Regulatory Impact Analysis for the Proposed 

Reconsideration of the Oil and Natural Gas 

Sector Emission Standards for New, 

Reconstructed, and Modified Sources
ii

[This page intentionally left blank]
iii

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
iv

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. 
v

TABLE OF CONTENTS

TABLE OF CONTENTS ..................................................................................................................... V

LIST OF TABLES............................................................................................................................VII

LIST OF FIGURES ...........................................................................................................................IX

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

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

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 A PM2.5 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

ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS............................. 4-36

4.1 INTRODUCTION .......................................................................................................................................... 4-36
vi

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

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
vii

LIST OF TABLES

Table 1-1 Estimated Cost and Emission Reductions of the 2016 NSPS OOOOa Fugitive Emissions 

Requirements: 2016 NSPS RIA and Updated 2018 Baseline Comparison ........................................ 1-6

Table 1-2 Emissions Sources and Controls Evaluated for the Regulatory Alternatives..................................... 1-7

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 ................................................................................. 1-11

Table 1-4 Cost Savings, Forgone Benefits and Increase in Emissions of Option 1 Compared to the 2018 

Baseline, 2019 through 2025 (millions 2016$) ................................................................................ 1-12

Table 1-5 Cost Savings, Forgone Benefits and Increase in Emissions of Option 2 Compared to the 2018 

Baseline, 2019 through 2025 (millions 2016$) ................................................................................ 1-13

Table 1-6 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

Table 2-1 Emissions Sources and Controls Evaluated for the Regulatory Alternatives..................................... 2-6

Table 2-2 Reconsideration Affected Source Counts of the Proposed Option 3 Compared to the 2018 Baseline . 2-

11

Table 2-3 Increase in Emissions under the Proposed Option 3 Compared to the 2018 Baseline, by year........ 2-12

Table 2-4 Estimated Decrease in Natural Gas Recovery (Mcf) for the Proposed Option 3 Compared to the 2018 

Baseline (millions 2016$) ................................................................................................................ 2-14

Table 2-5 Compliance Cost Savings Estimates for Proposed Option 3 Compared to the 2018 Baseline (millions 

2016$) .............................................................................................................................................. 2-15

Table 2-6 Estimated Cost Savings of the Proposed Option 3, 2019-2025, using 3 and 7 Percent Discount Rates 

(millions 2016$)............................................................................................................................... 2-16

Table 2-7 Comparison of Regulatory Alternatives to 2018 Baseline, 2020 and 2025...................................... 2-18

Table 2-8 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 1, 2020............... 2-20

Table 2-9 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 1, 2025............... 2-20

Table 2-10 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 2, 2020............... 2-21

Table 2-11 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 2, 2025............... 2-21

Table 2-12 Incrementally Affected Sources, Emissions Increases and Cost Savings, Proposed Option 3, 20202-22

Table 2-13 Incrementally Affected Sources, Emissions Increases and Cost Savings, Proposed Option 3, 20252-22

Table 2-14 Estimated Cost Savings for the Proposed Option 3, 2019-2025 (millions 2016$)........................... 2-24

Table 2-15 Discounted Cost Savings Estimates for Proposed Option 3 Compared to the 2018 Baseline Using a 7 

Percent Discount Rate (millions 2016$)........................................................................................... 2-25

Table 2-16 Comparison of Regulatory Alternatives to 2018 Baseline Using a 7 Percent Discount Rate........... 2-26

Table 2-17 Discounted Cost Savings for the Proposed Option 3 using 7 and 3 Percent Discount Rates Compared 

to the 2018 Baseline (millions 2016$).............................................................................................. 2-27

Table 2-18 Total Cost Savings and Increase in Emissions of the Proposed Option Under Alternative Monitoring 

Frequencies at Compressor Stations................................................................................................. 2-28

Table 3-1 Climate and Human Health Effects of Forgone Emission Reductions from this Proposed Rule ....... 3-2

Table 3-2 Total Direct Increases in Emissions Compared to the 2018 Baseline across Regulatory Options, 2019 

through 2025 ...................................................................................................................................... 3-5

Table 3-3 Annual Direct Increases in Methane, VOC and HAP Emissions Compared to the 2018 Baseline, 

Options 2 and 3, 2019 through 2025 .................................................................................................. 3-6

Table 3-4 Interim Domestic Social Cost of CH4, 2019-2025 (in 2016$ per metric ton CH4)*........................... 3-9

Table 3-5 Estimated Forgone Domestic Climate Benefits of the Proposed Option 3, 2019-2025 (millions, 

2016$) .............................................................................................................................................. 3-10

Table 3-6 Discounted Forgone Domestic Climate Benefits of the Proposed Option 3, PV and EAV (millions, 

2016$) .............................................................................................................................................. 3-10

Table 3-7 Estimated Forgone Domestic Climate Benefits Across the Regulatory Options (millions, 2016$) . 3-11

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$).. 5-2

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$).. 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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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.

• DrillingInfo: This RIA uses a more recent version of the DrillingInfo dataset than was 

used for the 2016 NSPS OOOOa.

6 The DrillingInfo 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 DrillingInfo 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.
1-5

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 DrillingInfo 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.
1-6

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, 

2016$)

$199 $407 $115 $219

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.
1-7

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

(CoProposed)1

Fugitive Emissions - Planning, Monitoring and Maintenance

Natural Gas and Oil Well Sites Semiannual Semiannual Semiannual 

2 Yrs. 

Semiannual, 

then Annual

Annual

Low Production Well Sites (<15 

BOE/day) Semiannual Semiannual Semiannual Annual Biennial

Natural Gas and Oil Well Sites on 

the Alaskan North Slope Semiannual Annual Annual Annual Annual

Compressor Stations in Gathering 

and Boosting, Transmission and 

Storage

Quarterly Quarterly Quarterly Quarterly Semiannual

Compressor Stations in Gathering 

and Boosting, Transmission and 

Storage on the Alaskan North 

Slope2

Quarterly Quarterly Quarterly 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 inhouse 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.
1-9

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 disbenefits 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.
1-10

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. 
1-11

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

Facilities

Affected

Methane Emission 

Reductions 

(short tons)

VOC Emission 

Reductions 

(short tons)

Total Annualized 

Cost, w/ Product 

Recovery 

(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.
1-12

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 coproposed 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 CO2E) 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.
1-13

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 CO2E) 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 CoProposed 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 CO2E) 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 
1-14

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
2-1

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
2-2

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.
2-3

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 
2-4

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.
2-5

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.
2-6

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

(CoProposed)1

Fugitive Emissions - Planning, Monitoring and Maintenance

Natural Gas and Oil Well Sites Semiannual Semiannual Semiannual 

2 Yrs. 

Semiannual, 

then Annual

Annual

Low Production Well Sites (<15 

BOE/day) Semiannual Semiannual Semiannual Annual Biennial

Natural Gas and Oil Well Sites on 

the Alaskan North Slope Semiannual Annual Annual Annual Annual

Compressor Stations in Gathering 

and Boosting, Transmission and 

Storage

Quarterly Quarterly Quarterly Quarterly Semiannual

Compressor Stations in Gathering 

and Boosting, Transmission and 

Storage on the Alaskan North 

Slope2

Quarterly Quarterly Quarterly 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 
2-7

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.
2-8

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.
2-9

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-
2-10

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
2-11

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; 
2-12

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.
2-13

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 GDPImplicit 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 EIA 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/.
2-14

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 1.85 $5.7

2020 2.3 $7.6

2021 2.7 $8.9

2022 3.1 $10

2023 3.5 $12

2024 4.0 $14

2025 4.4 $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.
2-15

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

Savings

1

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 
2-16

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
2-17

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.32 Natural 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 VI.B.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. 
2-18

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 11 Option 2 Option 3

(Co-Proposed) 2

Total Impacts, 2020

Increase in Emissions

Methane Emissions (short tons/year) 0 21,000 39,000

VOC Emissions (short tons/year) 0 5,700 10,000

Decrease in Natural Gas Recovery (Mcf) 

(millions) 0 1.2 2.3

Cost Savings

Planning Cost Savings $2.7 $3.0 $3.1

Annualized Cost Savings w/o Forgone 

Revenue $3.5 $38 $69

Annualized Cost Savings with Forgone 

Revenue $3.5 $34 $62

Total Impacts, 2025

Increase in Emissions

Methane Emissions (short tons/year) 0 41,000 76,000

VOC Emissions (short tons/year) 0 11,000 20,000

Decrease in Natural Gas Recovery (Mcf) 

(millions) 0 2.4 4.4

Cost Saving

Planning Cost Savings $2.9 $3.5 $3.7

Annualized Cost Savings w/o Forgone 

Revenue $3.7 $72 $132

Annualized Cost Savings with Forgone 

Revenue $3.7 $64 $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 coproposed 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 
2-19

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.
2-20

Table 2-8 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 1, 2020

Source/Emissions Point

Projected No. of 

Reconsideration 

Affected 

Sources

Total Increase in Emissions National Cost Savings

Methane 

(short 

tons)

VOC 

(short 

tons)

HAP 

(short 

tons)

Methane 

(metric 

tons 

CO2e)

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 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 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

Source/Emissions Point

Projected No. of 

Reconsideration 

Affected 

Sources

Total Increase in Emissions National Cost Savings

Methane 

(short 

tons)

VOC 

(short 

tons)

HAP 

(short 

tons)

Methane 

(metric 

tons 

CO2e)

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 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 15,000 0 0 0 0 $2.9 $0 $0 $3.7
2-21

Table 2-10 Incrementally Affected Sources, Emissions Increases and Cost Savings, Option 2, 2020

Source/Emissions Point

Projected No. of 

Reconsideration 

Affected 

Sources

Total Increase in Emissions National Cost Savings

Methane 

(short 

tons)

VOC 

(short 

tons)

HAP 

(short 

tons)

Methane 

(metric 

tons 

CO2e)

Planning

Cost

Savings

Operating 

and 

Maintenance

Forgone 

Product 

Recovery

Total 

Annualized 

Cost Savings 

with Forgone

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

Source/Emissions Point

Projected No. of 

Reconsideration 

Affected 

Sources

Total Increase in Emissions National Cost Savings

Methane 

(short 

tons)

VOC 

(short 

tons)

HAP 

(short 

tons)

Methane 

(metric 

tons 

CO2e)

Planning

Cost

Savings

Operating 

and 

Maintenance

Forgone 

Product 

Recovery

Total 

Annualized 

Cost Savings 

with Forgone

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
2-22

Table 2-12 Incrementally Affected Sources, Emissions Increases and Cost Savings, Co-Proposed Option 3, 2020

Source/Emissions Point

Projected No. of 

Reconsideration 

Affected 

Sources

Total Increase in Emissions National Cost Savings

Methane 

(short 

tons)

VOC 

(short

tons)

HAP 

(short 

tons)

Methane 

(metric 

tons 

CO2e)

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 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 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

Source/Emissions Point

Projected No. of 

Reconsideration 

Affected 

Sources

Total Increase in Emissions National Cost Savings

Methane 

(short 

tons)

VOC 

(short 

tons)

HAP 

(short 

tons)

Methane 

(metric 

tons 

CO2e)

Planning

Cost

Savings

Operating 

and 

Maintenance

Forgone 

Product 

Recovery

Total 

Annualized 

Cost Savings 

with Forgone

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
2-23

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. 
2-24

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

Savings

1

Operating 

and 

Maintenance 

Cost Savings

Total Cost

Savings Without 

Forgone 

Revenue

Forgone 

Revenue from 

Product 

Recovery

Total Cost

Savings with 

Forgone

Revenue

2

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.
2-25

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

Savings

1

Operating and 

Maintenance 

Cost Savings

Forgone 

Revenue from 

Product 

Recovery

Total Cost

Savings with 

Forgone

Revenue

2

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.
2-26

Table 2-16 Comparison of Regulatory Alternatives to 2018 Baseline Using a 7 Percent 

Discount Rate

Regulatory Alternatives

Option 1 Option 2 Option 3

(Co-Proposed)1

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 $17 $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.
2-27

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.1 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.1 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 
2-28

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

Quarterly

Semiannual

(Co-Proposed 

Option)

Annual

(Alternative CoProposed 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 coproposed option under semiannual monitoring. 
2-29

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. 
3-1

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 CO2-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. 
3-2

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

Category Specific Effect

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More 

Information

Improved Environment

Reduced climate 

effects

Climate impacts from methane (CH4) and 

carbon dioxide (CO2)

—1 ✓ Section 3.3

Other climate impacts (e.g., ozone, black 

carbon, aerosols, other impacts) — —

IPCC, Ozone ISA, 

PM ISA2

Improved Human Health

Reduced incidence of 

premature mortality 

from exposure to 

PM2.5

Adult premature mortality based on cohort 

study estimates and expert elicitation estimates 

(age >25 or age >30)

— — PM ISA3

Infant mortality (age <1) — — PM ISA3

Reduced incidence of 

morbidity from 

exposure to PM2.5

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

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

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

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

 

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.
3-3

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

Reduced incidence of 

morbidity from 

exposure to ozone

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

Minor restricted-activity days (age 18–65) — — Ozone ISA3

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 

impairment

Visibility in Class 1 areas — — PM ISA3

Visibility in residential areas — — PM ISA3

Reduced effects from 

PM deposition 

(organics)

Effects on Individual organisms and 

ecosystems — — PM ISA2

Reduced vegetation 

and ecosystem effects 

from exposure to 

ozone

Visible foliar injury on vegetation — — Ozone ISA3

Reduced vegetation growth and reproduction — — Ozone ISA3

Yield and quality of commercial forest 

products and crops — — Ozone ISA3

Damage to urban ornamental plants — — Ozone ISA2
3-4

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. 
3-5

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.
3-6

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 

(metric tons) VOC 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/m2of 

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/m2of 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 
3-7

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 
3-8

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
3-9

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)*

Year

Discount Rate and Statistic

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 SCCH4 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) 0 180,000 340,000

Forgone CH4 reductions (million 

metric tonnes of CO2 Eq.) 0 4.5 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 in EPAHQ-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 et 

al. (2014)” estimates. In addition, EPA-HQ-OAR-2015-0827-5886 provides a detailed discussion of the 

limitations and uncertainties associated with the SC-GHG estimates.
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There are several limitations specific to the estimation of SC-CH4. For example, the SCCH4 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 

<https://www.nap.edu/catalog/24651/valuing-climate-damages-updating-estimation-of-the-social-cost-of> 

Accessed May 30, 2017.
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CO2 estimates, a modeling framework to satisfy the specified criteria, and both near-term 

updates and longer-term research needs pertaining to various components of the estimation 

process (National Academies 2017). Since the framework used to estimate SC-CH4 is 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, 2011a). 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, 2011b)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 PM2.5-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 μg/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 
3-17

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 (2011g). 

When EPA quantifies PM2.5-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, 2011a; U.S. EPA, 2011g; 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-nationalair-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. <http://www.epa.gov/national-air-toxics-assessment/2011-national-air-toxics-assessment>.

47 Details on EPA’s approach to characterization of cancer risks and uncertainties associated with the 2011 NATA 

risk estimates can be found at <http://www.epa.gov/national-air-toxics-assessment/nata-limitations>.

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 <http://www.epa.gov/national-air-toxics-assessment/nata-limitations>.
3-21

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 

NATA, 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 

(<http://www.epa.gov/iris>) as repeated exposure by the oral, dermal, or inhalation route for more than 

approximately 10 of the life span in humans (more than approximately 90 days to 2 years in typically used 

laboratory animal species).

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 <http://www.epa.gov/iris>.
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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
3-23

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 μg/m3of a pollutant. These 

URFs 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, 2011a), 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: <http://www.epa.gov/iris/subst/0276.htm>.

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: <http://ntp.niehs.nih.gov/go/16183>.

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 <http://www.epa.gov/iris/subst/0118.htm>.
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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 (shortterm) 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 

<http://toxnet.nlm.nih.gov/cgi-bin/sis/search/r?dbs+hsdb:@term+@rn+@rel+463-58-1>.

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 <http://www.epa.gov/iris/subst/0617.htm>.
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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 Acad Sci 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) in F344/N Rats and in B6C3F1 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 <http://www.epa.gov/iris/subst/0270.htm>.

68 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is 

available electronically at <http://www.atsdr.cdc.gov/ToxProfiles/TP.asp?id=296&tid=53>.
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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 n-Hexane

The studies available in both humans and animals indicate that the nervous system is the 

primary target of toxicity upon exposure of n-hexane via inhalation. There are no data in humans 

and very limited information in animals about the potential effects of n-hexane via the oral route. 

Acute (short-term) inhalation exposure of humans to high levels of hexane causes mild central 

nervous system effects, including dizziness, giddiness, slight nausea, and headache. Chronic 

(long-term) exposure to hexane in air causes numbness in the extremities, muscular weakness, 

blurred vision, headache, and fatigue. Inhalation studies in rodents have reported behavioral 

effects, neurophysiological changes and neuropathological effects upon inhalation exposure to nhexane. 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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Corporate Average Fuel Economy Standards. EPA-420-R-12-016. Office of 

Transportation and Air Quality, Assessment and Standards Division. August. 

<http://www.epa.gov/otaq/climate/documents/420r12016.pdf>. Accessed March 30, 

2015.

U.S. Environmental Protection Agency (U.S. EPA). 2013. Integrated Science Assessment of 

Ozone and Related Photochemical Oxidants (Final Report). U.S. Environmental 

Protection Agency, Washington, DC, EPA/600/R-10/076F. February. 

<http://cfpub.epa.gov/ncea/isa/recordisplay.cfm?deid=247492#Download>. Accessed 

March 30, 2015.
3-35

U.S. Environmental Protection Agency (U.S. EPA). 2014a. Health Risk and Exposure 

Assessment for Ozone (Final Report). U.S. Environmental Protection Agency, Research 

Triangle Park, NC, EPA-452/R-14-004a. August. 

<http://www.epa.gov/ttn/naaqs/standards/ozone/data/20140829healthrea.pdf>. Accessed 

March 30, 2015.

U.S. Environmental Protection Agency (U.S. EPA). 2014b. Regulatory Impact Analysis for the 

Proposed Ozone NAAQS. U.S. Environmental Protection Agency, Research Triangle 

Park, NC, EPA-452/P-14-006. December. 

<http://www.epa.gov/ttnecas1/regdata/RIAs/20141125ria.pdf>. Accessed March 30, 

2015.

U.S. Environmental Protection Agency (U.S. EPA). 2014c. Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2012. EPA/430-R-14-003. April. < 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/2014.html >. 

Accessed April 3, 2015.

U.S. Environmental Protection Agency—Science Advisory Board (U.S. EPA-SAB). 2002. 

Workshop on the Benefits of Reductions in Exposure to Hazardous Air Pollutants: 

Developing Best Estimates of Dose-Response Functions An SAB Workshop Report of an 

EPA/SAB Workshop (Final Report). EPA-SAB-EC-WKSHP-02-001. January. 

<http://yosemite.epa.gov/sab5CSABPRODUCT.NSF/34355712EC011A358525719A005

BF6F6/$File/ecwkshp020012Bappa-g.pdf>. Accessed March 30, 2015.

U.S. Environmental Protection Agency—Science Advisory Board (U.S. EPA-SAB). 2008. 

Benefits of Reducing Benzene Emissions in Houston, 1990–2020. EPA-COUNCIL-08-

001. July. 

<http://yosemite.epa.gov/sab/sabproduct.nsf/D4D7EC9DAEDA8A548525748600728A8

3/$File/EPA-COUNCIL-08-001-unsigned.pdf>. Accessed March 30, 2015.

Waldhoff, S., D. Anthoff, S. Rose, R.S.J. Tol. 2014. “The Marginal Damage Costs of Different 

Greenhouse Gases: An Application of FUND.” The Open-Access, Open Assessment EJournal. 8(31): 1-33. http://dx.doi.org/10.5018/economics-ejournal.ja.2014-31. Accessed 

April 3, 2014.

West et al. 2006. “Global health benefits of mitigating ozone pollution with methane emission 

controls.” Proceedings of the National Academy of Sciences 103(11):3988-3993.

West, J.J., A.M. Fiore. 2005. “Management of tropospheric ozone by reducing methane 

emissions.” Environmental Science & Technology 39:4685-4691.
4-36

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
4-37

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 LowIncome 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. 
4-38

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).
4-39

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 (RFA; 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 
4-40

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).
4-41

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.
4-42

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 emissionsrelated 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.
5-1

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.
5-2

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 (SCCH4). 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% 3%

PV EAV PV 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

1 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 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 
5-3

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% 3%

PV EAV PV 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

1 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 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
5-4

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 
5-5

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.
A-1

A. APPENDIX: UNCERTAINTY ASSOCIATED WITH ESTIMATING THE 

SOCIAL COST OF METHANE

A.1 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.
A-2

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 multimodel 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.
A-5

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.
A-6

Figure 1. Frequency Distribution of Interim Domestic SC-CH4 Estimates for 2020 (in 

2016$ per metric ton CH4)

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).
A-7

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.
A-8

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 CH4 using 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.
A-9

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

Environmental Protection 

Agency

Office of Air Quality Planning and Standards

Health and Environmental Impacts Division

Research Triangle Park, NC

Publication No. EPA-452/R-18-001

September, 2018