the 2016 NSPS OOOOa, EPA finalized a requirement for closed vent systems (CVS)
on NSPS affected storage vessels, pneumatic pumps, reciprocating compressors and centrifugal
compressors to be certified by a professional engineer, if applicable. In addition, EPA finalized a
requirement that a "qualified professional engineer" would have to certify technical infeasibility
for sources claiming that routing emissions from a pneumatic pump at a well site to a control
device is technically infeasible. The costs for those certifications by a professional engineer were
not considered in the 2016 NSPS OOOOa regulatory impact analysis (2016 NSPS RIA).3 This
RIA estimates those costs in the updated baseline and the impact of proposing to change the
requirement to allow certification by an in-house engineer as well.
2 83 FR 10628
3 Found under Docket ID No. EPA-HQ-OAR-2010-0505, and at
https://www3.epa.gov/ttn/ecas/docs/ria/oilgas_ria_nsps_final_2016-05.pdf
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This analysis estimates the impacts of the proposed changes as compared to an updated
baseline, explained in section 1.2, for the analysis years 2019 through 2025. All monetized
impacts of these amendments are presented in 2016 dollars. This analysis also includes a
presentation of the impacts in a present value (PV) framework. All sources that are affected by
the 2016 NSPS OOOOa, starting at the promulgation of the 2016 NSPS OOOOa, are called
"NSPS affected sources." The subset of these sources that experience a change in their
requirements due to this proposed action, are called "reconsideration affected sources." The
universe of reconsideration affected sources varies across the options being considered. This will
be explained more in section 1.3, below.
1.2 Summary of Updates from the Final 2016 NSPS RIA
This section summarizes the updates made to data, assumptions, source counts,
projections and state and local regulations that have been revised or promulgated since the
promulgation of the 2016 NSPS OOOOa that affect the impacts of the proposed actions
quantified in this RIA. These updates were combined with unchanged assumptions and methods
from the 2016 NSPS RIA to estimate an updated, 2018 baseline. This 2018 baseline represents
the current state of the industry. The cost and emission impacts estimated as a result of the three
options analyzed in this RIA are compared to this updated 2018 baseline. The updates and
revisions that affect the estimated impacts include:
• Annual Energy Outlook: In the 2016 NSPS OOOOa, we used the 2015 Annual Energy
Outlook. For the purposes of this analysis, we are using the most recent publication of the
Annual Energy Outlook (AEO), published February 2018.4 The estimates of drilling
activity published in the AEO are used to estimate projections of NSPS affected sources
over time, and the estimates of natural gas prices are used to estimate the value of product
recovery.
• U.S. Greenhouse Gas Inventory updates: Since the promulgation of the 2016 NSPS
OOOOa, the U.S. Greenhouse Gas Inventory (GHGI) has been updated.5 The data from
the updated GHGI was used in the projection of NSPS affected sources over time.
• Drillinglnfo: This RIA uses a more recent version of the Drillinglnfo dataset than was
used for the 2016 NSPS OOOOa.6 The Drillinglnfo dataset is used to characterize oil and
4 The 2018 AEO can be found at: https://www.eia.gov/outlooks/aeo/
5 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
6 Drillinglnfo is a private company that provides information and analysis to the energy sector. More information is
available at: http://info.drillinginfo.com
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natural gas wells and completion activity in the base year. The base year is 2014 in this
analysis, updated from 2012 in the 2016 NSPS RIA.
• State and Local Regulations: Since the promulgation of the 2016 NSPS OOOOa,
additional state and local requirements affecting the oil and natural gas sector have been
published, namely regulations in California and general permits in Pennsylvania. In this
analysis, we take the requirements from California, Colorado, Ohio, Pennsylvania, and
Utah into account. The requirements in these states are expected to result in broadly
similar overall emissions reductions to those expected from the 2016 NSPS OOOO and
this reconsideration, though the particular program designs in each of these states differs
from the 2016 NSPS OOOOa and the reconsideration requirements. In the 2016 NSPS
RIA, Wyoming's program was included as a program expected to result in broadly
similar overall emissions reductions. The requirements in Wyoming were reexamined
and are no longer considered to be equivalent for purposes of the RIA because they are
basin specific permit requirements, and are not applicable to the entire state.7
• Fugitive Emissions Requirements: Since the promulgation of the 2016 NSPS OOOOa,
EPA has published a final package which amends the fugitive emissions monitoring and
repair requirements for NSPS affected oil and natural gas well sites on the Alaskan North
Slope. The Amendments package reduces the fugitive emissions monitoring frequency
for NSPS affected well sites on the Alaskan North Slope from semiannual, as
promulgated in the 2016 NSPS OOOOa, to annual.
• Professional Engineer Certification: The 2016 NSPS OOOOa requires closed vent
systems and pneumatic pump technical infeasibility be certified by a professional
engineer. The cost of this provision was not quantified in the 2016 NSPS RIA analysis. In
this analysis, we are including the cost of the requirement for professional engineer
certifications in the baseline.
• Social Cost of Methane: In the 2016 NSPS OOOOa, 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 are using an interim estimate of the domestic social cost of methane
to estimate the forgone climate benefits resulting from the increase in methane emissions
due to the proposed action.
• Model Plants: The model plants used to estimate the emissions from a well site, and
emission reductions due to the fugitive emissions monitoring requirements, have been
updated. The update includes the addition of fugitive emissions components, namely
storage vessels. By adding storage vessels to the model plant, base emissions from a
7 For information on additional states that were examined and why they are not considered equivalent, see the TSD
and the State memo, both of which are available in the docket.
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wellsite are estimated to be larger, and the reductions due to the monitoring and repair
requirements have also increased compared to the base emissions and emission reduction
estimates used in the 2016 NSPS OOOOa RIA.8
• Other: In the 2016 NSPS OOOOa, all costs and benefits were presented in 2012 dollars.
In this analysis, all estimated costs are presented in 2016 dollars per E.O. 13771
implementation guidance.9 In addition, in the 2016 NSPS RIA, we present annualized
compliance costs and the benefits resulting from emission reductions occurring in 2020
and 2025. For this analysis, we estimate cost savings and forgone benefits resulting from
changes in compliance activities and emissions occurring in each year from 2019 through
2025.10 We also discount the annual cost savings and forgone benefits to 2016, and
present total PV and equivalent annualized value (EAV) over the analysis period.
Table 1-1 below shows the number of NSPS affected facilities, methane emission
reductions, VOC emission reductions and the total annualized costs including the value of
product recovery, in 2020 and in 2025 for the fugitive emissions requirements of the 2016 NSPS
OOOOa as estimated in the 2016 NSPS RIA, and under the 2018 updated baseline. The emission
reductions presented here are the emission reductions assuming the affected sources were not
performing compliance activities prior to the 2016 NSPS OOOOa. The only difference in the
requirements between the two estimates stems from the change to the fugitive emissions
requirements for well sites on the Alaskan North Slope, as explained above. Also as mentioned
above, the 2016 NSPS RIA estimates did not include the cost of professional engineer
certification. To be consistent, the estimates presented in this table for the 2018 baseline also
exclude the cost of professional engineer certification. In addition to the updates related to the
Amendments package, it should be noted that the assumptions used to estimate the 2018 baseline
values have been updated from those used to estimate the 2016 NSPS RIA values as explained
above (for example, projections, state and local regulations and model plants). The 2016 NSPS
OOOOa costs presented here do not match the cost estimates for the fugitive emissions
requirements as presented in the 2016 NSPS RIA. This is because costs in the 2016 NSPS RIA
are presented in 2012 dollars, and they have been updated to 2016 dollars in this table.
8 For more information on the model plants, see the TSD.
9 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.
10 In this analysis, the Drillinglnfo base year was updated from 2012 to 2014, therefore, the source projection
estimates are based on reconsideration affected facilities established starting in 2014 and it goes through 2025.
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Table 1-1 Estimated Cost and Emission Reductions of the 2016 NSPS OOOOa Fugitive
Emissions Requirements: 2016 NSPS RIA and Updated 2018 Baseline Comparison
2016 NSPS RIA
2018 Baseline
2020
2025
2020
2025
Counts of NSPS Affected Fugitive
Emissions Sources
94,100
192,300
44,000
87,000
Methane Emission Reductions
(short tons)
169,600
346,200
120,000
240,000
VOC Emission Reductions (tons)
46,300
94,500
32,000
62,000
Total Annualized Cost, with
Product Recovery (7%, millions,
$199
$407
$115
$219
2016$)
1.3 Regulatory Options Analyzed in this RIA
In this RIA, we examine the effect of the proposed actions relative to the updated 2018
baseline. The sources affected by this proposed reconsideration (termed "reconsideration
affected sources" in this RIA) are a subset of the NSPS affected sources. The universe of
reconsideration affected sources includes sources of the types affected by this reconsideration
that are considered new or modified starting in 2019, as well as sources that were affected by the
2016 NSPS OOOOa before 2019 and are expected to change compliance activity as a result of
this action. For example, a low production well site that became an NSPS affected source in
2016 is also a reconsideration affected source under Option 2 and Option 3, because they are
expected to change compliance activities (reduce monitoring frequency from semiannual to
annual or biennial). In addition, the estimates of new low production well sites starting in 2019
are also reconsideration affected sources since the proposed action is different than the 2016
NSPS OOOOa action they would be performing otherwise. However, projected new affected
well sites on the Alaskan North Slope are not reconsideration affected sources, since they are not
changing compliance activities as a result of this action. The change in compliance activities
(from semiannual as promulgated under the 2016 NSPS OOOOa to annual fugitive emissions
monitoring frequency) at those well sites is attributed to the Amendments package. As we
assume certifications only happen once, the only affected sources for the proposed certification
requirements are those that become affected starting in 2019. We also examine the effect of two
alternative suites of options. The universe of reconsideration affected sources is different under
the different options. Table 1-2 shows the affected sources, points and controls for the 2016
NSPS OOOOa, the updated 2018 baseline and the three options that are analyzed in this RIA.
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The bolded entries in the table represent the sources that are considered reconsideration affected
sources under each option.
Table 1-2 Emissions Sources and Controls Evaluated for the Regulatory Alternatives
Emissions Point
2016 NSPS
OOOOa
2018
Baseline
Option 1
Option 2
Option 3
(Co-
Proposed)1
Fugitive Emissions - Planning, Monitoring and Maintenance
Natural Gas and Oil Well Sites
Low Production Well Sites (<15
BOE/day)
Natural Gas and Oil Well Sites on
the Alaskan North Slope
Compressor Stations in Gathering
and Boosting, Transmission and
Storage
Compressor Stations in Gathering
and Boosting, Transmission and
Storage on the Alaskan North
Slope2
Semiannual
Semiannual
Semiannual
Semiannual
Semiannual
Annual
2 Yrs.
Semiannual Semiannual,
then Annual
Semiannual
Annual
Annual
Annual
Annual
Biennial
Annual
Quarterly
Quarterly
Quarterly
Quarterly
Quarterly
Quarterly
Quarterly Semiannual
Annual
Annual
Certifications
Closed Vent Systems on
Pneumatic Pumps, Reciprocating
Compressors, Centrifugal
Compressors, and Storage
Vessels; and Pneumatic Pump
Technical Infeasibility
Professional
Engineer
Professional
Engineer
In-House
Engineer
In-House
Engineer
In-House
Engineer
1 In the preamble, we are co-proposing the option listed here with an option where all requirements remain the same,
with the exception of fugitive monitoring frequency at compressor stations. In the alternative co-proposed option,
fugitive monitoring at compressor stations is reduced to annual.
2 We do not currently have the data to estimate the effects of the proposed amendments pertaining to compressors
stations on the Alaskan North Slope. All other provisions presented in this table are analyzed in this RIA. 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 meaningful cost savings or emission changes.
The 2016 NSPS OOOOa requires fugitive emissions survey and repair programs be
performed semiannually (twice per year) at the NSPS affected newly drilled or refractured well
sites, and quarterly at new or modified gathering and boosting stations and new or modified
transmission and storage compressor stations. Closed vent systems and pneumatic pump
technical infeasibility have to be certified by a professional engineer.
The updated 2018 baseline reflects that fugitive emissions survey and repair programs are
now required to be performed only annually at NSPS affected well sites in the Alaskan North
Slope (as promulgated in the final Amendments package), semiannually at all other NSPS
affected newly drilled or refractured gas well sites, and quarterly at new or modified gathering
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and boosting stations and new or modified transmission and storage compressor stations. Closed
vent systems and pneumatic pump technical infeasibility have to be certified by a professional
engineer.
Option 1 is the most stringent option considered. Under this analysis, fugitive emissions
monitoring frequencies are unchanged. 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 requiring a professional engineer. This option results in reduced
regulatory burden related to the certification requirements, but is unlikely to affect realized
emission reductions.11 This option has the smallest universe of affected sources.
Option 2 reduces the monitoring frequency for all well sites outside of the Alaskan North
Slope, and all compressor stations on the Alaskan North Slope. Low production well sites
producing less than 15 barrels of oil equivalent (BOE) per day are required to perform fugitive
emissions survey and repair programs annually. Well sites on the Alaskan North Slope retain the
annual survey and repair requirement. All other NSPS affected well sites retain the semiannual
survey and repair requirement for two years, stepping down to annual monitoring thereafter.
Fugitive emissions survey and repair programs at compressor stations on the Alaskan North
Slope are also reduced to annual frequency, while monitoring frequency at all other NSPS
affected compressor stations remains at quarterly.12 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 requiring a professional engineer. This option leads to
reduced regulatory burden, as well as greater emissions compared to the 2018 baseline. The
universe of reconsideration affected sources under this option is greater than that of Option 1.
The co-proposed Option 3 is the least stringent option analyzed. It retains annual
monitoring and repair frequency for well sites on the Alaskan North Slope, reduces monitoring
frequency for all compressor stations on the Alaskan North Slope and all non-low production
11 Emissions should not be affected by this change in certification requirements as long as 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 any information to estimate the potential for
these types of technical changes, if any, when moving from professional engineer certifications to in-house engineer
certifications.
12 For an analysis of the costs of the proposed option under alternative monitoring frequencies at compressor
stations, see section 2.5.2.
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well sites outside of the Alaskan North Slope to annual, and reduces the frequency at all low
production well sites to biennial monitoring (every other year). Fugitive emissions monitoring
and repair frequency at compressor stations outside of the Alaskan North Slope is reduced to
semiannual. The certification requirement is updated to allow companies the choice of using an
in-house engineer as opposed to requiring a professional engineer. This option leads to the
largest universe of reconsideration affected sources, the largest impact on costs and benefits
compared to the 2018 baseline, as well as the greatest increase in emissions.13
1.4 Summary of Results
A summary of the key results of the co-proposed Option 3 of this RIA follow. All dollar
estimates are in 2016 dollars. Also, all costs, emissions changes, and benefits are estimated
relative to the updated 2018 baseline.
• Emissions Analysis: This proposed amendment to the 2016 NSPS OOOOa is expected
to lead to an increase in emissions compared to the 2018 baseline. Methane emissions are
estimated to increase by between 32,000 short tons per year (in 2019) and 76,000 short
tons per year (in 2025) for a total of 380,000 short tons over 2019 through 2025. VOC
emissions are expected to increase by between 8,500 tons per year and 20,000 tons per
year, for a total of 100,000 tons over the same period. HAP emissions are expected to
increase by between 320 and 760 tons per year, with an estimated total of 3,800 more
tons of HAP emissions over 2019 through 2025 under the proposed amendments
compared to the 2018 baseline.
• Benefits Analysis: The proposed option is expected to result in climate related dis-
benefits compared to the 2018 baseline. The PV of the domestic share of forgone
benefits, using an interim estimate of the domestic social cost of methane (SC-CH4)
discounting at a 7 percent rate is estimated to be $13.5 million from 2019 through 2025;
the EAV is estimated to be $2.3 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 $54 million; the EAV is estimated to be $8.3 million per year.
• Compliance Cost Analysis: The proposed option is expected to result in compliance cost
savings to the affected firms compared to the 2018 baseline. The PV of these cost
savings, discounted at a 7 percent rate and not including the forgone value of product
recovery (about $48 million) is estimated to be about $429 million dollars. When the
forgone value of product recovery is included, the PV of the cost savings is about $380
million. This is associated with an EAV of cost savings of about $74 million per year
without including the forgone value of product recovery (about $8.4 million per year), or
$66 million per year when the value of product recovery is included. Under a 3 percent
13 The alternative co-proposed option, assuming annual monitoring at compressor stations is slightly less stringent
and leads to a larger cost savings, forgone benefits and increase in emissions compared to the 2018 baseline.
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discount rate, the PV of cost savings, accounting for the forgone value of product
recovery (about $62 million) is $484 million, with an associated EAV of $75 million per
year after accounting for the forgone value of product recovery (about $9.6 million per
year).
• Energy Markets Impacts Analysis: The 2016 NSPS RIA estimated small (less than 1
percent) impacts on energy production and markets as a result of the final regulation.
EPA expects that this deregulatory action, if finalized, would partially ameliorate the
impacts estimated for the final NSPS in the 2016 NSPS RIA.
• Distributional Impacts: The compliance cost savings and forgone benefits presented in
this analysis are not expected to be felt uniformly across the population, and may not
accrue to the same individuals or communities. EPA did not conduct a quantitative
assessment of the distributional impacts of the proposed reconsideration, but a qualitative
discussion of the distributional aspects of the compliance cost savings and the forgone
health benefits of this deregulatory action are provided in section 4.3.
• Small Entity Impacts Analysis: EPA expects that this deregulatory action, if finalized
as proposed, would ameliorate the impacts estimated for the final 2016 NSPS OOOOa in
the 2016 NSPS RIA. We have therefore concluded that this action will relieve regulatory
burden for all directly regulated small entities and that this action, if finalized as
proposed, will not have a Significant Impact on a Substantial Number of Small Entities
(SISNOSE).
• Employment Impacts Analysis: EPA expects slight reductions in labor associated with
compliance-related activities relating to the proposed fugitive emissions requirements and
the inspections of closed vent systems compared to the 2016 NSPS OOOOa. However,
due to uncertainties associated with how the proposed reconsideration will influence the
portfolio of activities associated with fugitive emissions-related requirements, EPA is
unable to provide quantitative estimates of compliance-related labor changes.
Table 1-3 presents the estimated annualized costs accounting for product recovery and
the emission reductions for the updated 2018 baseline, as well as the three options analyzed in
this RIA for 2020 and 2025. The rest of this document details the changes estimated as a result of
this reconsideration. These changes are estimated as the difference between the 2018 baseline
and the option being analyzed.
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Table 1-3 Costs and Emissions Reductions of the 2016 NSPS OOOOa under the
Updated 2018 Baseline and the Regulatory Alternatives Evaluated in the RIA
Total Annualized
Methane Emission
VOC Emission
Cost, w/ Product
Facilities
Reductions
Reductions
Recovery
Affected
(short tons)
(short tons)
(7%, millions 2016$)
2020
2018 Baseline
58,000
120,000
32,000
$123
Option 1
58,000
120,000
32,000
$120
Option 2
58,000
102,000
26,000
$90
Option 3
58,000
83,000
22,000
$62
2025
2018 Baseline
102,100
240,000
62,000
$228
Option 1
102,100
240,000
62,000
$225
Option 2
102,100
200,000
51,000
$165
Option 3
102,000
160,000
42,000
$113
Table 1-4 through Table 1-6 present the PV and EAV, estimated using discount rates of 7
and 3 percent, of the changes in benefits, costs, and net benefits, as well as the increase in
emissions compared to the 2018 baseline for all three options. These values are estimated for the
universe of reconsideration affected sources under each option over the 2019 through 2025
analysis period, discounted to 2016, and are in 2016 dollars. When discussing net benefits, both
here and in section 5, we modify the relevant terminology to be more consistent with traditional
net benefits analysis. In the following tables, we refer to the cost savings as presented in section
2 as the "benefits" of this proposed action and the forgone benefits as presented in section 3 as
the "costs" of this proposed action. The net benefits are the benefits (cost savings) minus the
costs (forgone benefits). As explained in the following sections, all costs and benefits outlined in
this RIA are estimated as the change from the updated baseline.
As can be seen in Table 1-4 through Table 1-6, Option 1 results in the smallest estimated
impact on costs and emissions, and the proposed Option 3 results in the largest estimated
impacts.14 It should be noted that the estimated costs (forgone benefits) of Options 2 and 3 only
include the monetized climate effects of the increase in methane emissions as a result of the
14 Option 1 is unlikely to result in any changes in emissions, because it does not affect fugitive emissions
requirements. Emissions should not be affected by the change in certification requirements under Option 1 as
long as 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 any
information to estimate the potential for these types of technical changes, if any, or when moving from
professional engineer certifications to in-house engineer certifications.
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option under consideration, though there are increases in VOC and HAP emissions as well.
While we expect that the forgone VOC emission reductions may also degrade air quality and
adversely affect health and welfare effects associated with exposure to ozone, PM2.5, and HAP,
data limitations prevent us from quantifying forgone VOC-related health benefits. This omission
should not imply that these forgone benefits may not exist; rather, it reflects the difficulties in
modeling the direct and indirect impacts of the reductions in emissions for this industrial sector
with the data currently available. A broader explanation of forgone benefits can be read in
section 3 of this RIA. For a summary of the cost savings and increase in emissions from the co-
proposed option, assuming annual fugitive emissions monitoring frequency at compressor
stations, see section 2.5.2.
Table 1-4 Cost Savings, Forgone Benefits and Increase in Emissions of Option 1
Compared to the 2018 Baseline, 2019 through 2025 (millions 2016$)
7%
3%
Present
Value
Equivalent
Annualized
Value
Present
Value
Equivalent
Annualized
Value
Benefits (Total Cost Savings)
$17
$2.9
$21
$3.3
Cost Savings
$17
$2.9
$21
$3.3
Forgone Value of Product Recovery
$0
$0
$0
$0
Costs (Forgone Domestic Climate Benefits)1
$0
$0
$0
$0
Net Benefits2
$17
$2.9
$21
$3.3
Emissions Total Change
Methane (short tons) 0
VOC 0
HAP 0
Methane (million metric tons C02E) 0
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions. This option is
unlikely to affect emissions, therefore there are no monetized forgone benefits as a result of this option.
2 Estimates may not sum due to independent rounding.
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Table 1-5 Cost Savings, Forgone Benefits and Increase in Emissions of Option 2
Compared to the 2018 Baseline, 2019 through 2025 (millions 2016$)
7%
3%
Present
Value
Equivalent
Annualized
Value
Present
Value
Equivalent
Annualized
Value
Benefits (Total Cost Savings)
$209
$36
$265
$41
Cost Savings
$234
$41
$299
$47
Forgone Value of Product Recovery
$26
$4.5
$33
$5.2
Costs (Forgone Domestic Climate Benefits)1
$7.2
$1.2
$28
$4.4
Net Benefits2
$201
$35
$237
$37
Emissions Total Change
Methane (short tons) 200,000
VOC 56,000
HAP 2,100
Methane (million metric tons C02E) 4.5
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions. See Section 3.3
for more discussion.
2 Estimates may not sum due to independent rounding.
Table 1-6 Cost Savings, Forgone Benefits and Increase in Emissions of the Co-
Proposed Option 3 Compared to the 2018 Baseline, 2019 through 2025 (millions 2016$)
7%
3%
Present Value
Equivalent
Annualized
Value
Present Value
Equivalent
Annualized
Value
Benefits (Total Cost Savings)
$380
$66
$484
$75
Cost Savings
$429
$74
$546
$85
Forgone Value of Product Recovery
$48
$8.4
$62
$9.6
Costs (Forgone Domestic Climate Benefits)1
$13.5
$2.3
$54
$8.3
Net Benefits2
$367
$64
$431
$67
Emissions Total Change
Methane (short tons) 380,000
VOC 100,000
HAP 3,800
Methane (million metric tons C02E) 8.5
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 3.3 for
more discussion.
2 Estimates may not sum due to independent rounding.
1.5 Organization of this Report
This analysis follows much of the same methods used to estimate costs of the 2016 NSPS
OOOOa. The remainder of this report outlines some of that methodology, with further
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explanations of where the underlying data, assumptions or methods diverge, as well as the
estimated results. For details on the methodology that is unchanged from the 2016 NSPS
OOOOa, please see the 2016 NSPS RIA.15 Section 2 describes the emissions and compliance
cost analysis of the proposed action compared to the 2018 baseline. Section 2 also describes the
cost savings compared to the 2018 baseline in a PV framework, as well as presents the associated
EAV. Section 3 describes the forgone benefits of this rule compared to the 2018 baseline,
including the PV and EAV over the 2019 through 2025-time frame. Section 4 describes the
economic impacts expected as a result of this proposed action. Section 5 presents a comparison
of forgone benefits and cost savings of this proposed reconsidered rule, as well as the net
benefits compared to the updated 2018 baseline.
15 Found at: https://www3.epa.gov/ttn/ecas/docs/ria/oilgas_ria_nsps_final_2016-05.pdf
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2 COMPLIANCE COST SAVINGS AND FORGONE EMISSION REDUCTIONS
2.1 Introduction
This chapter describes the emissions and compliance cost analysis for the proposed
reconsideration of the 2016 NSPS OOOOa. Incremental changes in emissions and costs as a
result of this proposal are estimated with respect to a current policy baseline. Section 2.2
discusses the updates to data and the approach used in this analysis with respect to the RIA
analysis for the 2016 NSPS OOOOa. Section 2.3 describes the steps in the emissions and
compliance cost analysis of the requirements that are being reconsidered and presents an
overview of results. Section 2.4 presents detailed tables describing the impacts for each source
affected by this proposed reconsideration for the analyzed. Section 2.5 presents the present value
and equivalent annualized value of the cost savings. Please see the Background Technical
Support Document (TSD) located at Docket ID No. EPA-HQ-OAR-2017-0483 for more detail.
2.2 Emissions Points and Pollution Controls assessed in the RIA
This RIA estimates impacts associated with reconsidered requirements for fugitive
emissions monitoring, and certifications of closed vent system design and technical infeasibility
of routing pneumatic pump emissions to an existing control device. In addition, EPA is
proposing reconsidered requirements related to pneumatic pumps and oil well completions, as
well as technical corrections and clarifications, although this RIA does not quantify any changes
in emissions or costs resulting from those proposed amendments. This section provides a basic
description of the emissions sources and controls considered, and which aspects of the
reconsideration proposals have quantified impacts in this RIA. For more detailed information on
the requirements that are being reconsidered, see the Preamble.16 For the other emission sources
and controls evaluated in the 2016 NSPS OOOOa, see the 2016 NSPS RIA.17
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
16 Found on regulations.gov under Docket ID No. EPA-HQ-OAR-2017-0483
17 Found under Docket ID No. EPA-HQ-OAR-2010-0505, and at
https://www3.epa.gov/ttn/ecas/docs/ria/oilgas_ria_nsps_final_2016-05.pdf
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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.
In the 2016 NSPS RIA, EPA estimated costs and emission reductions assuming the use of
a leak monitoring program based on the use of optical gas imaging (OGI) leak detection
combined with leak correction. In addition, alternative frequencies for fugitive emissions surveys
were considered: annual, semiannual, and quarterly. This RIA estimates the changes in impacts
from reducing fugitive emissions monitoring frequency from the requirements promulgated in
the 2016 NSPS OOOOa on NSPS affected oil and natural gas facilities.
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 or processes. Closed vent systems must be designed to
properly handle the particular configuration and flow rates of different facilities.
For the 2016 NSPS OOOOa, EPA requires closed vent systems be certified by a
professional engineer. In addition, the 2016 NSPS OOOOa requires that facilities claiming
technically infeasibility in routing emissions from well site pneumatic pumps to an existing
control device must get that technical infeasibility certified by a professional engineer. The cost
impact of the professional engineer certification requirements was not evaluated in the 2016
NSPS RIA. In this analysis, EPA evaluates the impact of the certification requirements, and the
effects of allowing facilities to choose either a professional engineer or an in-house engineer to
perform the required certifications.
Additional Reconsideration Topics Not Quantified in this RIA: The reconsideration preamble
and proposed regulatory text includes discussion and proposals of a number of technical issues
for which this analysis does not estimate impacts. These include, but are not limited to, the issues
described below.18
• Pneumatic Pumps: EPA is proposing changes in the circumstances for which it
may be infeasible to control emissions from well site pneumatic pumps by
18 See the Preamble for more information, at Docket ID No. EPA-HQ-OAR-2017-0483.
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removing the distinctions between greenfield and non-greenfield sites. These
changes are intended to better characterize the circumstances under which control
may be infeasible, and thus would not necessarily lead to a change in actual
emissions.
• Well Completions: EPA is proposing changes and 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 increase cost savings (e.g., by lowering the burden of
recordkeeping requirements) or be associated with increases in emissions relative
to the 2018 baseline, but EPA does not have sufficiently specific information to
quantify these changes.
• Fugitive Emissions: In addition to the quantified issues described above, EPA is
proposing changes to fugitive emissions requirements with respect to the
definitions of modification, third party equipment, and more, as well as the
characterization of production levels for the purposes of well site fugitive
emissions monitoring. In addition, EPA is proposing changes to the repair of
leaking fugitive emissions components that were put on a delay of repair list.
Some changes may result in cost savings (e.g., aligning pneumatic pump closed
vent system requirements with storage vessel closed vent system requirements),
and some may result in increased emissions (e.g., exempting fugitive components
downstream of the custody meter assembly), but EPA does not have the
information necessary to quantify these changes.
• Gas Processing Plants: EPA is proposing to exempt equipment from LDAR at gas
processing plants that has been in service less than 300 hours per year when the
equipment is only used during emergencies, as a backup, or is only in service
during startup and shutdown. This may increase costs savings and emissions due
to reduced LDAR requirements, but EPA does not have the data necessary to
quantify these changes.
• Alternative Means of Emission Limitation provision: EPA is making changes to
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the Alternative Means of Emission Limitation (AMEL) provision. Though the
changes, as outlined in the preamble, may lead to lower costs (for example, due to
streamlining regulatory efforts), we do not have any information on specifically
when, or how, costs or emissions may change.
2.3 Compliance Cost Analysis
In this section, we provide an overview of the compliance cost analysis used to estimate
the difference in the private expenditures to the industry when complying with the proposed
reconsidered rule compared to the 2016 NSPS OOOOa, under the updated 2018 baseline.
Updates to the data and analysis approach from the 2016 NSPS RIA are described in section 1.2
of this RIA. A detailed discussion of the methodology, data and assumptions used to estimate the
compliance cost impacts of this reconsideration that have been updated since the 2016 NSPS
RIA is presented in the TSD.19 The methodology, data and assumptions that are not discussed
here are the same as were used in the 2016 NSPS RIA, and can be found in the 2016 NSPS Final
TSD for that action.20
The following sections describe each step in the compliance cost analysis. First,
representative facilities are established for each affected source category, including baseline
emissions and the control options. Second, the number of incrementally affected facilities under
the 2018 baseline for each type of equipment or facility are projected, and the reconsideration
affected sources are estimated. The change in national emissions and cost estimates are
calculated by multiplying representative factors from the first step, by the estimated number of
reconsideration 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 for useful processes or sold. The change in national cost estimates include the change
in estimated revenue from product recovery where applicable.
In this section, we present the effect of this proposal on costs and emissions from 2019
through 2025, under the assumption that 2019 is the first year the reconsidered requirements will
be in effect. We chose to analyze through 2025 due to limited information, as explained in
19 Docket ID No. EPA-HQ-OAR-2017-0483
20 Docket ID No. EPA-HQ-OAR-2010-0505-7631.
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section 2.3.3. In addition, in this section, we are providing analysis for 2020 and 2025, which
allows the reader to draw comparisons to the 2016 NSPS RIA. 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 2.3.3, and results in this RIA are presented in
2016 dollars, while the 2016 NSPS RIA results are presented in 2012 dollars.
2.3.1 Regulatory Options
For each reconsideration affected emission source, point, and control option, the TSD
develops a representative facility. The characteristics of this facility include typical equipment,
operating characteristics, and representative factors including baseline emissions and the costs,
emissions reductions, and product recovery resulting from each control option. In this RIA, we
examine three broad regulatory options. Table 2-1 shows the emissions sources, points, and
controls for 2016 NSPS OOOOa, the updated 2018 baseline, the co-proposed Option 3 and two
alternative options being considered for the sources affected under this reconsideration proposal
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Table 2-1 Emissions Sources and Controls Evaluated for the Regulatory Alternatives
Emissions Point
2016 NSPS
OOOOa
2018
Baseline
Option 1
Option 2
Option 3
(Co-
Proposed)1
Fugitive Emissions - Planning, Monitoring and Maintenance
Natural Gas and Oil Well Sites
Low Production Well Sites (<15
BOE/day)
Natural Gas and Oil Well Sites on
the Alaskan North Slope
Compressor Stations in Gathering
and Boosting, Transmission and
Storage
Compressor Stations in Gathering
and Boosting, Transmission and
Storage on the Alaskan North
Slope2
Semiannual
Semiannual
Semiannual
Semiannual
Semiannual
Annual
2 Yrs.
Semiannual Semiannual,
then Annual
Semiannual
Annual
Annual
Annual
Annual
Biennial
Annual
Quarterly
Quarterly
Quarterly
Quarterly
Quarterly
Quarterly
Quarterly Semiannual
Annual
Annual
Certifications
Closed Vent Systems on
Pneumatic Pumps, Reciprocating
Compressors, Centrifugal
Compressors, and Storage
Vessels; and Pneumatic Pump
Technical Infeasibility
Professional
Engineer
Professional
Engineer
In-House
Engineer
In-House
Engineer
In-House
Engineer
1 In the preamble, we are co-proposing the option listed here with an option where all requirements remain the same,
with the exception of fugitive monitoring frequency at compressor stations. In the alternative co-proposed option,
fugitive monitoring at compressor stations is reduced to annual.
2 We do not currently have the data to estimate the effects of the proposed amendments pertaining to compressors
stations on the Alaskan North Slope. All other provisions presented in this table are analyzed in this RIA. 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 meaningful cost savings or emission changes.
In addition to the requirements listed above, 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, and pneumatic controllers throughout the oil and
natural gas source category. These requirements are not analyzed in this RIA because the
proposed reconsideration does not include amendments that change the cost or emissions from
those achieved under the 2016 NSPS OOOOa requirements.
2.3.2 Unit Level Cost Savings and Emission Increases
The requirements affecting fugitive emissions requirements and certifications of technical
infeasibility and closed vent systems are the only sources where changes in cost and emissions
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resulting from proposed reconsideration requirements have been quantified. Facility level costs
and emission reductions for the fugitive emission requirements for each of the model plants is in
Volume 1 of the TSD. For this reconsideration, the TSD and RIA results are based on a more
disaggregated set of model plants used to analyze the changes in monitoring requirements among
subsets of oil and natural gas well sites than the set used in the 2016 NSPS OOOOa analysis.
Whereas the previous analysis included three model plants reflecting either oil, oil with
associated gas, or natural gas well sites, this analysis is based on 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 facility level cost savings
and emission increases from the proposed requirements in this reconsideration were calculated
by subtracting the costs and emissions of the model plants under the proposed option (and the
alternative options) from the costs and emissions of the model plants under the 2018 baseline.
Detailed descriptions of what is included in the cost estimates is also provided in Volume 1 of
the TSD.
The cost of certifications being performed by a professional engineer was not included in
the analysis of the 2016 NSPS OOOOa rule. This analysis updates baseline cost estimates to
include professional engineer certification costs, as well as estimates the savings from allowing
the certifications to be performed by an in-house engineer. The cost of a certification by a
professional engineer is estimated to be just under $550 per certification, and the cost of the
same certification performed by an in-house engineer is estimated to be about $358 per
certification. Therefore, the cost savings per certification is estimated to be about $190 per
certification.21
2.3.3 Projection of Affected Facilities
The second step in estimating national costs and emissions impacts of the proposed rule
is projecting the number of NSPS and reconsideration affected facilities. We first update the
number of NSPS affected facilities under the updated 2018 baseline. Then, we estimate the
projection of reconsideration affected facilities, which are facilities that would be expected to
21 The costs of certification being performed by a professional engineer and by an in-house engineer are explained
fully in the TSD.
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change their control activities as a result of this reconsideration. Facilities in states with similar
state-level requirements and facilities with only recordkeeping requirements are not included
within the estimates of affected facilities.
We analyze the effects of this proposal on cost and emissions compared to the 2018
baseline. The 2018 baseline includes the costs and emissions of the projected NSPS affected
facilities, after accounting for updated assumptions and data. NSPS affected facilities include
facilities that are new or modified since the 2015 NSPS OOOOa proposal, and were/are expected
to change control activities as a result of the 2016 NSPS OOOOa, starting from a baseline of a
world 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 total
number of facilities subject to the 2016 NSPS OOOOa accumulates. As in the final 2016 NSPS
RIA, this analysis assumes that all new equipment and facilities established from 2015 through
2024 are still in operation in 2025.
The reconsideration affected facilities are estimated as the subset of the NSPS affected
facilities that are expected to change control 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 action and are 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 what their
monitoring frequency would have been as a result of this action. For the proposed option, these
sources include fugitive emissions sources at well sites outside of the Alaskan North Slope and
compressor stations both outside of and on the Alaskan North Slope.22 Reconsideration affected
sources that require a certification are only affected under the projection of newly affected
sources. Sources that have already completed professional engineer certifications are not counted
as reconsideration affected sources.
EPA has projected affected facilities using a combination of historical data from the U.S.
GHG Inventory (GHGI), DI Desktop, and projected activity levels taken from the Energy
Information Administration (EIA) AEO. EPA derived typical counts for new gathering and
boosting, and transmission and storage compressor stations by averaging the year-to-year
22 We do not quantify any emissions or cost changes associated with new compressor stations on the Alaskan North
Slope. See Volume 2 of the TSD for details.
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changes over the past ten years in the GHGI. New and modified well sites are based on the count
of wells in 2014 from DI Desktop, and projections and growth rates consistent with the drilling
activity in the AEO. For this proposed RIA, the projections have been updated from the 2016
NSPS RIA to reflect the projection estimates in the 2018 AEO.
The 2018 AEO (along with historical year information from previous AEOs) reflects a
significant drop in oil and gas drilling between 2014 and 2016, followed by projected increases
from 2016 through 2025. While the 2018 AEO projects that oil and gas well drilling will more
than double from about 14 thousand wells in 2016 to about 30 thousand wells in 2025, this
projection is about 40 percent lower than was projected in the 2015 AEO, which was previously
used. In comparison to the 2015 AEO, the 2018 AEO shows about 11 percent lower crude oil
production and about 17 percent higher dry natural gas production, indicating an increase in
estimated production per well.
This RIA includes an enhanced analysis with respect to previous oil and gas NSPS RIA
analyses by including year-by-year results over the 2014 to 2025 analysis period and better
disaggregating facilities by vintage and production levels. While it is desirable to analyze
impacts beyond 2025 in this RIA, 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 gas
industry. For example, EPA has limited information on how practices, equipment, and emissions
at new facilities evolve as they age or may be shut down. The current analysis assumes that
newly established facilities remain in operation for the entire analysis period, which would be
less realistic for longer-term analysis. In addition, in a dynamic industry like oil and natural gas,
technological progress in control technology is also likely to change significantly over a longer
time horizon. For example, the current analysis does not include potential fugitive emissions
controls utilizing remote sensing technologies currently under development.
We also reviewed state regulations and permitting requirements which require mitigation
measures for many emission sources in the oil and natural gas sector. Detailed information is
included in section 3.2.2 of 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"), located at Docket ID No. EPA-HQ-OAR-2017-
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0483.23 This analysis was done for the 2016 NSPS RIA, with the states of Colorado, Utah, Ohio
and Wyoming expected to result in broadly similar overall emissions reductions. For this RIA,
state regulations and permitting requirements were reexamined. While the particular program
designs in each of the states examined differs from the 2016 NSPS OOOOa, for the purpose of
this RIA analysis, the current requirements in Colorado, Utah, Ohio, Pennsylvania, and
California are expected to result in broadly similar overall emissions reductions. California and
Pennsylvania have been added as states with similar requirements for this analysis because the
requirements in the states have been finalized since the promulgation of the 2016 NSPS OOOOa.
The requirements in Wyoming are no longer considered to be equivalent for purposes of the RIA
because they are basin specific permit requirements, and are not applicable to the entire state.
Requirements in Texas are not included as broadly equivalent requirements in this analysis
because they include a permit by rule, which we do not consider equivalent in terms of overall
emissions reductions.24 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.25
Applicable facilities in these five states are not included in the estimates of incrementally
affected facilities presented in the RIA, as sources in those states would be expected to control
emissions at a comparable level regardless of the reconsidered federal standards. This means that
any additional costs and benefits incurred by facilities in these states to comply with the federal
standards beyond the state requirements (e.g., recordkeeping or verification requirements) are not
reflected in this RIA.
Table 2-2 presents the number of reconsideration affected sources for each year of
analysis after generally accounting for state regulations. In addition to the caveats regarding
facilities affected by state regulations described above, facilities with only recordkeeping
requirements are also not included within incrementally affected facilities.
23 For a more detailed explanation of state programs, see section 3.2.2 of 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.
24 We do not consider the permit by rule in Texas as equivalent for RIA purposes because they are self-certified
permits and we currently have a lack of certainty on the degree of enforcement of these rules.
25 Docket ID No. EPA-HQ-OAR-2017-0483
2-10
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Table 2-2 Reconsideration Affected Source Counts of the Co-Proposed Option 3
Compared to the 2018 Baseline
Year
Incrementally Affected
Sources1
Total Affected
Sources2
2019
21,000
49,000
2020
22,000
58,000
2021
23,000
66,000
2022
23,000
75,000
2023
24,000
84,000
2024
24,000
93,000
2025
24,000
100,000
Note: Affected source counts are the same under the alternative co-proposed option.
1 Incrementally reconsideration affected sources includes sources that are newly affected in each year.
2 Total reconsideration affected sources includes sources that have to change their control activity as a result of the
rule 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 proposal compared to the 2018 baseline.
The table does not include estimated counts of a) affected facilities in states with similar state-level requirements to
the proposed option, b) NSPS affected facilities whose controls are unaffected by the reconsideration.
The estimates for affected well sites are based on the count of new and modified wells in
2014 from DI Desktop, and then projected using year by year growth rates from the AEO. The
estimates for other 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, particularly pneumatic pumps and controllers, the impact estimates may
be under-estimated due to the focus on new sources. Newly constructed affected facilities are
estimated based on averaging the year-to-year changes in the past 10 years of activity data in the
Greenhouse Gas Inventory for compressor stations, pneumatic pumps, compressors, and
pneumatic controllers. 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 newly
constructed units.
2.3.4 Emissions Increases
Table 2-3 summarizes the national increase in emissions associated with the proposed
Option 3 compared to the updated 2018 baseline as described in Section 2.2. This increase in
emissions is estimated by multiplying the unit-level increase in emissions from the updated
baseline associated with each applicable control and facility type by the number of incrementally
affected sources of that facility type. In this analysis, closed vent system and technical
infeasibility certification requirements are not associated with any direct emission reductions;
2-11
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therefore, all emissions increases are attributed to the changes in the fugitive emissions
monitoring program. Please note that all results have been rounded.
Table 2-3 Increase in Emissions under the Co-Proposed Option 3 Compared to the
2018 Baseline, by year
Emission Changes
Methane
(short tons)
VOC
(short tons)
HAP
(short tons)
Methane
(metric tons CO2 Eq.)
2019
32,000
8,500
320
730,000
2020
39,000
10,000
390
890,000
2021
46,000
12,000
460
1,000,000
2022
54,000
14,000
530
1,200,000
2023
61,000
16,000
610
1,400,000
2024
69,000
18,000
690
1,600,000
2025
76,000
20,000
760
1,700,000
Total
380,000
100,000
3,800
8,500,000
2.3.5 Forgone Product Recovery
The estimated decrease in costs presented below include the forgone revenue from the
reductions in natural gas recovery under the co-proposed Option 3 compared to the 2016 NSPS
OOOOa. Fugitive emissions monitoring and repair is assumed to increase the capture of methane
and VOC emissions that would otherwise be vented to the atmosphere with no fugitive emissions
program, and we assume that a large proportion of the averted methane emissions can be directed
into natural gas production streams and sold. In the 2016 NSPS OOOOa, we based the estimated
revenues from those averted natural gas emissions on an estimate of the amount of natural gas
that would not be emitted during one year. In this analysis, we estimate the forgone revenue
associated with the decrease in natural gas recovery due to this proposed action. Reducing the
frequency of the survey and repair program leads to a reduction in the amount of natural gas that
is assumed to be captured and sold, leading to forgone revenue in Option 2 and the co-proposed
Option 3, as well as the alternative co-proposed option, as compared to the 2018 baseline.26
Table 2-4 summarizes the decrease in natural gas recovery and the associated forgone
revenue included in the cost savings calculations. When including the decrease in natural gas
26 The co-proposed option is also associated with forgone revenue associated with a decrease in natural gas recovery.
2-12
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recovery in the cost savings analysis, we use the projections of natural gas prices provided in the
EIA's 2018 AEO reference case. The AEO projects Henry Hub natural gas prices between $3.40
and $4.07 in $/MMBtu in 2017 dollars.27 We adjust those prices to be between $3.09 and $3.70
in $/Mcf (using the conversion of 1 MMBtu = 1.028 Mcf) in 2016 dollars (using the GDP-
Implicit Price Deflator) at the wellhead.28
Operators in the gathering and boosting, and transmission and storage parts of the
industry do not typically own the natural gas they transport; rather, the operators receive
payment for the transportation service they provide. As a result, the unit-level cost and emission
reduction analyses supporting best system of emission reduction (BSER) decisions presented in
Volume 1 of the TSD do not include estimates of revenue from natural gas recovery as offsets to
compliance costs. From a social perspective, however, the increased financial returns from
natural gas recovery accrues to entities somewhere along the natural gas supply chain and should
be accounted for in the national impacts analysis. An economic argument can be made that, in
the long run, no single entity is going to bear the entire burden of the compliance costs or fully
receive the financial gain of the additional revenues associated with natural gas recovery. The
change in economic surplus resulting from natural gas recovery is going to be spread out
amongst different agents via price mechanisms. Therefore, the simplest and most transparent
option for allocating these revenues would be to keep the compliance costs and associated
revenues together in a given source category and not add assumptions regarding the allocation of
these revenues across agents. This is the approach followed in Volume 2 of the TSD, as well as
in the 2016 NSPS RIA.
27 Available at: http://www.eia.gov/forecasts/aeo/tables_ref.cfm.
28 An EI A study indicated that the Henry Hub price is, on average, about 11 percent higher than the wellhead price.
See http://www.eia.gov/oiaf/analysispaper/henryhub/.
2-13
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Table 2-4 Estimated Decrease in Natural Gas Recovery (Mcf) for the Co-Proposed
Option 3 Compared to the 2018 Baseline (millions 2016$)
Year
Decrease in Gas Recovery
(Mcf)
Forgone
Revenue
2019
2020
2021
2022
2023
2024
1.85
2.3
2.7
3.1
3.5
4.0
4.4
$5.7
$7.6
$8.9
2025
$10
$12
$14
$16
2.3.6 Compliance Cost Savings
Table 2-5 summarizes the cost savings and foregone revenue from product recovery for
the evaluated emissions sources and points. What we call planning costs in this analysis are a
part of what were included in the capital cost estimates in the 2016 NSPS RIA, however, in this
RIA we assume there are no capital equipment purchases. Instead, the analogous costs in this
RIA include the cost of creating the survey monitoring plan for the fugitives monitoring
requirement and completing the required certifications. The annual operating and maintenance
cost savings are all attributed to the fugitives monitoring requirement, and include the cost of
performing the surveys, as well as the costs of performing repairs. The planning cost savings in
the table represents savings in the total planning cost expenditures associated with affected units,
including the change in planning cost expenditures made by sources affected prior to the analysis
year. The cost savings are estimated by multiplying the unit level cost savings from the updated
baseline associated with applicable control and facility type, as explained in section 2.3.2, by the
number of incrementally affected sources of that facility type. In addition, the cost savings from
the streamlining of recordkeeping and reporting are included in the annualized cost savings
totals.29 These cost savings are described more below.
29 See preamble section 60.5420a for details on the proposed amendments to the recordkeeping and reporting
requirements.
2-14
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Table 2-5 Compliance Cost Savings Estimates for Co-Proposed Option 3 Compared to
the 2018 Baseline (millions 2016$)
Compliance Cost Savings
Year
Planning Cost
Savings1
Operating and
Maintenance
Cost Savings
Annualized
Cost Savings
(w/o Forgone
Product
Revenue)2
Forgone
Revenue from
Product
Recovery
Nationwide
Annualized
Cost Savings
with Forgone
Revenue
2019
$2.9
$54
$58
$5.7
$52
2020
$3.1
$66
$69
$7.6
$62
2021
$3.1
$78
$82
$8.9
$73
2022
$3.2
$90
$94
$10
$84
2023
$3.7
$102
$107
$12
$94
2024
$3.5
$115
$119
$14
$105
2025
$3.7
$128
$132
$16
$116
1 The planning cost savings include the cost savings incurred by the newly affected sources for both fugitive
emissions monitoring and certifications in each year, as well as the cost savings of fugitive emissions sources that
renew survey monitoring plans after 8 years.
2 These cost savings include the planning cost savings for all fugitive emissions requirements annualized over 8
years at an interest rate of 7 percent, plus the annual operating and maintenance cost savings for the fugitive
emissions requirements every year, plus the cost savings of certifications in each year, plus the cost savings from
streamlined recordkeeping and reporting.
Sums may not total due to independent rounding.
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 does not change in this reconsideration. The reduction in planning costs in
each year outlined in Table 2-5 includes the estimated reduction in the costs of designing a
fugitive emissions monitoring program for the new reconsideration affected sources in that year,
plus the reduction in the cost of redesigning an existing program for sources that became affected
previously. The first year a redesign cost is included in the planning cost 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 savings of closed vent system and technical
infeasibility certifications in each year to get the total planning cost savings for each year.
The fugitive emissions monitoring program design cost savings annualized over the
expected lifetime of 8 years at an interest rate of 7 percent, is added to the annual cost savings of
implementing the fugitive emissions monitoring program, the cost savings of in house
certifications in each year, and the cost savings from streamlined recordkeeping and reporting to
get the annualized cost savings in each year compared to the 2018 baseline. The forgone value of
2-15
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product recovery is then added to estimate the total annualized cost savings in each year.
Table 2-6 illustrates the sensitivity of compliance cost and emissions analysis results of the
proposed Option 3 to choice of discount rate. We present costs using discount rates of 7 percent
and 3 percent based on the OMB Circular A-4.30 The table shows that the choice of discount rate
has minor effects on the nationwide annualized cost savings of the proposed rule.
Table 2-6 Estimated Cost Savings of the Co-Proposed Option 3, 2019-2025, using 3 and
7 Percent Discount Rates (millions 2016$)
7 Percent
3 Percent
Year
Annualized
Cost Savings
(without
Product
Recovery)
Forgone
Revenue from
Product
Recovery
Nationwide
Annualized Cost
Savings with
Product
Recovery
Annualized
Cost Savings
(without
Product
Recovery)
Forgone
Revenue
from Product
Recovery
Nationwide
Annualized
Cost Savings
with Product
Recovery
2019
$58
$5.7
$52
$58
$5.7
$52
2020
$69
$7.6
$62
$69
$7.6
$62
2021
$82
$8.9
$73
$82
$8.9
$73
2022
$94
$10
$84
$94
$10
$84
2023
$107
$12
$94
$107
$12
$94
2024
$119
$14
$105
$119
$14
$105
2025
$132
$16
$116
$132
$16
$116
The choice of discount rate has a very small effect on nationwide annualized cost
savings. Discount rate generally affects estimates of annualized costs for controls with high
planning or capital costs relative to annual costs. In this analysis, the planning cost savings
related to fugitive emissions surveys, plus the cost savings of closed vent system design and
technical infeasibility certifications, are small relative to the annual cost savings related to
fugitive emissions surveys, so the interest rate has little impact on annualized cost savings for
these sources.
Reporting and recordkeeping costs were drawn from the information collection
requirements (ICR) in this final rule that have been submitted for approval to the OMB under the
Paperwork Reduction Act (see Preamble for more detail). The reporting and recordkeeping cost
savings in this RIA are estimated to be constant at about $810,000 every year. These
recordkeeping and recordkeeping cost savings are estimated for the selected Option 3 for all new
30 Found at: https://obamawhitehouse.archives.gOv/omb/circulars_a004_a-4/#e
2-16
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and modified affected facilities regardless of whether they are in states with regulatory
requirements similar to the final 2016 NSPS OOOOa. While these cost savings may differ across
regulatory options as a result of the varying frequency of the fugitive emissions program across
the options, we do not have the information to estimate the ICR burden for the unselected Option
1 and 2. As a result, we assume all options have the same recordkeeping and reporting cost
burden. Note also that the total reporting and recordkeeping cost savings from streamlining the
requirements is mitigated by the estimated cost of reading the proposed rule.
2.3.7 Comparison of Regulatory Alternatives
Table 2-7 presents a comparison of the regulatory alternatives through each step of the
emissions analysis in 2020 and 2025. The options vary with respect to the fugitive emissions
requirements at well sites. The co-proposed Option 3 reduces monitoring at low production wells
to biennial (every other year), retains annual monitoring at well sites on the Alaskan North
Slope, and requires annual monitoring for all other affected, non-low production wells sites.
Monitoring frequency for compressor stations on the Alaskan North Slope is reduced to annual
monitoring, while compressor stations located elsewhere require semiannual fugitive emissions
monitoring.31 Option 3 results in greater increases in emissions and cost savings compared to the
presented alternative options. The most stringent option, Option 1, would finalize no changes in
the fugitive emissions requirements from the 2016 NSPS OOOOa requirements, but amends the
requirement for closed vent systems and pneumatic pump technical infeasibility to allow the use
of an in-house engineer. There are no changes in emissions compared to the 2018 baseline, and
the cost savings are smaller than under the both Option 2 and the co-proposed Option 3. We
assume biennial, annual, stepped, semiannual, and quarterly fugitive emissions surveys result in
reductions in emissions of 30 percent, 40 percent, 45 percent, 60 percent and 80 percent,
respectively.32Natural gas recovery also varies as a result of survey frequency. The different
survey frequencies, as shown in Table 2-1, also affect the count of reconsideration affected
31 See section VLB. 1 of the preamble, section 2 of the TSD and section 2.5.2 below for further discussion on choice
of fugitive emissions monitoring frequency, including the alternative co-proposed option of annual fugitive
emissions monitoring at compressor stations outside of the Alaskan North Slope.
32 For the Option 2, the fugitives monitoring survey frequency is stepped from semiannual for two years down to
annual thereafter. The emission reductions for the stepped option averages out to 45 percent per year over the
eight-year lifetime of the fugitive emissions monitoring plan. See the TSD for more details on this and the
estimate for emission reductions under a biennial fugitive monitoring survey frequency.
2-17
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sources, which leads to variations in the natural gas recovery, and therefore the value of natural
gas recovery, as well as planning and annualized costs.
Table 2-7 Comparison of Regulatory Alternatives to 2018 Baseline, 2020 and 2025
Regulatory Alternative
Option 1' Option 2
Total Impacts, 2020
Increase in Emissions
Methane Emissions (short tons/year)
VOC Emissions (short tons/year)
Decrease in Natural Gas Recovery (Mcf)
(millions)
Cost Savings
Planning Cost Savings
Annualized Cost Savings w/o Forgone
Revenue
Annualized Cost Savings with Forgone
Revenue
21,000
5,700
1.2
39,000
10,000
2.3
$2.7
$3.5
$3.5
$3.0
$38
$34
$3.1
$69
$62
Total Impacts, 2025
Increase in Emissions
Methane Emissions (short tons/year)
VOC Emissions (short tons/year)
Decrease in Natural Gas Recovery (Mcf)
(millions)
41,000
11,000
2.4
76,000
20,000
4.4
Cost Saving
Planning Cost Savings
Annualized Cost Savings w/o Forgone
Revenue
Annualized Cost Savings with Forgone
Revenue
$2.9
$3.7
$3.7
$3.5
$72
$64
$3.7
$132
$116
1 The small difference between the planning cost savings and the annualized cost savings values for option 1 are due
to the cost savings from proposed amendments to the recordkeeping and reporting requirements.
1 The cost savings and increase in emission of the co-proposed option can be found in section 2.5.2.
As can be seen in Table 2-7, the most stringent Option 1 results in the smallest decrease
in annualized costs ($3.5 million in 2020 and $3.7 million in 2025), as well as the smallest
increase in emissions (at 0 tons). Option 2 results in a decrease of about $34 million in
annualized costs in 2020 and $64 million in 2025, after accounting for the value of the decrease
in product recovery. Option 2 also results in an estimated increase of about 21,000 short tons per
year of methane emissions and 5,700 tons per year in VOC emissions in 2020, and 41,000 short
tons per year methane emissions and 11,000 tons per year in VOC emissions in 2025. The co-
proposed Option 3 results in the largest decrease in costs, as well as the largest increase in
emissions. Option 3 is associated with an estimated decrease of about $62 million in annualized
2-18
-------
costs in 2020 and $116 million in 2025, after accounting for the value of the decrease in product
recovery. Option 3 also results in an estimated increase of about 39,000 short tons per year
methane emissions and 10,000 tons per year in VOC emissions in 2020, and 76,000 short tons
per year methane emissions and 20,000 tons per year in VOC emissions in 2025.
2.4 Detailed Impacts Tables
The following tables show the full details of the cost savings and increase in emissions by
emissions sources for each regulatory option in 2020 and 2025.
2-19
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Table 2-8 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 1, 2020
Total Increase in Emissions
National Cost Savings
Source/Emissions Point
Projected No. of
Reconsideration
Affected
Sources
Methane
(short
tons)
voc
(short
tons)
HAP
(short
tons)
Methane
(metric
tons
C02e)
Planning
Cost
Savings
Operating
and
Maintenance
Total Annualized
Forgone Cost Savings
Product with Forgone
Recovery Revenues
Fugitive Emissions
Well sites
0
0
0
0
0
$0
$0
$0
$0
Gathering and Boosting Stations
0
0
0
0
0
$0
$0
$0
$0
Transmission Compressor
Stations
0
0
0
0
0
$0
$0
$0
$0
Certifications
CVS and Technical Infeasibility
Reporting and Recordkeeping
14,000
All
0
0
0
0
0
0
0
0
$2.7
$0
$0
$0
$0
$0
$2.7
$0.81
TOTAL
14,000
0
0
0
0
$2.7
$0
$0
$3.5
Table 2-9 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 1, 2025
Total Increase in Emissions
National Cost Savings
Source/Emissions Point
Projected No. of
Reconsideration
Affected
Sources
Methane
(short
tons)
voc
(short
tons)
HAP
(short
tons)
Methane
(metric
tons
C02e)
Planning
Cost
Savings
Operating
and
Maintenance
Forgone
Product
Recovery
Total
Annualized
Cost Savings
with Forgone
Revenues
Fugitive Emissions
Well sites
0
0
0
0
0
$0
$0
$0
$0
Gathering and Boosting Stations
0
0
0
0
0
$0
$0
$0
$0
Transmission Compressor
Stations
0
0
0
0
0
$0
$0
$0
$0
Certifications
CVS and Technical Infeasibility
Reporting and Recordkeeping
15,000
All
0
0
0
0
0
0
0
0
$2.9
$0
$0
$0
$0
$0
$2.9
$0.81
TOTAL
15,000
0
0
0
0
$2.9
$0
$0
$3.7
2-20
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Table 2-10 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 2, 2020
Total Increase in Emissions
National Cost Savings
Total
Projected No. of
Methane
Annualized
Reconsideration
Affected
Methane
(short
voc
(short
HAP
(short
(metric
tons
Planning
Cost
Operating
and
Forgone
Product
Cost Savings
with Forgone
Source/Emissions Point
Sources
tons)
tons)
tons)
C02e)
Savings
Maintenance
Recovery
Revenues
Fugitive Emissions
Well sites
42,000
21,000
5,700
220
470,000
$0.27
$34
$4.0
$30
Gathering and Boosting Stations
0
0
0
0
0
$0
$0
$0
$0
Transmission Compressor
Stations
0
0
0
0
0
$0
$0
$0
$0.0
Certifications
CVS and Technical Infeasibility
14,000
0
0
0
0
$2.7
$0
$0
$2.7
Reporting and Recordkeeping
All
0
0
0
0
$0
$0
$0
$0.81
TOTAL
56,000
21,000
5,700
220
470,000
$3.0
$34
$4.0
$34
Table 2-11 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 2, 2025
Total Increase in Emissions National Cost Savings
Total
Projected No. of
Methane
Annualized
Reconsideration
Affected
Methane
(short
VOC
(short
HAP
(short
(metric
tons
Planning
Cost
Operating
and
Forgone
Product
Cost Savings
with Forgone
Source/Emissions Point
Sources
tons)
tons)
tons)
C02e)
Savings
Maintenance
Recovery
Revenues
Fugitive Emissions
Well sites
84,000
41,000
11,000
430
930,000
$0.57
$68
$8.8
$63
Gathering and Boosting Stations
0
0
0
0
0
$0
$0
$0
$0
Transmission Compressor
Stations
0
0
0
0
0
$0
$0
$0
$0
Certifications
CVS and Technical Infeasibility
15,000
0
0
0
0
$2.9
$0
$0
$2.9
Reporting and Recordkeeping
All
0
0
0
0
$0
$0
$0
$0.81
TOTAL
99,000
41,000
11,000
430
930,000
$3.5
$68
$8.8
$64
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Table 2-12 Incrementally Affected Sources, Emissions Increases and Cost Savings, Co-Proposed Option 3, 2020
Total Increase in Emissions
National Cost Savings
Source/Emissions Point
Projected No. of
Reconsideration
Affected
Sources
Methane
(short
tons)
voc
(short
tons)
HAP
(short
tons)
Methane
(metric
tons
C02e)
Planning
Cost
Savings
Operating
and
Maintenance
Forgone
Product
Recovery
Total
Annualized
Cost Savings
with Forgone
Revenues
Fugitive Emissions
Well sites
42,000
28,000
7,800
290
640,000
$0.37
$47
$5.5
$42
Gathering and Boosting Stations
1,300
8,900
2,500
94
200,000
$0
$16
$1.7
$14
Transmission Compressor
Stations
230
2,100
58
1.7
47,000
$0
$2.9
$0.36
$2.5
Certifications
CVS and Technical Infeasibility
Reporting and Recordkeeping
14,000
All
0
0
0
0
0
0
0
0
$2.7
$0
$0
$0
$0
$0
$2.7
$0.81
TOTAL
58,000
39,000
10,000
390
890,000
$3.1
$66
$7.6
$62
Table 2-13 Incrementally Affected Sources, Emissions Increases and Cost Savings, Co-Proposed Option 3, 2025
Total Increase in Emissions National Cost Savings
Total
Projected No. of
Methane
Annualized
Reconsideration
Affected
Methane
(short
VOC
(short
HAP
(short
(metric
tons
Planning
Cost
Operating
and
Forgone
Product
Cost Savings
with Forgone
Source/Emissions Point
Sources
tons)
tons)
tons)
C02e)
Savings
Maintenance
Recovery
Revenues
Fugitive Emissions
Well sites
84,000
56,000
16,000
590
1,300,000
$0.78
$94
$12
$83
Gathering and Boosting Stations
2,300
16,000
4,600
170
370,000
$0
$29
$3.5
$25
Transmission Compressor
Stations
420
3,800
110
3.1
87,000
$0
$5.3
$0.73
$4.5
Certifications
CVS and Technical Infeasibility
15,000
0
0
0
0
$2.9
$0
$0
$2.9
Reporting and Recordkeeping
All
0
0
0
0
$0
$0
$0
$0.81
TOTAL
100,000
76,000
20,000
760
1,700,000
$3.7
$128
$16
$116
2-22
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2.5 Analysis of the Present Value of Cost Savings
This section presents the economic cost impacts of the proposed action in a present value
(PV) framework in compliance with E.O. 13771, Reducing Regulation and Controlling
Regulatory Costs. The proposed action, if finalized, would be considered a deregulatory action as
it has total costs that are less than zero. The stream of the estimated cost savings for each year
from 2019 through 2025 is discounted back to 2016 using both a 7 and 3 percent discount rate,
and summed to estimate the PV of the cost savings. This PV represents the sum of the total
annual cost savings over the 2019 to 2025-time horizon as a result of this proposed action. The
PV is then used to estimate the equivalent annualized value (EAV) of the cost savings. The EAV
is the annualized PV of the cost savings. In other words, the EAV takes the "lumpy" stream of
cost savings and converts them into a single annual value that, when added together, equals the
original stream of values in PV terms.
As above, all costs are cost savings, and are presented as the change in costs of the
analyzed option compared to the 2018 baseline, and are in 2016 dollars. Section 2.4 above
presents the annualized cost savings of the co-proposed Option 3, however the cost savings used
to estimate the PV are the un-annualized cost savings in each year. In the case of this analysis,
using the annualized values would return results very similar to using the unannualized values
because the portion of the total cost savings that is annualized (the planning cost savings) is very
small.
2.5.1 Present Value and Equivalent Annualized Value of the Cost Savings
For this RIA, EPA evaluates the change in costs for each year where reconsideration
affected sources are expected to change their compliance activities from the 2016 NSPS OOOOa
requirements as a result of this reconsideration, through 2025. In the case of this proposed action,
the change in compliance activities lead to cost savings. EPA has chosen not to evaluate impacts
beyond 2025 in part due to the limited information available to model long-term dynamics in
practices and equipment in the oil and gas industry. In addition, the oil and natural gas industry is
dynamic, and technological progress in control technology is likely to change significantly over a
longer time horizon.
Table 2-14 shows the stream of cost savings for each year from 2019 through 2025.
2-23
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Planning cost savings are estimated as the sum of the difference in costs of the design of fugitive
emissions monitoring plans for new reconsideration affected facilities, the difference in costs of
the redesign of fugitive emissions monitoring plans for reconsideration affected facilities that
were affected by the 2016 NSPS OOOOa at least 8 years prior, and the difference in costs of
certification for closed vent system design and pneumatic pump technical infeasibility for new
reconsideration affected sources compared to the updated baseline. Total cost savings are the
sum of the planning cost savings and annual operating cost savings. The forgone revenue from
the decrease in product recovery is estimated using the AEO 2018 projected natural gas price, as
described in section 2.4.4. Total cost savings with forgone revenue is the total cost savings minus
the forgone revenue. Over time, with the addition of new reconsideration affects sources, the
planning cost savings, annual operating cost savings and forgone revenue increase.
Table 2-14 Estimated Cost Savings for the Co-Proposed Option 3, 2019-2025 (millions
2016$)
Year
Planning Cost
Savings1
Operating
and
Maintenance
Cost Savings
Total Cost
Savings Without
Forgone
Revenue
Forgone
Revenue from
Product
Recovery
Total Cost
Savings with
Forgone
Revenue2
2019
$2.9
$54
$58
$5.7
$52
2020
$3.1
$66
$70
$7.6
$62
2021
$3.1
$78
$82
$8.9
$73
2022
$3.2
$90
$94
$10
$84
2023
$3.7
$102
$107
$12
$95
2024
$3.5
$115
$119
$14
$105
2025
$3.7
$128
$132
$16
$116
1 The planning cost savings include the cost savings incurred by the newly affected sources for both fugitive
emissions monitoring and certifications in each year, as well as the cost savings of fugitive emissions sources that
renew survey monitoring plans after 8 years.
2 Total cost savings include the planning cost savings for all fugitive emissions, plus the annual operating and
maintenance cost savings for the fugitive emissions requirements every year, plus the cost savings of certifications
in each year, plus the cost savings from streamlined recordkeeping and reporting.
Sums may not total due to independent rounding.
Table 2-15 shows the stream of cost savings discounted to 2016 using a 7 percent
discount rate. The table also shows the PV and the EAV of planning cost savings, annual
operating cost savings, forgone revenue from decreased product recovery and the total cost
savings (after accounting for the forgone product recovery). The PV of total cost savings is $380
million, and the EAV of total cost savings is about $66 million per year.
2-24
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Table 2-15 Discounted Cost Savings Estimates for Co-Proposed Option 3 Compared to
the 2018 Baseline Using a 7 Percent Discount Rate (millions 2016$)
Discounted Compliance Cost Savings
Year
Planning Cost
Savings1
Operating and
Maintenance
Cost Savings
Forgone
Revenue from
Product
Recovery
Total Cost
Savings with
Forgone
Revenue2
2019
$2.3
$44
$4.7
$42
2020
$2.3
$50
$5.8
$47
2021
$2.2
$55
$6.3
$52
2022
$2.1
$60
$6.9
$56
2023
$2.3
$64
$7.6
$59
2024
$2.1
$67
$8.2
$61
2025
$2.0
$69
$8.8
$63
PV
$15
$410
$48
$380
EAV
$2.7
$71
$8.4
$66
The cost savings in each year are discounted to 2016. Sums may not total due to independent rounding.
1 The planning cost savings include the cost savings incurred by the newly affected sources for both fugitive
emissions monitoring and certifications in each year, as well as the cost savings of fugitive emissions sources that
renew survey monitoring plans after 8 years discounted to 2016.
2 Total cost savings include the planning cost savings for all fugitive emissions, plus the annual operating and
maintenance cost savings for the fugitive emissions requirements every year, plus the cost savings of certifications
in each year, plus the cost savings from streamlined recordkeeping and reporting discounted to 2016.
Table 2-16 shows the discounted cost savings of the co-proposed Option 3, as well as the
two alternative options, over 2019 through 2025 compared to the 2018 baseline, along with the
PV and EAV of those cost savings, estimated using a 7 percent discount rate. Option 1 does not
affect the fugitive emissions monitoring requirements, and therefore product recovery is not
affected. Option 1 results in a savings of about $17 million in the PV, or $2.9 million per year in
the EAV. Option 2 results in a larger decrease: about $209 million in the PV of total cost
savings, after accounting for the forgone value of the decrease in product recovery, or about $36
million per year in the EAV. Option 3 leads to a PV of about $380 million in savings than the
2018 baseline, after accounting for the forgone value of the decrease in product recovery, or
about $66 million per year in the EAV.
2-25
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Table 2-16 Comparison of Regulatory Alternatives to 2018 Baseline Using a 7 Percent
Discount Rate
Regulatory Alternatives
Option 2 (Co°|i"„"«d)'
Present Value of Cost Savings
Compliance Cost Savings (millions 2016$)
Planning Cost Savings $13 $15 $15
Total Cost Savings w/o Forgone Revenue $17 $234 $429
Total Cost Savings with Forgone Revenue $T7 $209 $380
EAV of Cost Savings
Compliance Cost Savings (millions 2016$)
Planning Cost Savings $2.3 $2.6 $2.7
Total Cost Savings w/o Forgone Revenue $2.9 $41 $74
Total Cost Savings with Forgone Revenue $2.9 $36 $66
1 The alternative co-proposed option leads to larger cost savings, as can be seen in table 2-18.
Table 2-17 shows how the choice of discount rate affects the PV and EAV estimates. A
lower discount rate results in the higher cost savings in later years having a greater impact on the
PV and EAV than would results under a higher discount rate. Therefore, the PV and EAV for the
cost savings are higher when using a 3 percent discount rate than when using a 7 percent
discount rate. Using a 3 percent discount rate increases the PV of the cost savings by between 27
and 28 percent from the estimates using a 7 percent discount rate. For the EAV, using a 3 percent
discount rate increases the cost savings by between 14 and 15 percent from the estimates using a
7 percent discount rate.
2-26
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Table 2-17 Discounted Cost Savings for the Co-Proposed Option 3 using 7 and 3 Percent
Discount Rates Compared to the 2018 Baseline (millions 2016$)
7 Percent
3 Percent
Year
Total Annual
Cost Savings
(without
forgone
revenue)
Forgone
Revenue from
Product
Recovery
Total Cost
Savings (with
forgone
revenue)1
Total Annual
Cost Savings
(without
forgone
revenue)
Forgone
Revenue from
Product
Recovery
Total Cost
Savings (with
forgone
revenue)1
2019
$47
$4.7
$42
$53
$5.2
$48
2020
$53
$5.8
$47
$62
$6.7
$55
2021
$58
$6.3
$52
$70
$7.7
$63
2022
$63
$6.9
$56
$79
$8.7
$70
2023
$67
$7.6
$59
$87
$10
$77
2024
$69
$8.2
$61
$94
$11
$83
2025
$72
$8.8
$63
$101
$12
$89
PV
$429
$48
$380
$546
$62
$484
EAV
$74
$8.4
$66
$85
$9.6
$75
The cost savings in each year are discounted to 2016. Sums may not total due to independent rounding.
1 Total cost savings include the planning cost savings for all fugitive emissions, plus the annual operating and
maintenance cost savings for the fugitive emissions requirements every year, plus the cost savings of certifications
in each year, plus the cost savings from streamlined recordkeeping and reporting discounted to 2016.
2.5.2 Sensitivity of Cost Savings to Fugitive Emissions Monitoring Frequency at Compressor
Stations
The requirements under the co-proposed Option 3 were chosen individually and are based
on the information we have available. This analysis was performed for the 2016 OOOOa NSPS,
and revisited for this action. Section VI.B.l of the preamble and section 2 of the TSD contain
discussions of the different fugitive emissions monitoring frequencies, as well as a discussion of
why we are co-proposing to reduce fugitive emissions monitoring frequency at compressor
stations from quarterly to semiannual or annual. Section VI.B.l of the preamble also contains
solicitations for specific information we need in order to reevaluate monitoring frequencies
further.
In this section, we provide an analysis of the total cost savings of the action under
alternative monitoring frequencies for compressor stations, including the alternative co-proposed
annual monitoring frequency. Table 2-18 contains the PV and EAV of the total cost savings and
the total increase in emissions under each alternative frequency. All other aspects of the
requirements remain as outlined under the co-proposed Option 3. The cost savings and increase
in emissions are measured as changes from the 2018 baseline, and cost savings are discounted to
2-27
-------
2016 using a 7 percent discount rate, and are in millions of 2016$. The total emissions are the
sum of the increase in emissions from 2019 through 2025.
Table 2-18 Total Cost Savings and Increase in Emissions of the Co-Proposed Options
Under Alternative Monitoring Frequencies at Compressor Stations
Semiannual
Annual
Quarterly
(Co-Proposed
(Alternative Co-
Option)
Proposed Option)
Present Value
Total Cost Savings
$277
$380
$424
Cost Savings
$312
$429
$485
Forgone Value of Product Recovery
$35
$48
$61
Equivalent Annualized Cost
Total Cost Savings
$48
$66
$73
Cost Savings
$54
$74
$84
Forgone Value of Product Recovery
$6.1
$8.4
$11
Total Emissions Increase (2019 through 2025)
Methane (short tons)
270,000
380,000
480,000
VOC (short tons)
76,000
100,000
120,000
HAP (short tons)
2,900
3,800
4,700
Methane (million metric tons CO2 Eq.)
6.2
8.5
11
1 Total cost savings include the planning cost savings for all fugitive emissions, the annual operating and
maintenance cost savings for the fugitive emissions requirements every year, the cost savings of certifications in
each year, the cost savings from streamlined recordkeeping and reporting, and the forgone revenue from the
decrease in product recovery, discounted to 2016.
Totals may not sum due to independent rounding.
Table 2-18 presents a comparison of the co-proposed Option 3, which requires
semiannual monitoring at compressor stations, with the alternative co-proposed option, which
requires annual monitoring at compressor stations, and a third alternative that requires quarterly
monitoring at compressor stations, that vary only with respect to the frequency of the fugitive
emissions monitoring requirements for compressor stations. All other requirements are those of
the co-proposed Option 3, as shown in Table 2-1. The cost savings, forgone value of product
recovery, and total emissions decrease compared to the co-proposed Option 3 under quarterly
monitoring and increase under the alternative co-proposed option (annual monitoring).
Assuming a 7 percent discount rate, and including the forgone value of product recovery,
the present value of the total cost savings from 2019 through 2025 are about $43 million greater
under the co-proposed option assuming annual monitoring than under the co-proposed option
assuming semiannual monitoring. This is associated with an increase in the equivalent
annualized value of total cost savings of about $7.5 million per year in comparison to the co-
proposed option under semiannual monitoring.
2-28
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Decreasing fugitive emissions monitoring frequency at compressor stations from
semiannual to annual also results in a greater increase in total emissions. Over 2019 through
2025, the increase in fugitive emissions under the co-proposed option assuming annual
monitoring compared to the 2018 baseline are about 100,000 short tons greater for methane,
24,000 tons greater for VOC, and 890 tons greater for HAP than those under the co-proposed
option assuming semiannual fugitive emissions monitoring.
2-29
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3 ESTIMATED FORGONE BENEFITS
3.1 Introduction
The 2016 NSPS OOOOa regulated methane and VOC emissions in the oil and natural gas
sector. For the 2016 NSPS OOOOa, EPA predicted 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 emission reduction. These benefits were expected to occur
because the control techniques to meet the standards simultaneously reduce methane, VOC, and
HAP emissions.33 Under the updated assumptions and data as described above, the sources that
are affected by this reconsideration would have prevented an estimated 120,000 tons of methane,
and 32,000 tons of VOC from new sources in 2020 assuming no changes to the regulation. In
2025, the affected sources would have prevented an estimated 240,000 tons of methane and
62,000 tons of VOC. The estimated C02-equivalent (CO2 Eq.) methane emission reductions
would have been about 2.8 million metric tons in 2020 and 5.4 million metric tons in 2025. As
described in the subsequent sections of this chapter, these pollutants are associated with
substantial climate, health, and welfare effects.
As in the 2016 NSPS RIA, the only estimated forgone benefits monetized in this RIA are
methane-related climate impacts. The co-proposed Option 3 is estimated to increase emissions
compared to the 2018 baseline. The total increase in emissions over 2019 through 2025 is
estimated to be about 380,000 short tons of methane, 100,000 tons of VOC and 3,800 tons of
HAP. The associated increase in CO2 Eq. methane emissions is estimated to be 8.5 million
metric tons. The PV of the forgone methane-related climate benefits are estimated to be $14
million from 2019 through 2025 using an interim estimate of the domestic social cost of methane
(SC-CH4) discounting at a 7 percent rate. The associated EAV is estimated to be $2.3 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 $54 million; the EAV is estimated to be $8.3 million
per year.
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
proposed action is anticipated to reduce these minor secondary emissions.
3-1
-------
While we expect that the forgone VOC emission reductions may also degrade air quality
and adversely affect health and welfare effects associated with exposure to ozone, PM2.5, and
HAP, data limitations prevent us from quantifying forgone VOC-related health benefits. This
omission should not imply that these forgone benefits may not exist; rather, it reflects the
difficulties in modeling the direct and indirect impacts of the reductions in emissions for this
industrial sector with the data currently available.34 With these data currently unavailable, we are
unable to estimate forgone health benefits estimates for this rule due to the differences in the
locations of oil and natural gas emission points relative to existing information and the highly
localized nature of air quality responses associated with HAP and VOC reductions.35 In this
chapter, we qualitatively assess the forgone health benefits associated with reducing exposure to
these pollutants, as well as visibility impairment and forgone ecosystem benefits. Table 3-1
summarizes the quantified and unquantified forgone benefits in this analysis.
Table 3-1 Climate and Human Health Effects of Forgone Emission Reductions from
this Proposed Rule
Effect Has
Effect Has
More
Information
Category
Specific Effect
Been
Quantified
Been
Monetized
Improved Environment
Reduced climate
Climate impacts from methane (CH4) and
carbon dioxide (CO2)
1
~
Section 3.3
effects
Other climate impacts (e.g., ozone, black
IPCC, Ozone ISA,
carbon, aerosols, other impacts)
PM ISA2
Improved Human Health
Reduced 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
Reduced incidence of
morbidity from
exposure to PM2.5
Hospital admissions—respiratory (all ages)
—
—
PM ISA3
Hospital admissions—cardiovascular (age >20)
—
—
PM ISA3
Emergency room visits for asthma (all ages)
—
—
PM ISA3
34 EPA is working on improving available data and our understanding of the effects of VOC emission reductions in
the oil and natural gas sector.
35 Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the
effect those emissions have on ambient PM2 5 levels and the health effects associated with PM2 5 exposure (Fann,
Fulcher, and Hubbell, 2009). While these ranges of benefit-per-ton estimates provide useful context, the
geographic distribution of VOC emissions from the oil and natural gas sector are not consistent with emissions
modeled in Fann, Fulcher, and Hubbell (2009). In addition, the benefit-per-ton estimates for VOC emission
reductions in that study are derived from total VOC emissions across all sectors. Coupled with the larger
uncertainties about the relationship between VOC emissions and PM2 5 and the highly localized nature of air
quality responses associated with VOC reductions, these factors lead us to conclude that the available VOC
benefit-per-ton estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding
exercise.
3-2
-------
Category
Specific Effect
Effect Has
Been
Quantified
Effect Has
Been
Monetized
More
Information
Acute bronchitis (age 8-12)
—
—
PM ISA3
Lower respiratory symptoms (age 7-14)
—
—
PM ISA3
Upper respiratory symptoms (asthmatics age 9-
11)
—
—
PM ISA3
Asthma exacerbation (asthmatics age 6-18)
—
—
PM ISA3
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
Reduced 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
Hospital admissions—respiratory causes (age
<2)
—
—
Ozone ISA3
Emergency department visits for asthma (all
ages)
—
—
Ozone ISA3
Reduced incidence of
Minor restricted-activity days (age 18-65)
—
—
Ozone ISA3
morbidity from
exposure to ozone
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
Reduced incidence of
morbidity from
exposure to HAP
Effects associated with exposure to hazardous
air pollutants such as benzene
—
—
ATSDR, IRIS2'3
Improved Environment
Reduced visibility
Visibility in Class 1 areas
—
—
PM ISA3
impairment
Visibility in residential areas
—
—
PM ISA3
Reduced effects from
PM deposition
(organics)
Effects on Individual organisms and
ecosystems
—
—
PM ISA2
Visible foliar injury on vegetation
—
—
Ozone ISA3
Reduced vegetation
and ecosystem effects
from exposure to
ozone
Reduced vegetation growth and reproduction
—
—
Ozone ISA3
Yield and quality of commercial forest
products and crops
—
—
Ozone ISA3
Damage to urban ornamental plants
—
—
Ozone ISA2
3-3
-------
Category
Specific Effect
Effect Has
Been
Quantified
Effect Has
Been
Monetized
More
Information
Carbon sequestration in terrestrial ecosystems
—
—
Ozone ISA3
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 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.
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 with significant concentrations 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 country. Distribution lines to customers are frequently located within areas of high
population density.
Implementing this rule may result in forgone reductions in ambient PM2.5 and ozone
concentrations in areas attaining and not attaining the National Ambient Air Quality Standards
(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
36 The responsiveness of ozone and PM2 5 formation is discussed in greater detail in sections 3.4.1 and 3.5.1 of this
RIA.
3-4
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control strategies for different sources.37 By contrast, the emission reductions for implementation
rules, including this rule, are generally from a specific class of well-characterized sources. In
general, 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.
Table 3-2 shows the total increase in direct emissions, compared to the 2018 baseline,
anticipated for this proposed rule across the regulatory options examined for 2019 through 2025.
It is important to note that 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 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). Section 2.4.3 describes
the emission increases for the co-proposed Option 3 estimated in each year.
Table 3-2 Total Direct Increases in Emissions Compared to the 2018 Baseline across
Regulatory Options, 2019 through 2025
Pollutant
Option 1
Option 2
Option 3
(Co-Proposed)
Methane (short tons)
0
200,000
380,000
VOC (short tons)
0
56,000
100,000
HAP (short tons)
0
2,100
3,800
Methane (metric tons)
0
180,000
340,000
Methane (million metric tons CO2 Eq.)
0
4.5
8.5
Table 3-3 shows the methane, VOC and HAP emissions increases for Option 2 and
Option 3 for each year, compared to the 2018 baseline. Option 1 is not included in this table, as
there are no estimated changes in emissions under Option 1 (as seen in Table 3-2).
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 costs and benefits
estimated in this RIA may account for the same air quality improvements as estimated in an illustrative NAAQS
RIA.
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Table 3-3 Annual Direct Increases in Methane, VOC and HAP Emissions Compared to
the 2018 Baseline, Options 2 and 3, 2019 through 2025
Option 2
Option 3 (Co-Proposed)
Year
Methane VOC
(metric tons)
HAP
Methane
(metric tons)
VOC
HAP
2019
15,000
4,700
180
29,000
8,500
320
2020
19,000
5,700
220
35,000
10,000
390
2021
22,000
6,800
260
42,000
12,000
460
2022
26,000
7,900
300
49,000
14,000
530
2023
30,000
9,100
340
55,000
16,000
610
2024
33,000
10,000
380
62,000
18,000
690
2025
37,000
11,000
430
69,000
20,000
760
Total
180,000
56,000
2,100
340,000
100,000
3,800
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.
According to the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment
Report (AR5, 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 amounts of methane. The public Inventory
of U.S. Greenhouse Gas Emissions and Sinks: 1990-2014 (published 2016) estimates 2014
methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries
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and petroleum transportation) to be 232 MMt CO2 Eq. In 2014, total methane emissions from the
oil and natural gas industry represented 32 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, 2016c).
The 2016 NSPS OOOOa was expected to result in climate-related benefits by reducing
methane emissions. The proposed changes would therefore forgo climate-related benefits
associated with these emissions reductions as discussed above. To give a sense of the magnitude
of the emissions increases presented in Table 2-3, Table 3-2, and Table 3-3, the forgone methane
reductions estimated for 2020 (0.89 million metric tons CO2 Eq.) are equivalent to about 0.4
percent of the methane emissions for this sector reported in the U.S. GHGI for 2014 (about 232
million metric tons CO2 Eq. are from petroleum and natural gas production and gas processing,
transmission, and storage). Expected forgone emission reductions in 2025 (about 1.7 million
metric tons CO2 Eq.) are equivalent to around 0.7 percent of 2014 emissions. As it is expected
that emissions from this sector would increase over time, the estimates compared against the
2014 emissions would likely overestimate the percent of total emissions in 2020 and 2025.
We estimate the forgone climate benefits from the proposal 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 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
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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 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. EPA
follows this guidance below by presenting estimates based on both 3 and 7 percent discount rates
in the main analysis. See the Appendix for a discussion the modeling steps involved in
estimating the domestic SC-CH4 estimates based on these discount rates.
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 Medicine38
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
38 See National Academies of Sciences, Engineering, and Medicine, Valuing Climate Damages: Updating
Estimation of the Social Cost of Carbon Dioxide, Washington, D.C., January 2017.
http://www.nap.edu/catalog/24651/valuing-climate-changes-updating-estimation-of-the-social-cost-of
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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 3-4 presents the average domestic SC-CH4 estimates across all the model runs for
each discount rate for emissions occurring in 2019 to 2025. 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 as proportional to gross GDP.
Table 3-4 Interim Domestic Social Cost of CH4, 2019-2025 (in 2016$ per metric ton
CH4)*
Discount Rate and Statistic
Year
7% Average
3% Average
2019
$53
$170
2020
55
180
2021
58
180
2022
60
190
2023
63
190
2024
65
200
2025
68
200
* 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.
The SC-CH4 estimates in Table 3-4 are used to monetize the forgone domestic climate
benefits across regulatory options under consideration. Forecasted increases in methane
emissions in a given year, expected as a result of the regulatory action, are multiplied by the SC-
CH4 estimate for that year. Under the co-proposed Option 3, the forgone climate benefits vary by
discount rate and year, and range from about $1.6 million to approximately $4.7 million under a
7 percent discount rate, and from about $5 million to approximately $14 million under a 3
percent discount rate, as seen in Table 3-5.
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Table 3-5 Estimated Forgone Domestic Climate Benefits of the Co-Proposed Option 3,
2019-2025 (millions, 2016$)
Year
7 percent
3 Percent
2019
$1.6
$5.0
2020
$2.0
$6.2
2021
$2.4
$7.6
2022
$2.9
$9.1
2023
$3.5
$11
2024
$4.1
$12
2025
$4.7
$14
Table 3-6 shows the forgone domestic climate benefits in each year discounted to 2016
using a 3 or 7 percent discount rate. The table also shows the PV and the EAV for the 2019
through 2025-time horizon under each discount rate. The PV of forgone benefits under a 7
percent discount rate is about $14 million, with an EAV of about $2.3 million per year. The PV
of forgone benefits under a 3 percent discount rate of $54 million, with an EAV of about $8.3
million per year.
Table 3-6 Discounted Forgone Domestic Climate Benefits of the Co-Proposed Option 3,
PV and EAV (millions, 2016$)
Year
7 percent
3 Percent
2019
$1.3
$4.6
2020
$1.5
$5.5
2021
$1.7
$6.6
2022
$1.9
$7.6
2023
$2.2
$8.7
2024
$2.4
$9.7
2025
$2.5
$11
PV
$14
$54
EAV
$2.3
$8.3
The forgone domestic climate benefits in each year are discounted to 2016.
Table 3-7 shows the total increase in emissions over the 2019 through 2025-time horizon
as well as the PV and EAV of the forgone domestic climate benefits under 3 percent and 7
percent discount rates. This table shows how the different values of the climate benefits, as seen
in Table 3-4, affect the PV and EAV of each option. The affected sources in Option 1 are all
related to certification requirements, which do not affect emissions. The number of affected
sources under the co-proposed Option 3 is slightly larger than under Option 2, which leads the
increase in emissions, as well as the forgone benefits, to be slightly larger as well.
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Table 3-7 Estimated Forgone Domestic Climate Benefits Across the Regulatory
Options (millions, 2016$)
Option 1
Option 2
Option 3
(Co-Proposed)
Total Increase in Emission, 2019-2025
Forgone CH4 reductions (metric
tonnes)
Forgone CH4 reductions (million
metric tonnes of CO2 Eq.)
0
0
180,000
4.5
340,000
8.5
Forgone Domestic Climate Benefits (millions 2016$)
PV
3% (average)
$0
$28
$54
7% (average)
$0
$7.2
$14
EAV
3% (average)
$0
$4.4
$8.3
7% (average)
$0
$1.2
$2.3
The SC-CH4 values are dollar-year and emissions-year specific. SC-CH4 values represent only a partial accounting
of climate impacts.
The limitations and uncertainties associated with the global SC-CH4 estimates, which
were discussed in detail in the 2016 NSPS RIA, likewise apply to the forgone domestic SC-CH4
estimates presented in this analysis.39 Some uncertainties are captured within the analysis, as
discussed in detail in the Appendix, while other areas of uncertainty have not yet been quantified
in a way that can be modeled. For example, as with the methodology used to calculate SC-CO2
estimates, limitations include incomplete or inadequate representation in the integrated
assessment models of several important factors: catastrophic and non-catastrophic impacts,
adaptation and technological change, inter-regional and inter-sectoral linkages, uncertainty in the
extrapolation of damages to high temperatures, and the relationship between the discount rate
and uncertainty in economic growth over long time horizons. The science incorporated into these
models understandably lags behind the most recent research, and the limited amount of research
linking climate impacts to economic damages makes the modeling exercise even more difficult.
39 The SC-CH4 estimates presented in the 2016 NSPS RIA are the same as the SC-CH4 estimates presented inEPA-
HQ-OAR-2015-0827-5886, "Addendum to Technical Support Document on Social Cost of Carbon for
Regulatory Impact Analysis under Executive Order 12866: Application of the Methodology to Estimate the
Social Cost of Methane and the Social Cost of Nitrous Oxide (August 2016)", except the estimates in the 2016
NSPS RIA were adjusted to 2012$. The estimates published in the 2016 NSPS RIA were labeled as "Marten el
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.40 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, the Appendix 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,41 and recommended specific criteria for future updates to the SC-
40 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
41 National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages: Updating
Estimation of the Social Cost of Carbon Dioxide. National Academies Press. Washington, DC Available at
Accessed May 30, 2017.
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C02 estimates, a modeling framework to satisfy the specified criteria, and both near-term
updates and longer-term research needs pertaining to various components of the estimation
process (National Academies 2017). Since the framework used to estimate SC-CH4is 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, the Appendix presents the forgone global climate
benefits from the proposal using global SC-CH4 estimates based on both 3 and 7 percent
discount rates. Note that EPA did not quantitatively project the full impact of the 2016 NSPS
OOOOa on international trade and the location of production, so it is not possible to present
analogous estimates of global cost savings resulting from the proposed action. However, to the
extent that affected firms have some foreign ownership, some of the cost savings accruing to
entities outside U.S. borders is captured in the compliance cost savings presented in this RIA.
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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,
volatile organic compounds (VOC) and 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 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 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 modeling42.
42 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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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, 2010a).
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, EPA has generally quantified several health effects associated with
exposure to ozone (e.g., U.S. EPA, 2010a; U.S. EPA, 201 la). 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.
EPA has previously estimated the ozone-related benefits of reducing VOC emissions
from the industrial boiler sector (U.S. EPA, 201 lb)43 and in the RIA for the proposed Ozone
NAAQS (U.S. EPA, 2014b). 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.
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.
43 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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3.4.3 Ozone Climate Effects
Ozone is a well-known short-lived climate forcing greenhouse gas (GHG) (U.S. EPA,
2013). Stratospheric ozone (the upper ozone layer) is beneficial because it protects life on Earth
from the sun's harmful ultraviolet (UV) radiation. In contrast, tropospheric ozone (ozone in the
lower atmosphere) is a harmful air pollutant that adversely affects human health and the
environment and contributes significantly to regional and global climate change. Due to its short
atmospheric lifetime, tropospheric ozone concentrations exhibit large spatial and temporal
variability (U.S. EPA, 2009b). The IPCC AR5 estimated that the contribution to current warming
levels of increased tropospheric ozone concentrations resulting from human methane, NOx, and
VOC emissions was 0.5 W/m2, or about 30 percent as large a warming influence as elevated CO2
concentrations. This quantifiable influence of ground level ozone on climate leads to increases in
global surface temperature and changes in hydrological cycles.
3.5 VOC as a PM2.5 Precursor
This rulemaking may forgo emission reductions of VOC, which are a precursor to PM2.5,
thus possibly increasing human exposure to PM2.5 and the incidence of PIVh.s-related health
effects. 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. Given that a
fraction of secondarily formed organic carbon aerosols is from anthropogenic VOC emissions
and the extremely small amount of VOC emissions from this sector relative to the entire VOC
inventory, it is unlikely this sector has a large contribution to ambient secondary organic carbon
aerosols. Photochemical models typically estimate secondary organic carbon from anthropogenic
VOC emissions to be less than 0.1 |ig/m3. Therefore, we have not quantified the forgone PM2.5-
related benefits in this analysis.
Due to data limitations regarding potential locations of new and modified sources
affected by this rulemaking, we were unable to perform air quality modeling of the ambient
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PM2.5 impacts of the proposed rule, which is needed to quantify forgone PM2.5 benefits
associated with forgone VOC emission reductions for this rule.44 Due to the high degree of
variability in the responsiveness of PM2.5 formation to VOC emission reductions, we are unable
to estimate the effect that reducing VOC will have on ambient PM2.5 levels without air quality
modeling. However, we provide the discussion below for context regarding findings from
previous modeling.
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,
coughing, or difficulty breathing (U.S. EPA, 2009a). These health effects result in hospital and
ER visits, lost work days, and restricted activity days. When adequate data and resources are
available, EPA has quantified the health effects associated with exposure to PM2.5 (e.g., U.S.
EPA (201 lg).
When 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,
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.
Fann, Fulcher, and Hubbell (2009) examined how the monetized benefit-per-ton
estimates of reducing ambient PM2.5 varies by the location of the emission reduction, the type of
44 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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source emitting the precursor, and the specific precursor controlled. This study employed a
reduced-form air quality model to estimate changes in ambient PM2.5 from reducing 12 different
combinations of precursor emissions and emission sources, including reducing directly emitted
carbonaceous particles, nitrogen oxides, sulfur oxides, ammonia, and VOCs for nine urban areas
and nationwide. However, while these ranges of benefit-per-ton estimates provide general
context, the geographic distribution of VOC emissions from the oil and natural gas sector are not
consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition, the
benefit-per-ton estimates for VOC emission reductions in that study are derived from total VOC
emissions across all sectors. Coupled with the larger uncertainties about the relationship between
VOC emissions and PM2.5, these factors have lead EPA to conclude that the available VOC
benefit per ton estimates are not appropriate for use in monetizing the PM2.5 benefits of this rule,
even as a bounding exercise.
3.5.2 Organic PM Welfare Effects
According to the previous residual risk assessment that 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, 2012c).
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.
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, 2006b; U.S. EPA, 201 la; U.S. EPA, 201 lg; U.S. EPA, 2012c) 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 VOC emission would be likely to have a significant impact on visibility in
urban areas or Class I areas.
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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 2011 National-Scale Air Toxics Assessment (NATA) predicts that most Americans
are exposed to ambient concentrations of air toxics at levels that have the potential to cause
adverse health effects (U.S. EPA, 2015).45 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, EPA conducts the NATA.46 The most recent NATA was conducted for
calendar year 2011 and was released in December 2015. 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. utilizing dispersion
models;
3) Estimating population exposures across the U.S. utilizing exposure models; and
4) Characterizing potential public health risk due to inhalation of air toxics including both
cancer and noncancer effects.
Based on the 2011 NATA, EPA estimates that less than 1 percent of census tracts
nationwide have increased cancer risks greater than 100 in a million. The average national cancer
risk is about 40 in a million. Nationwide, the key pollutants that contribute most to the overall
cancer risks are formaldehyde and benzene.47 48 Secondary formation (e.g., formaldehyde
forming from other emitted pollutants) was the largest contributor to cancer risks, while
45 The 2011 NATA is available on the Internet at http://www.epa.gov/national-air-toxics-assessment/2011-national-
air-toxics-assessment.
46 The NATA modeling framework has a number of limitations that prevent its use as the sole basis for setting
regulatory standards. These limitations and uncertainties are discussed on the 2011 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. (2015) 2011 National-Scale Air
Toxics Assessment, .
47 Details onEPA's approach to characterization of cancer risks and uncertainties associated with the 2011 NATA
risk estimates can be found at .
48 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 .
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stationary, mobile, biogenics, and background sources contribute lesser amounts to the remaining
cancer risk.
Noncancer health effects can result from chronic,49 subchronic,50 or acute51 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 2011
NAT A, about 80 percent of the U.S. population was exposed to an average chronic concentration
of air toxics that has the potential for adverse noncancer respiratory health effects. Results from
the 2011 NATA indicate that acrolein is the primary driver for noncancer respiratory risk.
Figure 3-1 and Figure 3-2 depict the 2011 NATA estimated census tract-level
carcinogenic risk and noncancer respiratory hazard 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, acetaldehyde mass emissions were more than seventeen times acrolein
mass emissions on a national basis in EPA's 2011 National Emissions Inventory (NEI).
However, the Integrated Risk Information System (IRIS) reference concentration (RfC) for
acrolein is considerably lower than that for acetaldehyde. This results in 2011 NATA estimates
of nationwide chronic respiratory noncancer risks from acrolein being over three times that of
acetaldehyde.52 Thus, it is important to account for the toxicity and exposure, as well as the mass
of the targeted emissions.
49 Chronic exposure is defined in the glossary of the Integrated Risk Information System (IRIS) database
() 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).
50 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).
51 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.
52 Details on the derivation of IRIS values and available supporting documentation for individual chemicals (as well
as chemical values comparisons) can be found at .
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Total Cancer Risk
(In a million)
0-25
25-50
Zero Population Tracts
Figure 3-1 2011 NATA Model Estimated Census Tract Carcinogenic Risk from HAP
Exposure from All Outdoor Sources based on the 2011 National Emissions Inventory
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Respiratory HI
AK
PR and VI
Zero Population Tracts
Figure 3-2 2011 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk
from HAP Exposure from All Outdoor Sources based on the 2011 National Emissions
Inventory
Due to methodology and data limitations, we were unable to estimate the forgone benefits
associated with the hazardous air pollutant emissions that would be forgone as a result of this
rule. In a few previous analyses of the benefits of reductions in HAP, 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, EPA relied on unit risk factors (URF) and reference concentrations
(RfC) developed through risk assessment procedures. The URF 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 jjigfei3 of a pollutant. These
URF-'s are designed to be conservative, and as such, are more likely to represent the high end of
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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 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 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, 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), 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, 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 2009, EPA convened a workshop to address the inherent complexities, limitations, and
uncertainties in current methods to quantify the benefits of reducing HAP. Recommendations
from this workshop included identifying research priorities, focusing on susceptible and
vulnerable populations, and improving dose-response relationships (Gwinn et al., 2011).
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. EPA remains committed to improving methods for estimating HAP benefits by
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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, ethyl benzene,
mixed xylenes, and n-hexane. This rule is anticipated to result an increase of a total of 3,800 tons
of HAP emissions over 2019 through 2025. With the data available, it was not possible to
estimate the change in emissions of each individual HAP.
3.6.1 Benzene
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.53'54'55 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
53 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene.
Research and Development, National Center for Environmental Assessment, Washington, DC. This material is
available electronically at: .
54 International Agency for Research on Cancer, IARC monographs on the evaluation of carcinogenic risk of
chemicals to humans, Volume 29, Some industrial chemicals and dyestuffs, International Agency for Research
on Cancer, World Health Organization, Lyon, France, p. 345-389, 1982.
55 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, V.A. (1992) Synergistic action of the benzene metabolite
hydroquinone on myelopoietic stimulating activity of granulocyte/macrophage colony-stimulating factor in vitro,
Proc. Natl. Acad. Sci. 89:3691-3695.
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Services has characterized benzene as a known human carcinogen.56'57 A number of adverse
noncancer health effects including blood disorders, such as preleukemia and aplastic anemia,
have also been associated with long-term exposure to benzene.58 59
3.6.2 Toluene60
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 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
56 International Agency for Research on Cancer (IARC). 1987. Monographs on the evaluation of carcinogenic risk
of chemicals to humans, Volume 29, Supplement 7, Some industrial chemicals and dyestuffs, World Health
Organization, Lyon, France.
57 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens
available at: .
58 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197.
59 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541-554.
60 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 on the Internet at .
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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.
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.61 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.62
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
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
61 Hazardous Substances Data Bank (HSDB), online database. US National Library of Medicine, Toxicology Data
Network, available online at http://toxnet.nlm.nih.gov/. Carbonyl health effects summary available at
.
62 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 .
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cavities in male and female rats exposed to ethylbenzene via the oral route.63'64 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).65'66 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.
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.67 Other reported effects include labored
breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and
kidneys.68 Long-term inhalation exposure to xylenes in humans has been associated with a
63 Maltoni C, Conti B, Giuliano C and Belpoggi F, 1985. Experimental studies on benzene carcinogenicity at the
Bologna Institute of Oncology: Current results and ongoing research. Am J Ind Med 7:415-446.
64 Maltoni C, Ciliberti A, Pinto C, Soffritti M, Belpoggi F and Menarini L, 1997. Results of long-term experimental
carcinogenicity studies of the effects of gasoline, correlated fuels, and major gasoline aromatics on rats. Annals
NY AcadSci 837:15-52.
65 International Agency for Research on Cancer (IARC), 2000. Monographs on the Evaluation of Carcinogenic
Risks to Humans. Some Industrial Chemicals. Vol. 77, p. 227-266. IARC, Lyon, France.
66 National Toxicology Program (NTP), 1999. Toxicology and Carcinogenesis Studies of Ethylbenzene (CAS No.
100-41-4) inF344/N Rats and inB6C3Fl Mice (Inhalation Studies). Technical Report Series No. 466. NIH
Publication No. 99-3956. U.S. Department of Health and Human Services, Public Health Service, National
Institutes of Health. NTP, Research Triangle Park, NC.
67 U.S. Environmental Protection Agency (U.S. EPA). 2003. Integrated Risk Information System File for Mixed
Xylenes. Research and Development, National Center for Environmental Assessment, Washington, DC. This
material is available electronically at .
68 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is
available electronically at .
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number of effects in the nervous system including headaches, dizziness, fatigue, tremors, and
impaired motor coordination.69 EPA has classified mixed xylenes in Category D, not classifiable
with respect to human carcinogenicity.
3.6.6 tt-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 EPA has
classified hexane in Group D, not classifiable as to human carcinogenicity.70
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 EPA's IRIS database.71
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(WMO). 2011. An Integrated Assessment of Black Carbon and Tropospheric Ozone,
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. Accessed April 6,
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Clean Air Benefits: Actions for Controlling Short-Lived Climate Forcers. United Nations
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Petroleum Refinery NESHAP. Revised Draft for Promulgation. Office of Air Quality
Planning and Standards, Research Triangle Park, N.C.
. Accessed March 30, 2015.
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Quality Planning and Standards, Research Triangle Park, NC.
. Accessed March
30, 2015.
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Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for
Environmental Assessment—RTP Division.
. Accessed March 30,
2015.
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Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under
Section 202(a) of the Clean Air Act.
. Accessed March 30, 2015.
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U.S. Environmental Protection Agency (U.S. EPA). 2011b. Regulatory Impact Analysis:
National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial,
and Institutional Boilers and Process Heaters. Office of Air Quality Planning and
Standards, Research Triangle Park, NC. February.
. Accessed
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and Gas Production and Natural Gas Transmission and Storage Source Categories.
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Proposed Ozone NAAQS. U.S. Environmental Protection Agency, Research Triangle
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4 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS
4.1 Introduction
This section includes four sets of discussion for the proposed reconsideration: energy
markets impacts, distributional impacts, small business impacts, and employment impacts.
4.2 Energy Markets Impacts
As it is implemented, the 2016 NSPS OOOOa may have impacts on energy production
and markets which would be reduced under the proposed reconsideration. The 2016 NSPS RIA
used the National Energy Modeling System (NEMS) to estimate the impacts to drilling activity,
price, and 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.72 In that analysis, 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 proposed reconsideration includes proposing to
reduce the stringency of the requirements on a substantial portion of the sources included in the
2016 NSPS OOOOa. The co-proposed Option 3 is expected to lead to total cost savings
compared to the 2018 baseline. Relative to the baseline, the EAV of cost savings over the 2019-
72 See Section 6.2 of the 2016 NSPS RIA
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25 timeframe is about $74 million per year without including the forgone value of product
recovery (about $8.4 million per year), or $66 million less per year when the forgone value of
product recovery is included. As a result, EPA expects that this deregulatory action, if finalized,
would partially ameliorate the impacts estimated for the final NSPS in the 2016 NSPS RIA.
4.3 Distributional Impacts
The compliance cost savings and forgone benefits presented above are not expected to be
felt uniformly across the population, and may not accrue to the same individuals or communities.
OMB recommends including a description of distributional effects, as part of a regulatory
analysis, "so that decision makers can properly consider them along with the effects on economic
efficiency [i.e., net benefits]. Executive Order 12866 authorizes this approach." (U.S. Office of
Management and Budget 2003). Understanding the distribution of the compliance cost savings
and forgone benefits can aid in understanding community-level impacts associated with this
action.73 This section discusses the general expectations regarding how compliance cost savings
and forgone health benefits might be distributed across the population, relying on a review of
recent literature. EPA did not conduct a quantitative assessment of these distributional impacts
for the proposed reconsideration, but the qualitative discussion in this section provides a general
overview of the types of impacts that could result from this action.
4.3.1 Distributional Aspects of Compliance Cost Savings
The compliance costs associated with an environmental action can impact households by
raising the prices of goods and services; the extent of the price increase depends on if and how
producers pass-through those costs to consumers. The literature evaluates the distributional
effects of introducing a new regulation; as the literature relates to the proposed reconsideration,
which is deregulatory, these effects can 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
73 Executive Order 12898, Federal Actions to Address Environmental Justice in Minority Populations and Low-
Income Populations, directs agencies to address impacts on minority and low-income populations, particularly
those that may be considered disproportionate. EPA developed guidance, both in its Guidelines for Preparing
Economic Analyses (U.S. EPA 2010) and Technical Guidance for Assessing Environmental Justice in Regulatory
Analyses (U.S. EPA 2016) to provide recommendations for how to consider distributional impacts of rules on
vulnerable populations.
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to be regressive, placing a greater burden on lower income households (e.g., Burtraw et al., 2009;
Hassett et al., 2009; Williams et al. 2015). However, compliance costs will not be solely passed
on in the form of higher energy prices, but also through lower labor earnings and returns to
capital in the sector. Changes in employment associated with lower labor earnings can have
distributional consequences depending on a number of factors (Section 6.5 discusses
employment effects further). Capital income tends to make up a greater proportion of overall
income for high income households. As result, the costs passed through to households via lower
returns to capital tend to be progressive, placing a greater share of the burden on higher income
households in these instances (Rausch et al., 2011; Fullerton et al., 2011).
The ultimate distributional outcome 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 literature using an economy-wide framework finds 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 households74 (Fullerton et al., 2011; Blonz et al.,
2012). 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., 2017). Different
classifications of households, such as on the basis of lifetime income rather than
contemporaneous annual income, may provide notably different results (Fullerton and Metcalf,
2002; Fullerton et al., 2011). Furthermore, there may be important regional differences in the
incidence of regulations. There are differences in the composition of goods consumed, regional
production methods, 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).
74 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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4.3.2 Distributional Aspects of the Forgone Health Benefits
This section discusses the distribution of forgone health benefits that result from the
proposed reconsideration. EPA guidance directs analysts to first consider the distribution of
impacts in the baseline, prior to any regulatory action (see U.S. EPA 2016). Often the baseline
incidence of health outcomes is greater among low-income or minority populations due to a
variety of factors, including a greater number of pollution sources located where low-income and
minority populations live, work and play (Bullard, et al. 2007; United Church of Christ 1987);
greater susceptibility to a given exposure due to physiology or other triggers (Akinbami 2012);
and pre-existing conditions (Schwartz et al 2011). EPA (2016) then recommends analysts
examine the distribution of health outcomes under the policy scenarios being considered. Finally,
this can be followed by an examination of the change between the baseline and policy scenario,
taking note of whether the action ameliorates or exacerbates any pre-existing disparities.
Because the manner in which the health benefits of a rulemaking are distributed is based
on the correlation of housing and work locations to changes in atmospheric concentrations of
pollutants, it is difficult to fully know the distributional impacts of a rule. Air dispersion models
provide some information on changes in pollution, 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 any households change their housing location choice in response to air quality
changes (Sieg et al., 2004).
4.4 Small Business Impacts
The Regulatory Flexibility Act (REA; 5 U.S.C. §601 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. §605[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
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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 the small entities subject to the rule. As described in
Section 2 of this RIA, this proposed reconsideration includes proposing to reduce the stringency
of the requirements on a substantial portion of the sources included in the 2016 NSPS OOOOa.
In addition, the three options being analyzed in this RIA would result in neutral or beneficial
effects on the affected facilities, including small businesses. Where changes to the regulation are
being proposed, they decrease burden to the industry through direct changes in the requirements
(for example, reducing fugitive monitoring frequency at well sites and compressor stations, and
excluding well sites without major production and processing equipment from fugitive emissions
monitoring), increased clarity of requirements (for example, through more robust definitions),
updating of the alternative means of limitation (for example specifying specific state level
provisions as equivalent to the provisions being proposed in this reconsideration), and the
streamlining of recordkeeping and reporting requirements. Relative to the baseline, the reduction
in EAV of costs over the 2019-25 timeframe is about $74 million per year without including the
forgone value of product recovery (about $8.4 million per year), or $66 million less per year
when the forgone value of product recovery is included. As a result, EPA expects that this
deregulatory action, if finalized as proposed, would lessen the impacts estimated for the final
NSPS in the 2016 NSPS RIA. We have therefore concluded that this action will relieve
regulatory burden for all directly regulated small entities.
4.5 Employment Impacts
In this section, EPA presents a qualitative discussion of the impacts of this rulemaking on
employment.75 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
75 The employment analysis in this RIA is part of EPA's ongoing effort to "conduct continuing evaluations of
potential loss or shifts of employment which may result from the administration or enforcement of [the Act]"
pursuant to CAA section 321(a).
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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 they are
mitigated by 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 distributional impacts of
interest to policy makers. Transitional job losses experienced by workers operating in declining
industries, exhibiting low migration rates, or living in communities or regions where
unemployment rates are high are of particular concern.
A discussion of partial employment impacts for affected entities in the oil and gas
industry was completed in the 2016 NSPS RIA using detailed engineering information on labor
requirements for each of the control strategies identified in the rule.76 These bottom-up,
engineering-based estimates represented only one portion of potential employment impacts
within the regulated industry, and did not represent estimates of the net employment impacts of
the rule. Labor changes may be required as part of an initial effort to comply with a regulation or
required as a continuous or annual effort to maintain compliance. In the 2016 analysis, EPA
estimated up-front and continual annual labor requirements by estimating hours of labor required
and converting this number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per
week multiplied by 52 weeks). Overall, the 2016 NSPS OOOOa estimated the one-time labor
requirement for the affected sector to be about 270 FTEs in 2020 and 2025, and the annual labor
requirement was estimated to be about 1,100 FTEs in 2020 and 1,800 FTEs in 2025. Due to data
and methodology limitations, other potential employment impacts in the affected industry and
impacts in related industries were not estimated.
As the proposed reconsideration is likely to cause little change in oil and natural gas
76 EPA did not estimate the labor required to perform the professional engineer certification requirements in the
2016 NSPS OOOOa.
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exploration and production, and many aspects of the 2016 NSPS OOOOa requirements are not
affected by the proposed reconsideration, demand for labor employed in exploration and
production and associated industries is unlikely to change greatly. For the affected oil and natural
gas entities, some reductions in labor from 2016 NSPS OOOOa related requirements may be
expected under the proposed reconsideration. For the proposed reconsideration, EPA expects
there will be slight reductions in the labor required for compliance-related activities associated
with the 2016 NSPS OOOOa requirements relating to fugitive emissions and inspections of
closed vent systems. However, due to uncertainties associated with how the proposed
reconsideration will influence the portfolio of activities associated with fugitive emissions-
related requirements, EPA is unable to provide quantitative estimates of compliance-related labor
changes. EPA continues to explore the relevant theoretical and empirical literature and to seek
public comments in order to ensure that the way EPA characterizes the employment effects of its
regulations is valid and informative.
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5 COMPARISON OF BENEFITS AND COSTS
5.1 Comparison of Benefits and Costs Across Regulatory Options
In this section, we present a comparison of the benefits and costs of this regulation. To be
more consistent with traditional net benefits analysis, we modify the relevant terminology in the
following tables, which present the costs, benefits and net benefits for this proposed action across
regulatory options. In this section, we refer to the cost savings as presented in section 2 as the
"benefits" of this proposed action and the forgone benefits as presented in section 3 as the
"costs" of this proposed action. The net benefits are the benefits (cost savings) minus the costs
(forgone benefits). As explained in the previous sections, all costs and benefits outlined in this
RIA are estimated as the change from the updated baseline.
All benefits, costs, and net benefits shown in this section are presented as the PV of the
costs and benefits of each option from 2019 through 2025 discounted back to 2016 under both a
7 percent and a 3 percent discount rate, and their associated EAV.
Table 5-1 shows the estimated benefits, costs and net benefits for Option 1, the most
stringent option. Option 1 is associated with a decrease in costs due to in-house certifications
compared to all certifications being performed by a professional engineer. There are no forgone
benefits associated with this action. Therefore, the net benefits stem entirely from the cost
savings (or benefits as presented in the table). The net benefits from this option are the smallest
compared to Options 2 and 3.
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Table 5-1 Summary of the Present Value (PV) and Equivalent Annualized Value
(EAV) of Forgone Monetized Benefits, Cost Savings, and Net Benefits for Option 1 from
2019 through 2025 (millions, 2016$)
7%
3%
PV
EAV
PV
EAV
Benefits (Total Cost Savings)
$17
$2.9
$21
$3.3
Cost Savings
$17
$2.9
$21
$3.3
Forgone Value of Product Recovery
$0
$0
$0
$0
Costs (Forgone Domestic Climate Benefits)1
$0
$0
$0
$0
Net Benefits2
$17
$2.9
$21
$3.3
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-
CH4). SC-CH4 values represent only a partial accounting of domestic climate impacts from
methane emissions. This option is unlikely to affect emissions, therefore there are no monetized
forgone benefits as a result of this option.
2 Estimates may not sum due to independent rounding.
Table 5-2 shows the estimated benefits, costs and net benefits for Option 2. Option 2
results in net benefits greater than those of Option 1, but less than those of Option 3. In this
option, we estimate the impact of in-house certifications, a step down in the fugitives monitoring
frequency for all non-low production well sites to annual after two years, and an immediate
reduction in monitoring frequency to annual for all low production well sites and all compressor
stations on the Alaskan North Slope. The benefits (cost savings) are moderated by a decrease in
the value of product recovery producers would have received under the 2016 NSPS OOOOa.
Table 5-2 Summary of the Present Value (PV) and Equivalent Annualized Value
(EAV) of Forgone Monetized Benefits, Cost Savings, and Net Benefits for Option 2 from
2019 through 2025 (millions, 2016$)
7%
PV
EAV
PV
3%
EAV
Benefits (Total Cost Savings)
$209
$36
$265
$41
Cost Savings
$234
$41
$299
$47
Forgone Value of Product Recovery
$26
$4.5
$33
$5.2
Costs (Forgone Domestic Climate Benefits)1
$7.2
$1.2
$28
$4.4
Net Benefits2
$201
$35
$237
$37
11 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
values represent only a partial accounting of domestic climate impacts from methane emissions. See Section 3.3
for more discussion.
2 Estimates may not sum due to independent rounding.
Table 5-3 shows the estimated benefits, costs and net benefits for Option 3. Option 3
results in the greatest cost savings, forgone benefits, and net benefits of the three options
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analyzed. Under Option 3, fugitive emissions monitoring frequency is annual at non-low
production well sites not on the Alaskan North Slope, biennial at all low production well sites
not on the Alaskan North Slope, and annual at all well sites and compressor stations on the
Alaskan North slope. Fugitive emissions monitoring frequency at compressor stations not on the
Alaskan North Slope is reduced from quarterly to semiannual.
Table 5-3 Summary of the Present Value (PV) and Equivalent Annualized Value
(EAV) of Forgone Monetized Benefits, Cost Savings, and Net Benefits for the Co-Proposed
Option 3 from 2019 through 2025 (millions, 2016$)
7%
PV
EAV
PV
3%
EAV
Benefits (Total Cost Savings)
$380
$66
$484
$75
Cost Savings
$429
$74
$546
$85
Forgone Value of Product Recovery
$48
$8.4
$62
$9.6
Costs (Forgone Domestic Climate Benefits)1
$13.5
$2.3
$54
$8.3
Net Benefits2
$367
$64
$431
$67
11 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 3.3
for more discussion.
2 Estimates may not sum due to independent rounding.
Table 5-4 provides a summary of the direct increase in emissions for each regulatory
option. As explained in section 3, there are no changes in emissions estimated as a result of
Option 1. Option 2 results in an increase in emissions compared to both option 1, and the
updated baseline. Option 3 results in the greatest increase in emissions compared to the baseline.
Table 5-4 Summary of Total Emissions Increases across Options, 2019 through 2025
Pollutant
Option 1
Option 2
Option 3
(Co-Proposed)
Methane (short tons)
0
200,000
380,000
VOC (short tons)
0
56,000
100,000
HAP (short tons)
0
2,100
3,800
Methane (metric tons)
0
180,000
340,000
Methane (million metric tons CO2 Eq.)
0
4.5
8.5
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5.2 Uncertainties and Limitations
Throughout the RIA, we considered a number of sources of uncertainty, both
quantitatively and qualitatively, regarding emissions increases, forgone benefits, and cost savings
of the proposed rule. We summarize the key elements of our discussions of uncertainty here:
• Projection methods and assumptions: As discussed in Section 2.4.2, 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 total number of facilities subject to the NSPS
accumulates. The impacts of this rule are based on projections and growth rates
consistent with the drilling activity in the 2018 Annual Energy Outlook. To the extent
actual drilling activities diverge from the Annual Energy Outlook projections, the
projected regulatory impacts estimated in this document will diverge. In addition, we
assume one hundred percent compliance with the rule, starting from when the source
becomes affected. If sources are not complying with the rule, at all or as written, the cost
savings may be overestimated.
• Years of analysis: The years of analysis are 2019, to represent the first-year facilities are
affected by this reconsideration, through 2025, to represent impacts of the rule over a
longer period, as discussed in Section 2.4.2. While it is desirable to analyze impacts
beyond 2025, in this RIA 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 2025 would introduce substantial and increasing uncertainties in
projected impacts of the proposed regulation.
• State regulations in baseline: In preparing the impacts analysis, EPA reviewed state
regulations and permitting requirements, as discussed in Section 2.4.2. Applicable
facilities in states with similar requirements to the proposed reconsideration are not
included in the estimates of incrementally affected facilities presented in the RIA. This
means that any additional costs and benefits incurred by facilities in these states to
comply with the federal standards beyond the state requirements are not reflected in this
RIA.
• Wellhead natural gas prices used to estimate forgone revenues from natural gas
recovery: The compliance cost savings estimates presented in this RIA include the
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forgone revenue associated with the decrease in natural gas recovery resulting from the
decrease in emissions reductions. As a result, the national compliance cost savings
depends on the price of natural gas. Natural gas prices used in this analysis are from the
projection of the Henry Hub price in the 2018 AEO. To the extent actual natural gas
prices diverge from the AEO projections, the projected regulatory impacts estimated in
this document will diverge.
• Monetized forgone methane-related climate benefits: 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 reconsideration. Some uncertainties are captured within the
analysis, while other areas of uncertainty have not yet been quantified in a way that can
be modeled. Chapter 3 and the accompanying Appendix 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.
• Non-monetized forgone benefits: Numerous categories of forgone health, welfare, and
climate benefits are not quantified and monetized in this RIA. These unquantified
forgone benefits, including forgone benefits from increases in emissions of methane,
VOCs and HAP, are described in detail in Chapter 3.
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A. APPENDIX: UNCERTAINTY ASSOCIATED WITH ESTIMATING THE
SOCIAL COST OF METHANE
A.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 2009.77 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.78 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. borders79—is calculated directly in both FUND and PAGE.
However, DICE 2010 generates only global estimates. Therefore, 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).80
Although the regional shares reported in Nordhaus (2017) are specific to SC-CO2, they still
77 The full models names are as follows: Dynamic Integrated Climate and Economy (DICE); Climate Framework for
Uncertainty, Negotiation, and Distribution (FUND); and Policy Analysis of the Greenhouse Gas Effect (PAGE).
78 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.
79 Note that inside the U.S. borders is not the same as accruing to U.S. citizens, which may be higher or lower.
80 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 similar to that of 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 t
based on a Monte Carlo simulation of 10,000 runs. For each of the IAMs, the basic
computational steps for calculating the social cost estimate in a particular year t 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, 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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A.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).81 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 of 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.
Monte Carlo techniques were used to run the IAMs a large number of times. In each
simulation the uncertain parameters are represented by random draws from their defined
81 Institute of Medicine of the National Academies. 2013. Environmental Decisions in the Face of Uncertainty. The
National Academies Press.
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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.82 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 a
given 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 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
82 Specifically, the Roe and Baker distribution for the climate sensitivity parameter was bounded between 0 and 10
with a median of 3 °C and a cumulative probability between 2 and 4.5 °C of two-thirds.
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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 1 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.83 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.
83 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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Interim U.S. Domestic Social Cost of Methane in 2020 [2016$ / metric ton CH4]
Figure 1. Frequency Distribution of Interim Domestic SC-CILt Estimates for 2020 (in
2016$ per metric ton CELt)
As illustrated by the frequency distributions in Figure 1, 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,84 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 assumptions85, 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
84 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)".
85 "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 2019 is $220 per metric ton of CH4 (2016$)86; in this case the forgone domestic
climate benefits of the co-proposed Option 3 are $6.3 million in 2019 under a 2.5 percent
discount rate. By 2025, the average domestic SC-CH4 using a 2.5 percent discount rate is $250
per metric ton of CH4 (2016$), and the corresponding forgone domestic climate benefits of the
proposed action increase to $18 million. The PV of the forgone domestic climate benefits under a
2.5 percent discount rate is $69 million, with a corresponding EAV of $11 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 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
86 The estimates are adjusted for inflation using the GDP implicit price deflator and then rounded to two significant
digits.
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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.
A.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).87 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 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 (2019-2025) range from $350 to
$450 per metric ton of CH4 emissions (in 2016 dollars) using a 7 percent discount rate, and
$1,300 to $1,600 per metric ton of CH4using a 3 percent discount rate.88 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. Applying these estimates to
the forgone CH4 emission reductions results in estimated forgone global climate benefits ranging
from $10 million in 2019 to $31 million in 2025, using a 7 percent discount rate. The PV of the
87 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.
88 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 using a 7 percent discount rate is $89 million, with an associated
EAV of $15 million per year. The estimated forgone global climate benefits are $39 million in
2019 and increase to $110 million in 2025 using a 3 percent rate. The PV of the forgone global
climate benefits using a 3 percent discount rate is $421 million, with an associated EAV of $66
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
2019-2025 ranges from $1,800 to $2,100 per metric ton of CH4 (2016$). The forgone global
climate benefits are estimated to be $52 million in 2019 and $144 million in 2025 using a 2.5
percent discount rate. The PV of the forgone global climate benefits using a 2.5 percent discount
rate is $567 million, with an associated EAV of $87 million per year. All estimates are reported
in 2016 dollars.
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United States Office of Air Quality Planning and Standards Publication No. EPA-452/R-18-001
Environmental Protection Health and Environmental Impacts Division September, 2018
Agency Research Triangle Park, NC
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