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EO12866_O&GNSPS 2060 AS30 RIA_201508120

Regulatory Impact Analysis of the Proposed 

Emission Standards for New and Modified 

Sources in the Oil and Natural Gas Sector
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EPA-452/R-15-002, August 2015

Regulatory Impact Analysis of the Proposed Emission Standards for New and 

Modified Sources in the Oil and Natural Gas Sector

U.S. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, NC 27711
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CONTACT INFORMATION

This document has been prepared by staff from the Office of Air and Radiation, U.S. 

Environmental Protection Agency. Questions related to this document should be addressed to 

Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air and Radiation, 

Research Triangle Park, North Carolina 27711 (email: macpherson.alex@epa.gov).

ACKNOWLEDGEMENTS

In addition to U.S. EPA staff from the Office of Air and Radiation, personnel from the U.S. EPA

Office of Policy, EC/R Incorporated, and ICF International contributed data and analysis to this 

document. 
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TABLE OF CONTENTS

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

LIST OF TABLES.......................................................................................................................... VIII

LIST OF FIGURES ............................................................................................................................ X

1 EXECUTIVE SUMMARY........................................................................................................ 1-1

1.1 BACKGROUND.............................................................................................................................................. 1-1

1.2 MARKET FAILURE........................................................................................................................................ 1-3

1.3 SUMMARY OF RESULTS................................................................................................................................ 1-3

1.4 ORGANIZATION OF THIS REPORT................................................................................................................ 1-11

2 INDUSTRY PROFILE ............................................................................................................. 2-1

2.1 INTRODUCTION ............................................................................................................................................ 2-1

2.2 PRODUCTS OF THE CRUDE OIL AND NATURAL GAS INDUSTRY .................................................................... 2-2

2.2.1 Crude Oil ........................................................................................................................................... 2-2

2.2.2 Natural Gas........................................................................................................................................ 2-3

2.2.3 Condensates....................................................................................................................................... 2-3

2.2.4 Other Recovered Hydrocarbons......................................................................................................... 2-3

2.2.5 Produced Water ................................................................................................................................. 2-4

2.3 OIL AND NATURAL GAS PRODUCTION PROCESSES ...................................................................................... 2-4

2.3.1 Exploration and Drilling .................................................................................................................... 2-4

2.3.2 Production.......................................................................................................................................... 2-5

2.3.3 Natural Gas Processing...................................................................................................................... 2-7

2.3.4 Natural Gas Transmission and Distribution....................................................................................... 2-8

2.4 RESERVES AND MARKETS............................................................................................................................ 2-8

2.4.1 Domestic Proved Reserves ................................................................................................................ 2-9

2.4.2 Domestic Production........................................................................................................................ 2-13

2.4.3 Domestic Consumption.................................................................................................................... 2-20

2.4.4 International Trade........................................................................................................................... 2-24

2.4.5 Forecasts.......................................................................................................................................... 2-26

2.5 INDUSTRY COSTS ....................................................................................................................................... 2-30

2.5.1 Finding Costs................................................................................................................................... 2-30

2.5.2 Lifting Costs .................................................................................................................................... 2-32

2.5.3 Operating and Equipment Costs ...................................................................................................... 2-33

2.6 FIRM CHARACTERISTICS ............................................................................................................................ 2-35

2.6.1 Ownership........................................................................................................................................ 2-36

2.6.2 Size Distribution of Firms in Affected NAICS................................................................................ 2-36

2.6.3 Trends in National Employment and Wages ................................................................................... 2-37

2.6.4 Horizontal and Vertical Integration ................................................................................................. 2-39

2.6.5 Firm-level Information .................................................................................................................... 2-41

2.6.6 Financial Performance and Condition.............................................................................................. 2-45

2.7 REFERENCES .............................................................................................................................................. 2-49

3 EMISSIONS AND ENGINEERING COSTS................................................................................ 3-1

3.1 INTRODUCTION ............................................................................................................................................ 3-1

3.2 SECTOR EMISSIONS OVERVIEW.................................................................................................................... 3-1

3.3 EMISSIONS POINTS AND POLLUTION CONTROLS ASSESSED IN THE RIA ....................................................... 3-2

3.4 ENGINEERING COST ANALYSIS .................................................................................................................... 3-5

3.4.1 Control Options ................................................................................................................................. 3-5

3.4.2 Projection of Incrementally Affected Facilities................................................................................. 3-8
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3.4.3 Emissions Reductions...................................................................................................................... 3-10

3.4.4 Product Recovery............................................................................................................................. 3-12

3.4.5 Engineering Compliance Costs........................................................................................................ 3-14

3.4.6 Cost-Effectiveness........................................................................................................................... 3-15

3.4.7 Comparison of Regulatory Alternatives .......................................................................................... 3-20

3.5 COMPLIANCE COSTS ESTIMATED USING 3 AND 7 PERCENT DISCOUNT RATES ........................................... 3-24

3.6 DETAILED IMPACTS TABLES ...................................................................................................................... 3-25

4 BENEFITS OF EMISSIONS REDUCTIONS............................................................................... 4-1

4.1 INTRODUCTION ............................................................................................................................................ 4-1

4.2 EMISSION REDUCTIONS FROM THE PROPOSED NSPS ................................................................................... 4-4

4.3 METHANE .................................................................................................................................................... 4-6

4.3.1 Methane climate effects and valuation............................................................................................... 4-6

4.4 VOC AS A PM2.5 PRECURSOR...................................................................................................................... 4-18

4.4.1 PM2.5 health effects and valuation.................................................................................................... 4-18

4.4.2 Organic PM welfare effects............................................................................................................. 4-22

4.4.3 Visibility Effects.............................................................................................................................. 4-23

4.5 VOC AS AN OZONE PRECURSOR ................................................................................................................ 4-23

4.5.1 Ozone health effects and valuation .................................................................................................. 4-24

4.5.2 Ozone vegetation effects.................................................................................................................. 4-25

4.5.3 Ozone climate effects....................................................................................................................... 4-25

4.6 HAZARDOUS AIR POLLUTANT (HAP) BENEFITS ........................................................................................ 4-26

4.6.1 Benzene ........................................................................................................................................... 4-31

4.6.2 Toluene ............................................................................................................................................ 4-32

4.6.3 Carbonyl sulfide............................................................................................................................... 4-33

4.6.4 Ethylbenzene.................................................................................................................................... 4-33

4.6.5 Mixed xylenes.................................................................................................................................. 4-35

4.6.6 n-Hexane.......................................................................................................................................... 4-35

4.6.7 Other Air Toxics.............................................................................................................................. 4-36

4.7 SECONDARY AIR EMISSIONS IMPACTS ....................................................................................................... 4-36

4.8 REFERENCES .............................................................................................................................................. 4-38

5 STATUTORY AND EXECUTIVE ORDER REVIEWS ................................................................ 5-1

5.1 EXECUTIVE ORDER 12866, REGULATORY PLANNING AND REVIEW AND EXECUTIVE ORDER 13563,

IMPROVING REGULATION AND REGULATORY REVIEW.......................................................................................... 5-1

5.2 PAPERWORK REDUCTION ACT ..................................................................................................................... 5-1

5.3 REGULATORY FLEXIBILITY ACT .................................................................................................................. 5-2

5.4 UNFUNDED MANDATES REFORM ACT ......................................................................................................... 5-2

5.5 EXECUTIVE ORDER 13132: FEDERALISM ..................................................................................................... 5-2

5.6 EXECUTIVE ORDER 13175: CONSULTATION AND COORDINATION WITH INDIAN TRIBAL GOVERNMENTS.... 5-3

5.7 EXECUTIVE ORDER 13045: PROTECTION OF CHILDREN FROM ENVIRONMENTAL HEALTH RISKS AND SAFETY 

RISKS..................................................................................................................................................................... 5-4

5.8 EXECUTIVE ORDER 13211: ACTIONS CONCERNING REGULATIONS THAT SIGNIFICANTLY AFFECT ENERGY 

SUPPLY, DISTRIBUTION, OR USE............................................................................................................................ 5-4

5.9 NATIONAL TECHNOLOGY TRANSFER AND ADVANCEMENT ACT.................................................................. 5-6

5.10 EXECUTIVE ORDER 12898: FEDERAL ACTIONS TO ADDRESS ENVIRONMENTAL JUSTICE IN MINORITY 

POPULATIONS AND LOW-INCOME POPULATIONS................................................................................................... 5-6

6 COMPARISON OF BENEFITS AND COSTS ............................................................................. 6-1

7 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS............................... 7-1

7.1 INTRODUCTION ............................................................................................................................................ 7-1

7.2 ENERGY SYSTEM IMPACTS ANALYSIS.......................................................................................................... 7-1

7.2.1 Description of the Department of Energy National Energy Modeling System.................................. 7-2

7.2.2 Inputs to National Energy Modeling System..................................................................................... 7-3
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7.2.2.1 Compliance Costs for Oil and Gas Exploration and Production .............................................. 7-4

7.2.2.2 Adding Averted Methane Emissions into Natural Gas Production .......................................... 7-6

7.2.3 Energy System Impacts ..................................................................................................................... 7-7

7.3 INITIAL REGULATORY FLEXIBILITY ANALYSIS .......................................................................................... 7-10

7.4 EMPLOYMENT IMPACT ANALYSIS .............................................................................................................. 7-10

7.4.1 Employment Impacts of Environmental Regulation........................................................................ 7-11

7.4.2 Labor Estimates Associated with Proposed Requirements.............................................................. 7-15

7.5 REFERENCES .............................................................................................................................................. 7-22
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LIST OF TABLES

Table 1-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS .............................................. 1-7

Table 1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 2020 and 2025 (2012$)

1-8

Table 1-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 (Proposed Option) in 2020 

and 2025 (2012$)....................................................................................................................................................... 1-9

Table 1-4 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2a in 2020 and 2025 (2012$)

1-10

Table 1-5 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in 2020 and 2025 (2012$)

1-11

Table 2-1 Technically Recoverable Crude Oil and Natural Gas Resource ...................................................... 2-10

Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Production, Proved Reserves, and Proved Ultimate 

Recovery, 1977-2013............................................................................................................................................... 2-11

Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by State, 2013 .................................................... 2-13

Table 2-4 Crude Oil Domestic Production, Wells, Well Productivity, and...................................................... 2-14

Table 2-5 Natural Gas Production and Well Productivity, 1990-2013 ............................................................ 2-15

Table 2-6 Crude Oil and Natural Gas Exploratory and Development Wells and Average Depth, 1990-2010 2-17

Table 2-7 U.S. Onshore and Offshore Oil, Gas, and Produced Water Generation, 2007................................. 2-18

Table 2-8 U.S. Oil and Natural Gas Pipeline Mileage, 2010-2013 .................................................................. 2-20

Table 2-9 Crude Oil Consumption by Sector, 1990-2012................................................................................ 2-21

Table 2-10 Natural Gas Consumption by Sector, 1990-2012 ............................................................................ 2-23

Table 2-11 Total Crude Oil and Petroleum Products Trade (Million Bbl),........................................................ 2-25

Table 2-12 Natural Gas Imports and Exports, 1990-2013.................................................................................. 2-26

Table 2-13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2040....................................... 2-27

Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2011-2040 .................................... 2-28

Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price ..................................... 2-30

Table 2-16 SBA Size Standards and Size Distribution of Oil and Natural Gas Firms....................................... 2-37

Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-2013................................................. 2-38

Table 2-18 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2013 (2012 dollars) .................... 2-39

Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012 ......................................... 2-43

Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009 ............................................. 2-44

Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2012 ............................ 2-45

Table 2-22 Selected Financial Items from Income Statements (Billion 2008 Dollars)...................................... 2-47

Table 2-23 Return on Investment for Lines of Business (all FRS), for 1998, 2003, 2008, and 2009 (percent). 2-48

Table 2-24 Income and Production Taxes, 1990-2009 (Million 2008 Dollars) ................................................. 2-49

Table 3-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS .............................................. 3-7

Table 3-2 Number of Incrementally Affected Sources for the NSPS ................................................................ 3-9

Table 3-3 Emissions Reductions for Proposed NSPS Option 2, 2020 and 2025.............................................. 3-12

Table 3-4 Estimated Natural Gas Recovery (Mcf) for Proposed NSPS Option 2 in 2020 and 2025 ............... 3-13

Table 3-5 Engineering Compliance Cost Estimates for Proposed NSPS Option 2 in 2020 and 2025 ............. 3-15

Table 3-6 Engineering Compliance Cost-Effectiveness Estimates in 2020 and 2025 for Proposed NSPS Option 

2, Single Pollutant Approach................................................................................................................................... 3-18

Table 3-7 Engineering Compliance Cost-Effectiveness Estimates for Proposed NSPS Option 2 in 2020 and 

2025, Multipollutant Approach ............................................................................................................................... 3-20

Table 3-8 Comparison of Regulatory Alternatives .......................................................................................... 3-21

Table 3-9 Detailed Comparison of Regulatory Alternatives for Fugitive Emissions at Well Sites and 

Compressor Stations................................................................................................................................................ 3-23

Table 3-10 Annualized Costs using 3 and 7 Percent Discount Rates for Proposed NSPS Option 2 in 2020 and 

2025 3-24

Table 3-11 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 1, 2020 ........... 3-26

Table 3-12 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025 ........................... 3-27

Table 3-13 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, 2020 ........... 3-28

Table 3-14 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, 2025 ........... 3-29

Table 3-15 Incrementally Affected Units, Emissions Reductions and Costs, Option 2a, 2020 ......................... 3-30
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Table 3-16 Incrementally Affected Units, Emissions Reductions and Costs, Option 2a, 2025 ......................... 3-31

Table 3-17 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020 ........................... 3-32

Table 3-18 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025 ........................... 3-33

Table 4-1 Climate and Human Health Effects of Emission Reductions from this Proposal .............................. 4-2

Table 4-2 Direct Emission Reductions from the Proposed NSPS in 2020 and 2025 ......................................... 4-5

Table 4-3 Social Cost of Methane (SC-CH4), 2012 – 2050a[in 2012$ per metric ton] (Source: Marten et al., 

2015b) 4-14

Table 4-4 Estimated Global Benefits of Methane Reductions* (in millions, 2012$)....................................... 4-16

Table 4-5 Monetized Benefits-per-Ton Estimates for VOC based on Previous Modeling in 2015 (2012$).... 4-21

Table 4-6 Secondary Air Pollutant Impacts (short tons per year) .................................................................... 4-36

Table 4-7 Summary of Emissions Changes Across Options (short tons per year, except where noted).......... 4-38

Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 2020 and 2025 (2012$)

6-1

Table 6-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 (Proposed Option) in 2020 

and 2025 (2012$)....................................................................................................................................................... 6-2

Table 6-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2a in 2020 and 2025 (2012$)

6-3

Table 6-4 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in 2020 and 2025 (2012$)

6-4

Table 7-1 Per Well Costs for Environmental Controls Entered into NEMS (2012$) ........................................ 7-6

Table 7-2 Successful Oil and Gas Wells Drilled (Onshore, Lower 48 States)................................................... 7-8

Table 7-3 Annual Domestic Natural Gas and Crude Oil Production (Onshore, Lower 48 States) .................... 7-8

Table 7-4 Average Natural Gas and Crude Oil Wellhead Price (Onshore, Lower 48 States, 2012$) ................ 7-9

Table 7-5 Net Imports of Natural Gas and Crude Oil ...................................................................................... 7-10

Table 7-6 Estimates of Labor Required to Comply with Proposed NSPS for Hydraulically Fractured Oil Well 

Completions, 2020 and 2025 ................................................................................................................................... 7-18

Table 7-7 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, 2020 and 2025

7-19

Table 7-8 Estimates of Labor Required to Comply with Proposed NSPS for Reciprocating and Centrifugal 

Compressors, 2020 and 2025................................................................................................................................... 7-20

Table 7-9 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic Controllers and Pumps, 

2020 and 20257-21

Table 7-10 Estimates of Labor Required to Comply with Proposed NSPS, 2020 and 2025.............................. 7-22
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LIST OF FIGURES

Figure 2-1 A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990-2013. B) Domestic 

Natural Gas Proved Reserves and Cumulative Production, 1990-2013................................................................... 2-12

Figure 2-2 A) Total Producing Crude Oil Wells and Average Well Productivity, 1990-2011. B) Total Producing 

Natural Gas Wells and Average Well Productivity, 1990-2013.............................................................................. 2-16

Figure 2-3 U.S. Produced Water Volume by Management Practice, 2007 ....................................................... 2-19

Figure 2-4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990-2011 ............................ 2-22

Figure 2-5 Forecast of Domestic Crude Oil Production and Net Imports, 2010-2040 ...................................... 2-29

Figure 2-6 Costs of Crude Oil and Natural Gas Wells Drilled, 1981-2008....................................................... 2-31

Figure 2-7 Finding Costs for FRS Companies, 1981-2009 ............................................................................... 2-32

Figure 2-8 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2009 (3-year Running Average)

2-33

Figure 2-9 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976 

dollars), 1976-2009.................................................................................................................................................. 2-34

Figure 2-10 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas Price, 1976-2009

2-35

Figure 4-1 Path from GHG Emissions to Monetized Damages......................................................................... 4-11

Figure 4-3 2005 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk from HAP Exposure from 

All Outdoor Sources based on the 2005 National Toxics Inventory ....................................................................... 4-29
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1 EXECUTIVE SUMMARY

1.1 Background

The action analyzed in this regulatory impact analysis (RIA) proposes to amend the new 

source performance standards (NSPS) for the oil and natural gas source category by setting

standards for both methane and volatile organic compounds (VOC) for certain equipment, 

processes and activities across this source category. 

The Environmental Protection Agency (EPA) is including requirements for methane 

emissions in this proposal because methane is a greenhouse gas (GHG), and the oil and natural 

gas category is currently one of the country's largest emitters of methane. In 2009, the EPA

found that by causing or contributing to climate change, GHGs endanger both the public health 

and the public welfare of current and future generations.

The EPA is proposing to amend the NSPS to include standards for reducing methane as 

well as VOC emissions across the oil and natural gas source category. Specifically, we are 

proposing both methane and VOC standards for several emission sources not currently covered 

by the NSPS (i.e., hydraulically fractured oil well completions, fugitive emissions from well sites 

and compressor stations, pneumatic pumps). In addition, we are proposing methane standards for 

certain emission sources that are currently regulated for VOC (i.e., hydraulically fractured gas 

well completions, equipment leaks at natural gas processing plants). However, we do not expect 

any incremental benefits or costs as a result from regulating methane for currently regulated 

VOC sources. 

With respect to certain equipment that are used across the source category, the current 

NSPS regulates only a subset of these equipment (pneumatic controllers, centrifugal 

compressors, reciprocating compressors). The proposed amendents would establish methane 

standards for these equipment across the source category and extend the current VOC standards 

to the remaining unregulated equipment. Lastly, amendments to the current NSPS are being 

proposed that improve several aspects of the current standards related to implementation. These 

improvements result from reconsideration of certain issues raised in petitions for reconsideration 

that were received by the Administrator on the August 16, 2012, final NSPS for the oil and 
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natural gas sector and related amendments. Except for these implementation improvements and 

the setting of standards for methane, these amendments do not change the requirements for 

operations already covered by the current standards.

As part of the regulatory process, EPA is required to develop a regulatory impact analysis 

(RIA) for rules that have costs or benefits that exceed $100 million annually. EPA estimates the 

proposed NSPS will have costs that exceed $100 million, so the Agency has prepared an RIA.

This RIA includes an economic impact analysis and an analysis of the climate, health, and 

welfare impacts anticipated from the proposed NSPS.1 We also estimate potential impacts of the

proposed rule on the national energy economy using the U.S. Energy Information 

Administration’s National Energy Modeling System (NEMS). The engineering compliance costs 

are annualized using 3 and 7 percent discount rates.

This analysis estimates regulatory impacts for the analysis years of 2020 and 2025, which 

spans a period of six years. The analysis of 2020 is assumed to represent the first year the full 

suite of proposed standards is in effect and thus represents a single year of potential impacts. We 

estimate impacts in 2025 to illustrate how new and modified sources accumulate over time under 

the proposed NSPS. The regulatory impact estimates for 2025 include sources newly affected in 

2025 as well as the accumulation of affected sources from 2020 to 2024 that are also assumed to 

be in continued operation in 2025, thus incurring compliance costs and emissions reductions in 

2025. 

Several emission controls for the NSPS, such as reduced emissions completions (RECs) 

of hydraulically-fractured oil wells, capture methane and VOC emissions that otherwise would

be vented to the atmosphere. The averted methane emissions can be directed into natural gas 

production streams and sold. The revenues derived from natural gas recovery are expected to 

offset a portion of the engineering costs of implementing the NSPS. In this RIA, we present 

results that include the additional product recovery and the revenues we expect producers to gain 

from the additional product recovery.

 

1 The analysis in this draft RIA constitutes the economic assessment required by CAA section 317. In the EPA’s 

judgment, the assessment is as extensive as practicable taking into account the EPA’s time, resources, and other 

duties and authorities.
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The baseline used for the impacts analysis of our NSPS takes into account emissions 

reductions conducted pursuant to state regulations covering the relevant operations. More 

detailed discussion on the derivation of the baseline is presented in Section 3 of this RIA. 

1.2 Market Failure

Many regulations are promulgated to correct market failures, which lead to a suboptimal 

allocation of resources within the free market. Air quality and pollution control regulations 

address “negative externalities” whereby the market does not internalize the full opportunity cost 

of production borne by society as public goods such as air quality are unpriced. 

Greenhouse Gas (GHG) and VOC emissions impose costs on society, such as negative 

climate, health, and welfare impacts that are not reflected in the market price of the goods 

produced through the polluting process. For this regulatory action the goods produced, 

processed, transported, or stored are crude oil, natural gas, and other hydrocarbon products. 

These social costs associated with the climate, health, and welfare impacts are referred to as 

negative externalities. If an oil and natural gas firm pollutes the atmosphere while extracting, 

processing, transporting, or storing the commodities, this cost will be borne not by the polluting 

firm but by society as a whole. The market price of the products will fail to incorporate the full 

opportunity cost to society of producing the products. All else equal, given this externality, the 

quantity of oil and natural gas produced in a free market will not be at the socially optimal level. 

More oil and natural gas will be produced than would occur if the power producers had to 

account for the full opportunity cost of production including the negative externality.

Consequently, absent a regulation on emissions, the marginal social cost of the last units of oil 

and natural gas produced will exceed its marginal social benefit.

1.3 Summary of Results

For the proposed NSPS, the key results of the RIA follow and are summarized in Table 

1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 2020 and 

2025 (2012$)

2020 2025

Total Monetized Benefits1 $200 million $470 million
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Total Costs2 $150 million $310 million

Net Benefits3 $43 million $160 million

Non-monetized Benefits

Non-monetized climate benefits Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 120,000 tons of VOC 

reduced

Health effects of PM2.5 and ozone 

exposure from 170,000 tons of VOC 

reduced

Health effects of HAP exposure from 

310 tons of HAP reduced

Health effects of HAP exposure from 

1,900 tons of HAP reduced

Health effects of ozone exposure from 

170,000 tons of methane

Health effects of ozone exposure from 

340,000 tons of methane

Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes of 

this table, we show the benefits associated with the model average a 3 percent discount rate. However, we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the 

additional benefit estimates range from $89 million to $530 million in 2020 and $220 million to $1,200 million in 

2025 for the proposed option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for 

details.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.
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Table 1-3Table 1-1. Note all dollar estimates are in 2012 dollars:

 Emissions Analysis: The proposed NSPS is anticipated to prevent significant new 

emissions, including 180,000 tons of methane, 120,000 tons of VOCs and 400 tons of 

hazardous air pollutants (HAP) in 2020, increasing to 400,000 tons of methane, 180,000

tons of VOCs, and 2,500 tons of HAP prevented in 2025.

2 The CO2-equivalent (CO2 Eq.)

methane emission reductions are 4.0 million metric tons in 2020 and 9.0 million metric 

tons in 2025.

 Benefits Analysis: The monetized benefits in this RIA include those from reducing 

methane emissions, which are valued using the social cost of methane (SC-CH4).3 The 

EPA estimates that, in 2020, the proposal will yield monetized climate benefits of $93 

million to approximately $550 million; the mean SC-CH4 at the 3% discount rate results 

in an estimate of about $210 million in 2020. In 2025, the EPA estimates monetized 

climate benefits of $250 million to approximately $1.4 billion; the mean SC-CH4 at the 

3% discount rate results in an estimate of about $550 million in 20254 While we expect 

that the avoided emissions will result in improvements in ambient air quality and 

reductions in health effects associated with exposure to HAP, ozone, and particulate 

matter (PM), we have determined that quantification of those benefits cannot be 

accomplished for this rule.

5 This is not to imply that there are no health benefits 

anticipated from the proposed rule; rather, it is a reflection of the difficulties in modeling 

the direct and indirect impacts of the reductions in emissions for this industrial sector 

with the data currently available. In addition to health improvements, there will be 

improvements in visibility effects, ecosystem effects, as well as additional natural gas 

recovery. The specific control technologies for the proposed NSPS are anticipated to 

have minor secondary disbenefits.

 Engineering Cost Analysis: EPA estimates the total capital cost of the proposed NSPS 

will be $180 million in 2020 and $330 million in 2025. The estimate of total annualized 

engineering costs of the proposed NSPS is $200 million in 2020 and $500 million in 

2025 when using a 7 percent discount rate. When estimated revenues from additional 

natural gas are included, the annualized engineering costs of the proposed NSPS are 

estimated to be $170 million in 2020 and $420 million in 2025, assuming a wellhead 

 

2 Estimates are presented in short tons. 

3 The social cost of methane (SC-CH4) is the monetary value of impacts associated with a marginal change in 

methane emissions in a given year.

4 The range of estimates reflects four SC-CH4 estimates are associated with different discount rates (model average 

at 2.5, 3 and 5 percent; 95th percentile at 3 percent). See Section 4.3 for a complete discussion.

5 Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the 

effect that 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 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.
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natural gas price of $4/thousand cubic feet (Mcf). The estimated engineering compliance 

costs that include the product recovery are sensitive to the assumption about the price of 

the recovered product. There is also geographic variability in wellhead prices, which can 

also influence estimated engineering costs. For example, $1/Mcf change in the wellhead 

price causes a change in estimated engineering compliance costs of about $8.2 million in 

2020 and $19 million in 2025, given EPA estimates that about 8.2 million Mcf in 2020 

and 19 million Mcf of natural gas will be recovered by implementing the NSPS. When 

using a 3 percent discount rate, the estimate of total annualized engineering costs of the

proposed NSPS is $200 million in 2020 and $4900 million in 2025, or $170 million in 

2020 and $420 million in 2025, when estimated revenues from additional natural gas are 

included.6

 Energy System Impacts Analysis: The EPA used the National Energy Modeling System 

(NEMS) to estimate the impacts of the proposed rule on the United States energy system.

We estimate that natural gas and crude oil production levels remains essentially 

unchanged in 2020, while slight declines are estimated for 2020 for both natural gas 

(about 4 billion cubic feet (bcf) or about 0.01 percent) and crude oil production (about 

2,000 barrels per day or 0.03 percent). Wellhead natural gas prices for onshore lower 48 

production are not estimated to change in 2020, but are estimated to increase about 

$0.007 per Mcf or 0.14 percent in 2025. Meanwhile, well crude oil prices for onshore 

lower 48 production are not estimated to change, despite the incidence of new 

compliance costs from the proposed NSPS. Meanwhile, net imports of natural gas are 

estimated to decline slightly in 2020 (by about 1 bcf or 0.05 percent) and in 2025 (by 

about 3 bcf or 0.09 percent). Crude oil imports are estimated to not change in 2020 and 

increase by about 1,000 barrels per day (or 0.02 percent) in 2025.

 Small Entity Analyses: [Placeholder for summary of Initial Regulatory Flexibility 

Analysis]

 Employment Impacts Analysis: EPA estimated the labor impacts due to the installation, 

operation, and maintenance of control equipment and control activities, as well as the

labor associated with new reporting and recordkeeping requirements. We estimated onetime and continual, annual labor requirements by estimating hours of labor required for 

compliance and converting this number to full-time equivalents (FTEs) by dividing by 

2,080 (40 hours per week multiplied by 52 weeks). The one-time labor requirement to 

comply with the proposed NSPS is estimated at about 70 FTEs in 2020 and in 2025. The 

annual labor requirement to comply with proposed NSPS is estimated at about 530 FTEs 

in 2020 and 1,400 FTEs in 2025. We note that this type of FTE estimate cannot be used 

to identify the specific number of people involved or whether new jobs are created for 

new employees, versus displacing jobs from other sectors of the economy.

 

6 The choice of discount rate has a small effect on nationwide annualized costs. The compliance costs related to oil 

well completions and fugitive emissions surveys occur in each year, so the interest rate has little impact on 

annualized costs for these sources. The annualized costs for pneumatic pumps, compressors, and pneumatic 

controllers are sensitive to interest rate, but these constitute a relatively small part of the total compliance cost 

estimates for the proposal.
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In thise RIA, we examine four broad regulatory options (see Chapter 3 for a detailed 

discussion).7 Table 1-1 shows the emissions sources, points, and controls for the four NSPS 

regulatory options analyzed in this RIA, which we term Option 1, Option 2, Option 2a, and 

Option 3. Option 2 was selected for proposal. The proposed Option 2 contains reduced emission 

completion (REC) and completion combustion requirements for a subset of newly completed oil 

wells that are hydraulically fractured or refractured. Option 2 also requires fugitive emissions 

survey and repair programs be performed semiannually (twice per year) at newly drilled or 

refractured oil and natural gas well sites, new or modified gathering and boosting stations, and 

new or modified transmission and storage compressor stations. Option 2 also requires reductions 

from centrifugal compressors, reciprocating compressors, pneumatic controllers, and pneumatic 

pumps throughout the oil and natural gas source category. 

The unselected Options 1, 2a, and 3 differ from the selected Option 2 with respect to the 

requirements for fugitive emissions. While Option 2 requires the fugitive emissions program all 

new and modified well sites, Option 2a does not have the fugitive requirements for low 

production sites.8 A low production site is defined by the average combined oil and natural gas 

production for the wells at the site being less than 15 barrels of oil equivalent (boe) per day.

9

Fewer sites in the program leads to lower costs and emissions reductions than under the proposed 

Option 2. Meanwhile, the less stringent Option 1 requires annual monitoring for well sites,

including low production sites, while maintaining semi-annualsemiannual requirements for 

others sites. Annual monitoring requirements at wells sites leads to lower costs, emission 

reductions, and natural gas recovery than the semiannual monitoring in the proposed Option 2. 

Finally, the more stringent Option 3 requires quarterly monitoring for all sites under the fugitive 

 

7 See Chapter 3 for a detailed discussion of the comparative impacts of the regulatory options. The EPA also 

analyzed a variant of proposed Option 2 where only emissions combustion is required for hydraulically fractured 

and re-fracture oil well completions, rather than require reduced emissions completions (RECs) in combination 

with combustion. This variation of the proposed Option 2 would achieve direct emission reduction that are 

equivalent to requiring RECs and combustion, but at an approximately $70 million per year lower cost. 

However, as explained in Section VIII.F of the preamble to the proposed NSPS, the EPA determined RECs and 

combustion to be the best system of emissions reduction. Section 4 of the Technical Support Document for the 

proposal presents the detailed technical analysis of the regulatory options for hydraulically fractured and refractured oil well completions.

8

In the preamble to the proposed rule, EPA is soliciting comment on excluding low production sites from the 

fugitive emissions program.

9 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels of crude oil 

equals 1000 cubic feet natural gas.
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emissions program, including low production sites. More frequent surveys result in higher costs, 

higher emissions reductions, and increased natural gas recovery over the proposed Option 2.
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Table 1-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS 

Emissions Point Emissions Control Option 1 Option 2 

(proposed) Option 2a Option 3

Well Completions and Recompletions

Hydraulically Fractured 

Development Oil Wells REC or Combustion X X X X

Hydraulically Fractured 

Wildcat and Delineation 

Oil Wells

Combustion X X X X

Fugitive Emissions

Well Pads

Monitoring and 

Maintenance Annual Semiannual

Semiannual 

with Low 

Production 

Exemption

Quarterly

Gathering and Boosting 

Stations

Monitoring and 

Maintenance Semiannual Semiannual Semiannual Quarterly

Transmission Compressor 

Stations

Monitoring and 

Maintenance Semiannual Semiannual Semiannual Quarterly

Pneumatic Pumps

Well Pads Route to control X X X X

Gathering and Boosting 

Stations Route to control X X X X

Transmission and Storage 

Compressor Stations Route to control X X X X

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations Emissions limit X X X X

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations

Annual Monitoring 

and Maintenance X X X X

Centrifugal Compressors

Natural Gas Transmission 

and Storage Stations Route to control X X X X

Table 1-2 presents the summary results for the Option 1, Table 1-3 presents summary 

results for the proposed Option 2, Table 1-4 presents summary results for Option 2a, and Table 

1-5 presents summary results for Option 3.
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Table 1-21-1 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 

2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits1 $200 million $470 million

Total Costs2 $150 million $310 million

Net Benefits3 $40 43 million $160 million

Non-monetized Benefits

Non-monetized climate benefits Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 120,000 tons of VOC 

reduced

Health effects of PM2.5 and ozone 

exposure from 170,000 tons of VOC 

reduced

Health effects of HAP exposure from 

310 tons of HAP reduced

Health effects of HAP exposure from 

1,900 tons of HAP reduced

Health effects of ozone exposure from 

170,000 tons of methane

Health effects of ozone exposure from 

340,000 tons of methane

Visibility impairment$200 million Visibility impairment$470 million

Vegetation effects$150 million Vegetation effects$310 million

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes of 

this table, we show the benefits associated with the model average a 3 percent discount rate. However, we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the 

additional benefit estimates range from $89 million to $530 million in 2020 and $220 million to $1,200 million in 

2025 for the proposed option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for 

details.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.
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Table 1-31-2 Summary of the Monetized Benefits, Costs, and Net Benefits for the 

Proposed Option 2 (Proposed Option) in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits1 $210 million $550 million

Total Costs2 $170 million $420 million

Net Benefits3 $35 million $120 million

Non-monetized Benefits

Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 120,000 tons of VOC 

reduced

Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 180,000 tons of VOC 

reduced

Health effects of HAP exposure

from 400 tons of HAP reduced

Health effects of ozone exposure 

from 180,000 tons of methane

Health effects of HAP exposure from 

2,500 tons of HAP reduced

Health effects of ozone exposure 

from 400,000 tons of methane

Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes of 

this table, we show the benefits associated with the model average a 3 percent discount rate. However, we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the

additional benefit estimates range from $93 million to $550 million in 2020 and $250 million to $1,400 million in 

2025 for the proposed option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 4.0 million metric tons in 2020 and 9.0 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for 

details.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.
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Table 1-41-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 

2athe Less Stringent Option in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits1 $200 million $460 million

Total Costs2 $150 million $320 million

Net Benefits3 $42 million $150 million

Non-monetized Benefits

Non-monetized climate benefits Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 120,000 tons of VOC 

reduced

Health effects of PM2.5 and ozone 

exposure from 170,000 tons of VOC 

reduced

Health effects of HAP exposure from 

310 tons of HAP reduced

Health effects of HAP exposure from 

1,900 tons of HAP reduced

Health effects of ozone exposure from 

170,000 tons of methane

Health effects of ozone exposure from 

340,000 tons of methane

Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes 

of this table, we show the benefits associated with the model average at a 3 percent discount rate. However we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the 

additional benefit estimates range from $88 million to $520 million in 2020 and $220 million to $1,200 million in 

2025 for this less stringent option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.
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Table 1-51-4 Summary of the Monetized Benefits, Costs, and Net Benefits for the More 

Stringent Option Option 3 in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits1 $220 million $640 million

Total Costs2 $210 million $680 million

Net Benefits3 $7.6 million -$35 million

Non-monetized Benefits

Non-monetized climate benefits Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 130,000 tons of VOC 

reduced

Health effects of PM2.5 and ozone 

exposure from 200,000 tons of VOC 

reduced

Health effects of HAP exposure from 

510 tons of HAP reduced

Health effects of HAP exposure from 

3,200 tons of HAP reduced

Health effects of ozone exposure from 

190,000 tons of methane

Health effects of ozone exposure from 

470,000 tons of methane

Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes 

of this table, we show the benefits associated with the model average at a 3 percent discount rate. However we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the 

additional benefit estimates range from $99 million to $590 million in 2020 and $300 million to $1,700 million in 

2025 for this more stringent option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 4.2 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.

1.4 Organization of this Report

The remainder of this report details the methodology and the results of the RIA. Section 2 

presents the industry profile of the oil and natural gas industry. Section 3 describes the emissions 

and engineering cost analysis. Section 4 presents the benefits analysis. Section 5 presents 

statutory and executive order analyses. Section 6 presents a comparison of benefits and costs.

Section 7 presents energy system impact, employment impact, and small entity impact analyses.
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2 INDUSTRY PROFILE

2.1 Introduction 

The oil and natural gas industry includes the following five segments: drilling and 

extraction, processing, transportation, refining, and marketing. The Oil and Natural Gas NSPS

require controls for the oil and natural gas products and processes of the drilling and extraction 

of crude oil and natural gas, natural gas processing, and natural gas transportation segments. 

Most crude oil and natural gas production facilities are classified under NAICS 211: 

Crude Petroleum and Natural Gas Extraction (211111) and Natural Gas Liquid Extraction 

(211112). The drilling of oil and natural gas wells is included in NAICS 213111. Most natural 

gas transmission and storage facilities are classified under NAICS 486210—Pipeline 

Transportation of Natural Gas. While other NAICS (221210—Natural Gas Distribution, 

486110—Pipeline Transportation of Crude Oil, and 541360—Geophysical Surveying and 

Mapping Services) are often included in the oil and natural gas sector, these are not discussed in 

detail in the Industry Profile because they are not directly affected by the proposed NSPS.

The outputs of the oil and natural gas industry are inputs for larger production processes 

of gas, energy, and petroleum products. As of 2013, the Energy Information Administration 

(EIA) estimates that about 490,000 producing natural gas wells operated in the U.S. The latest 

available information from EIA indicates there were about 360,000 producing oil wells in the 

U.S. as of 2009. Domestic dry natural gas production was 24.3 trillion cubic feet (tcf) in 2013, 

the highest annual production level in U.S. history. The leading five natural gas producing states 

are Texas, Pennsylvania, Louisiana, Oklahoma, and Wyoming. Domestic crude oil production in 

2013 was 2,716 million barrels (bbl), the highest annual level in the U.S. since 1991. The leading 

five crude oil producing states are Texas, North Dakota, California, Alaska, and Oklahoma.

The Industry Profile provides a brief introduction to the components of the oil and natural 

gas industry that are relevant to the proposed NSPS. The purpose is to give the reader a general 

understanding of the geophysical, engineering, and economic aspects of the industry that are 

addressed in subsequent economic analysis in this RIA. The Industry Profile relies heavily on 

background material from the U.S. EPA’s “Economic Analysis of Air Pollution Regulations: Oil 

and Natural Gas Production” (1996), the U.S. EPA’s “Sector Notebook Project: Profile of the Oil 
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and Gas Extraction Industry” (2000), and the U.S. EPA’s “Regulatory Impact Analysis: Final 

New Source Performance Standards and Amendments to the National Emissions Standards for 

Hazardous Air Pollutants for the Oil and Natural Gas Industry” (2012).

2.2 Products of the Crude Oil and Natural Gas Industry

Each producing crude oil and natural gas field has its own unique properties. The 

composition of the crude oil and natural gas and reservoir characteristics are likely to be different 

from that of any other reservoir.

2.2.1 Crude Oil

Crude oil can be broadly classified as paraffinic, naphthenic (or asphalt-based), or 

intermediate. Generally, paraffinic crudes are used in the manufacture of lube oils and kerosene.

Paraffinic crudes have a high concentration of straight chain hydrocarbons and are relatively low 

in sulfur compounds. Naphthenic crudes are generally used in the manufacture of gasolines and 

asphalt and have a high concentration of olefin and aromatic hydrocarbons. Naphthenic crudes

may contain a high concentration of sulfur compounds. Intermediate crudes are those that are not 

classified in either of the above categories. 

Another classification measure of crude oil and other hydrocarbons is by API gravity.

API gravity is a weight per unit volume measure of a hydrocarbon liquid as determined by a 

method recommended by the American Petroleum Institute (API). A heavy or paraffinic crude 

oil is typically one with API gravity of 20oor less, while a light or naphthenic crude oil, which 

typically flows freely at atmospheric conditions, usually has API gravity in the range of the high 

30's to the low 40's.

Crude oils recovered in the production phase may be referred to as live crudes. Live 

crudes contain entrained or dissolved gases which may be released during processing or storage.

Dead crudes are those that have gone through various separation and storage phases and contain 

little, if any, entrained or dissolved gases.
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2.2.2 Natural Gas

Natural gas is a mixture of hydrocarbons and varying quantities of non-hydrocarbons that 

exists in a gaseous phase or in solution with crude oil or other hydrocarbon liquids in natural 

underground reservoirs. Natural gas may contain contaminants, such as hydrogen sulfide (H2S), 

CO2, mercaptans, and entrained solids.

Natural gas may be classified as wet gas or dry gas. Wet gas is unprocessed or partially 

processed natural gas produced from a reservoir that contains condensable hydrocarbons. Dry 

gas is either natural gas whose water content has been reduced through dehydration or natural 

gas that contains little or no recoverable liquid hydrocarbons.

Natural gas streams that contain threshold concentrations of H2S are classified as sour 

gases. Those with threshold concentrations of CO2 are classified as acid gases. The process by 

which these two contaminants are removed from the natural gas stream is called sweetening. The 

most common sweetening method is amine treating. Sour gas contains a H2S concentration of 

greater than 0.25 grain per 100 standard cubic feet, along with the presence of CO2. 

Concentrations of H2S and CO2, along with organic sulfur compounds, vary widely among sour 

gases. A majority of total onshore natural gas production and nearly all offshore natural gas 

production is classified as sweet.

2.2.3 Condensates

Condensates are hydrocarbons in a gaseous state under reservoir conditions, but become 

liquid in either the wellbore or the production process. Condensates, including volatile oils, 

typically have an API gravity of 40oor more. In addition, condensates may include hydrocarbon 

liquids recovered from gaseous streams from various oil and natural gas production or natural 

gas transmission and storage processes and operations.

2.2.4 Other Recovered Hydrocarbons

Various hydrocarbons may be recovered through the processing of the extracted 

hydrocarbon streams. These hydrocarbons include mixed natural gas liquids (NGL), natural 

gasoline, propane, butane, and liquefied petroleum gas (LPG).
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2.2.5 Produced Water

Produced water is the water recovered from a production well. Produced water is 

separated from the extracted hydrocarbon streams in various production processes and 

operations.

2.3 Oil and Natural Gas Production Processes

2.3.1 Exploration and Drilling 

Exploration involves the search for rock formations associated with oil or natural gas 

deposits and involves geophysical prospecting and/or exploratory drilling. Well development 

occurs after exploration has located an economically recoverable field and involves the 

construction of one or more wells from the beginning (called spudding) to either abandonment if 

no hydrocarbons are found or to well completion if hydrocarbons are found in sufficient 

quantities.

After the site of a well has been located, drilling commences. A well bore is created by 

using a rotary drill to drill into the ground. As the well bore gets deeper sections of drill pipe are 

added. A mix of fluids called drilling mud is released down into the drill pipe then up the walls 

of the well bore, which removes drill cuttings by taking them to the surface. The weight of the 

mud prevents high-pressure reservoir fluids from pushing their way out (“blowing out”). The 

well bore is cased in with telescoping steel piping during drilling to avoid its collapse and to 

prevent water infiltration into the well and to prevent crude oil and natural gas from 

contaminating the water table. The steel pipe is cemented by filling the gap between the steel 

casing and the wellbore with cement.

Horizontal drilling technology has been available since the 1950s. Horizontal drilling 

facilitates the construction of horizontal wells by allowing for the well bore to run horizontally 

underground, increasing the surface area of contact between the reservoir and the well bore so 

that more oil or natural gas can move into the well. Horizontal wells are particularly useful in 

unconventional gas extraction where the gas is not concentrated in a reservoir. Recent advances 

have made it possible to steer the drill in different directions (directional drilling) from the 
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surface without stopping the drill to switch directions and allowing for a more controlled and 

precise drilling trajectory.

Hydraulic fracturing (also referred to as “fracking”) has been performed since the 1940s

(U.S. DOE, 2013). Hydraulic fracturing involves pumping fluids into the well under very high 

pressures in order to fracture the formation containing the resource. Proppant is a mix of sand 

and other materials that is pumped down to hold the fractures open to secure gas flow from the 

formation (U.S. EPA, 2004).

2.3.2 Production

Production is the process of extracting the hydrocarbons and separating the mixture of 

liquid hydrocarbons, gas, water, and solids, removing the constituents that are non-saleable, and 

selling the liquid hydrocarbons and gas. The major activities of crude oil and natural gas 

production are bringing the fluid to the surface, separating the liquid and gas components, and 

removing impurities.

Oil and natural gas are found in the pores of rocks and sand (Hyne, 2001). In a 

conventional source, the oil and natural gas have been pushed out of these pores by water and 

moved until an impermeable surface had been reached. Because the oil and natural gas can travel 

no further, the liquids and gases accumulate in a reservoir. Where oil and gas are associated, a 

gas cap forms above the oil. Natural gas is extracted from a well either because it is associated 

with oil in an oil well or from a pure natural gas reservoir. Once a well has been drilled to reach

the reservoir, the oil and gas can be extracted in different ways depending on the well pressure

(Hyne, 2001).

Frequently, oil and natural gas are produced from the same reservoir. As wells deplete the 

reservoirs into which they are drilled, the gas to oil ratio increases (as does the ratio of water to 

hydrocarbons). This increase of gas over oil occurs because natural gas usually is in the top of 

the oil formation, while the well usually is drilled into the bottom portion to recover most of the 

liquid. Production sites often handle crude oil and natural gas from more than one well (Hyne, 

2001).
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Well pressure is required to move the resource up from the well to the surface. During

primary extraction, pressure from the well itself drives the resource out of the well directly.

Well pressure depletes during this process. Typically, about 30 to 35 percent of the resource in 

the reservoir is extracted this way (Hyne, 2001). The amount extracted depends on the specific 

well characteristics (such as permeability and oil viscosity). Lacking enough pressure for the 

resource to surface, gas or water is injected into the well to increase the well pressure and force 

the resource out (secondary or improved oil recovery). Finally, in tertiary extraction or

enhanced recovery, gas, chemicals or steam are injected into the well. This can result in 

recovering up to 60 percent of the original amount of oil in the reservoir (Hyne, 2001).

In contrast to conventional sources, unconventional oil and gas are trapped in rock or 

sand or, in the case of oil, are found in rock as a chemical substance that requires a further 

chemical transformation to become oil (U.S. DOE, 2013). Therefore, the resource does not move 

into a reservoir as in the case with a conventional source. Mining, induced pressure, or heat is 

required to release the resource. The specific type of extraction method needed depends on the 

type of formation where the resource is located. Unconventional oil and natural gas resource 

types relevant for this rule include:

 Shale Oil and Natural Gas: Shale natural gas comes from sediments of clay mixed with 

organic matter. These sediments form low permeability shale rock formations that do not 

allow the gas to move. To release the gas, the rock must be fragmented, making the 

extraction process more complex than it is for conventional gas extraction. Shale gas can 

be extracted by drilling either vertically or horizontally, and breaking the rock using 

hydraulic fracturing (U.S. DOE, 2013).

 Tight Sands Natural Gas: Reservoirs are composed of low-porosity sandstones and 

carbonate into which natural gas has migrated from other sources. Extraction of the 

natural gas from tight gas reservoirs is often performed using horizontal wells. Hydraulic 

fracturing is often used in tight sands (U.S. DOE, 2013).

 Coalbed Methane: Natural gas is present in a coal bed due to the activity of microbes in 

the coal or from alterations of the coal through temperature changes. Horizontal drilling 
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is used but given that coalbed methane reservoirs are frequently associated with 

underground water reservoirs, hydraulic fracturing is often restricted (Andrews, 2009).

2.3.3 Natural Gas Processing

Natural gas conditioning is the process of removing impurities from the gas stream so 

that it is of sufficient quality to pass through transportation systems and used by final consumers.

Conditioning is not always required. Natural gas from some formations emerges from the well 

sufficiently pure that it can be sent directly to the pipeline. As the natural gas is separated from 

the liquid components, it may contain impurities that pose potential hazards or other problems. 

The most significant impurity is H2S, which may or may not be contained in natural gas. 

H2S is toxic (and potentially fatal at certain concentrations) to humans and is corrosive for pipes.

It is therefore desirable to remove H2S as soon as possible in the conditioning process.

Another concern is that posed by water vapor. At high pressures, water can react with 

components in the gas to form gas hydrates, which are solids that can clog pipes, valves, and 

gauges, especially at cold temperatures (Manning and Thompson, 1991). Nitrogen and other 

gases may also be mixed with the natural gas in the subsurface. These other gases must be 

separated from the methane prior to sale. High vapor pressure hydrocarbons that are liquids at 

surface temperature and pressure (benzene, toluene, ethylbenzene, and xylene, or BTEX) are 

removed and processed separately.

Dehydration removes water from the gas stream. Three main approaches toward 

dehydration are the use of a liquid or solid desiccant, and refrigeration. When using a liquid 

desiccant, the gas is exposed to a glycol that absorbs the water. The water can be evaporated 

from the glycol by a process called heat regeneration. The glycol can then be reused. Solid 

desiccants, often materials called molecular sieves, are crystals with high surface areas that 

attract the water molecules. The solids can be regenerated simply by heating them above the 

boiling point of water. Finally, particularly for gas extracted from deep, hot wells, simply cooling 

the gas to a temperature below the condensation point of water can remove enough water to 

transport the gas. Of the three approaches mentioned above, glycol dehydration is the most 

common when processing at or near the well.
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Sweetening is the procedure in which H2S and sometimes CO2 are removed from the gas 

stream. The most common method is amine treatment. In this process, the gas stream is exposed 

to an amine solution, which will react with the H2S and separate them from the natural gas. The 

contaminant gas solution is then heated, thereby separating the gases and regenerating the amine.

The sulfur gas may be disposed of by flaring, incinerating, or when a market exists, sending it to 

a sulfur-recovery facility to generate elemental sulfur as a salable product. 

2.3.4 Natural Gas Transmission and Distribution

After processing, natural gas enters a network of compressor stations, high-pressure 

transmission pipelines, and often-underground storage sites. Compressor stations are any facility 

which supplies energy to move natural gas at increased pressure in transmission pipelines or into 

underground storage. Typically, compressor stations are located at intervals along a transmission 

pipeline to maintain desired pressure for natural gas transport. These stations will use either large 

internal combustion engines or gas turbines as prime movers to provide the necessary 

horsepower to maintain system pressure. Underground storage facilities are subsurface facilities 

utilized for storing natural gas which has been transferred from its original location for the 

primary purpose of load balancing, which is the process of equalizing the receipt and delivery of 

natural gas. Processes and operations that may be located at underground storage facilities 

include compression and dehydration.

2.4 Reserves and Markets

Crude oil and natural gas have historically served two separate and distinct markets. Oil 

is an international commodity, transported and consumed throughout the world. Natural gas, on 

the other hand, has historically been consumed close to where it is produced. However, as 

pipeline infrastructure and LNG trade expand, natural gas is increasingly a national and 

international commodity. The following subsections provide historical and forecast data on the

U.S. reserves, production, consumption, and foreign trade of crude oil and natural gas.
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2.4.1 Domestic Proved Reserves

Table 2-1 shows crude oil and dry natural gas proved reserves, unproved reserves, and 

total technically recoverable resources as of 2009. According to EIA10, these concepts are defined 

as:

 Proved reserves: estimated quantities of energy sources that analysis of geologic and 

engineering data demonstrates with reasonable certainty are recoverable under 

existing economic and operating conditions.

 Unproved resources: additional volumes estimated to be technically recoverable 

without consideration of economics or operating conditions, based on the application 

of current technology.

 Total technically recoverable resources: resources that are producible using current 

technology without reference to the economic viability of production.

According to EIA, dry natural gas is consumer-grade natural gas. The dry natural gas volumes 

reported in Table 2-1 reflect the amount of gas remaining after liquefiable portion has been 

removed from the natural gas, as well as any non-hydrocarbon gases that render the natural gas 

unmarketable have been removed. The sum of proved reserves and unproved reserves equal the 

total technically recoverable resources. As seen in Table 2-1, as of 2009, proved domestic crude 

oil reserves accounted for about 10 percent of the totally technically recoverable crude oil 

resources.

 

10 U.S. Department of Energy, Energy Information Administration, Glossary of Terms 

<http://www.eia.doe.gov/glossary/index.cfm?id=P> Accessed 12/21/2010.
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Table 2-1 Technically Recoverable Crude Oil and Natural Gas Resource 

Estimates, 2009

Region Proved Reserves

Unproved 

Resources

Total Technically 

Recoverable 

Resources

Crude Oil and Lease Condensate (billion

barrels)

 48 States Onshore 14.2 112.6 126.7

 48 States Offshore 4.6 50.3 54.8

 Alaska 3.6 35.0 38.6

 Total U.S. 22.3 197.9 220.2

Dry Natural Gas (trillion cubic feet)

 Conventionally Reservoired Fields 105.5 904.0 1,009.5

 48 States Onshore 1/ 81.4 369.7 451.1

 48 States Offshore 15.0 262.6 277.6

 Alaska 9.1 271.7 280.8

Tight Gas, 

Shale Gas and Coalbed Methane 167.1 1,026.7 1,193.8

 Total U.S. 272.5 1,930.7 2,203.3

Source: U.S. Energy Information Administration, Annual Energy Review 2012. Totals may not sum due to 

independent rounding.

1/ Includes associated-dissolved natural gas that occurs in crude oil reservoirs either as free gas (associated) or as gas 

in solution with crude oil (dissolved gas).

Proved natural gas reserves accounted for about 12 percent of the total technically recoverable

natural gas resources. Significant proportions of these reserves exist in Alaska and offshore 

areas. While the dry natural gas proved reserves in 2009 were estimated at 272.5 tcf, wet natural 

gas reserves were estimated at 283.9 tcf. Of the 283.9 tcf, 250.5 tcf (about 88 percent) is 

considered to be wet non-associated natural gas, while 33.3 tcf (about 12 percent) is considered 

to be wet associated-dissolved natural gas. Associated-dissolved natural gas, according to EIA, is 

natural gas which occurs in crude oil reservoirs as free natural gas or in solution with crude oil.

Table 2-2 and Figure 2-1 show trends in crude oil and natural gas production and reserves 

from 1990 to 2013. In Table 2-2, proved ultimate recovery equals the sum of cumulative 

production and proved reserves. While crude oil and natural gas are nonrenewable resources, the 

table shows that proved ultimate recovery rises over time as new discoveries become 
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economically accessible. Reserves growth and decline is also partly a function of exploration 

activities, which are correlated with oil and natural gas prices. For example, when oil prices are 

high there is more of an incentive to use secondary and tertiary recovery, as well as to develop 

unconventional sources. 

Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Production, Proved 

Reserves, and Proved Ultimate Recovery, 1977-2013

 Crude Oil and Lease Condensate (million barrels) Dry Natural Gas (Billion Cubic Feet or bcf)

Cumulative 

Production

Proved

Reserves

Proved Ult.

Recovery

Cumulative

Production

Proved

Reserves

Proved Ult. 

Recovery

1990 158,175 26,254 184,429 744,546 169,346 913,892

1991 160,882 24,682 185,564 762,244 167,062 929,306

1992 163,507 23,745 187,252 780,084 165,015 945,099

1993 166,006 22,957 188,963 798,179 162,415 960,594

1994 168,437 22,457 190,894 817,000 163,837 980,837

1995 170,831 22,351 193,182 835,599 165,146 1,000,745

1996 173,197 22,017 195,214 854,453 166,474 1,020,927

1997 175,552 22,546 198,098 873,355 167,223 1,040,578

1998 177,834 21,034 198,868 892,379 164,041 1,056,420

1999 179,981 21,765 201,746 911,211 167,406 1,078,617

2000 182,112 22,045 204,157 930,393 177,427 1,107,820

2001 184,229 22,446 206,675 950,009 183,460 1,133,469

2002 186,326 22,677 209,003 968,937 186,946 1,155,883

2003 188,388 21,891 210,279 988,036 189,044 1,177,080

2004 190,379 21,371 211,750 1,006,627 192,513 1,199,140

2005 192,270 21,757 214,027 1,024,677 204,385 1,229,062

2006 194,127 20,972 215,099 1,043,181 211,085 1,254,266

2007 195,981 21,317 217,298 1,062,447 237,726 1,300,173

2008 197,811 19,121 216,932 1,082,605 244,656 1,327,261

2009 199,763 20,682 220,445 1,103,229 272,509 1,375,738

2010 201,764 23,267 225,031 1,124,545 304,625 1,429,170

2011 203,825 26,544 230,369 1,147,447 334,067 1,481,514

2012 206,202 30,529 236,731 1,171,480 308,036 1,479,516

2013 208,918 33,371 242,289 1,195,814 338,264 1,534,078

Source: U.S. Energy Information Administration

However, annual production as a percentage of proved reserves has declined over time for both 

crude oil and natural gas, from above 11 percent in the early 1990s to 8 to 10 percent over the 
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period from 2006 to 2013 for crude oil and from above 11 percent during the 1990s to between 7

and 9 percent from 2006 to 2013 for natural gas.

Figure 2-1 A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990-

2013. B) Domestic Natural Gas Proved Reserves and Cumulative Production, 1990-2013

Table 2-3 presents the U.S. proved reserves of crude oil and natural gas by state or 

producing area as of 2013. Five areas currently account for 81 percent of the U.S. total proved 

reserves of crude oil, led by Texas and followed by North Dakota, U.S. Federal Offshore, 

Alaska, and California. The top five states (Texas, Pennsylvania, Wyoming, Oklahoma, and 

West Virginia) account for about 65 percent of the U.S. total proved reserves of natural gas.

0

50,000

100,000

150,000

200,000

250,000

300,000

Crude Oil (million bbl)

A). Crude Oil

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

Natural Gas (bcf)

B). Natural Gas

Cumulative Production Proved Reserves
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Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by State, 2013

State/Region

Crude Oil 

(million bbls)

Dry Natural Gas 

(bcf)

Crude Oil 

(% of total)

Dry Natural Gas 

(% of total)

Alabama 44 1,597 0.1 0.5

Alaska 2,898 7,316 8.7 2.2

Arkansas 40 13,518 0.1 4.0

California 2,876 1,887 8.6 0.6

Colorado 896 22,381 2.7 6.6

Florida 38 15 0.1 0.0

Kansas 372 3,592 1.1 1.1

Kentucky 17 1,663 0.1 0.5

Louisiana 503 20,164 1.5 6.0

Michigan 64 1,807 0.2 0.5

Miscellaneous States 105 2,552 0.3 0.8

Mississippi 223 595 0.7 0.2

Montana 413 575 1.2 0.2

New Mexico 1,171 13,576 3.5 4.0

New York * 144 * 0.0

North Dakota 5,677 5,420 17.0 1.6

Ohio 42 3,161 0.1 0.9

Oklahoma 1,019 26,873 3.1 7.9

Pennsylvania 15 49,674 0.0 14.7

Texas 10,468 90,349 31.4 26.7

U.S. Federal Offshore 5,137 8,193 15.4 2.4

Utah 613 6,829 1.8 2.0

West Virginia 17 22,765 0.1 6.7

Wyoming 723 33,618 2.2 9.9

Total Proved Reserves 33,371 338,264 100.0 100.0

Source: U.S. Energy Information Administration. Total may not sum due to independent rounding.

* New York crude oil reserves are included in miscellaneous states.

2.4.2 Domestic Production

Domestic oil production was in a state of decline that began in 1970 and continued to a 

low point in 2008. Since 2008, domestic oil production has recovered to the highest levels since 

1991. Table 2-4 shows U.S. production in 2013 at 2,716 million bbl per year.
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Table 2-4 Crude Oil Domestic Production, Wells, Well Productivity, and 

U.S. Average First Purchase Price, 1990-2013

Total Production 

(million barrels)

Producing Wells 

(1000s)

Avg. Well 

Productivity 

(bbl/well)

US Average First

Purchase 

Price/Barrel 

(nominal dollars)

US Average First 

Purchase 

Price/Barrel 

(2012 dollars)

1990 2,685 602 4,460 20.03 31.55

1991 2,707 614 4,409 16.54 25.21

1992 2,625 594 4,419 15.99 23.83

1993 2,499 584 4,279 14.25 20.74

1994 2,431 582 4,178 13.19 18.80

1995 2,394 574 4,171 14.62 20.41

1996 2,366 574 4,122 18.46 25.31

1997 2,355 573 4,110 17.23 23.23

1998 2,282 562 4,060 10.87 14.50

1999 2,147 546 3,932 15.56 20.44

2000 2,131 534 3,990 26.72 34.32

2001 2,118 530 3,995 21.84 27.42

2002 2,097 529 3,963 22.51 27.84

2003 2,062 513 4,019 27.56 33.42

2004 1,991 510 3,905 36.77 43.39

2005 1,891 498 3,798 50.28 57.49

2006 1,857 497 3,737 59.69 66.21

2007 1,853 500 3,706 66.52 71.87

2008 1,830 526 3,479 94.04 99.64

2009 1,953 526 3,712 56.35 59.26

2010 2,001 520 3,848 74.71 77.62

2011 2,060 536 3,844 95.73 97.45

2012 2,378 N/A N/A 94.52 94.52

2013 2,716 N/A N/A 95.99 94.58

Source: U.S. Energy Information Administration

First purchase price represents the average price at the lease or wellhead at which domestic crude is purchased.

Prices adjusted using GDP Implicit Price Deflator.

Average well productivity has also generally decreased since 1990 (Table 2-4 and Figure 2-2).

These production and productivity decreases are in spite of the fact that average first purchase

prices have shown a generally increasing trend.

Annual production of natural gas from natural gas wells has increased more than 8000 

bcf from the 1990 to 2013 (Table 2-5Table 2-5). The number of wells producing natural gas has 

nearly doubled between 1990 and 2011 (Figure 2-2). While the number of producing wells has

increased overall, average well productivity has declined, despite improvements in exploration 

and gas well stimulation technologies. 
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Table 2-5 Natural Gas Production and Well Productivity, 1990-2013

Natural Gas Gross Withdrawals 

(Billion Cubic Feet) Natural Gas Well Productivity

Total

Dry Gas 

Production 1

Producing 

Wells

Avg. Well 

Productivity 

Million Cubic 

Feet/Year)

1990 21,523 17,810 269,790 66.0

1991 21,750 17,698 276,987 63.9

1992 22,132 17,840 276,014 64.6

1993 22,726 18,095 282,152 64.1

1994 23,581 18,821 291,773 64.5

1995 23,744 18,599 298,541 62.3

1996 24,114 18,854 301,811 62.5

1997 24,213 18,902 310,971 60.8

1998 24,108 19,024 316,929 60.0

1999 23,823 18,832 302,421 62.3

2000 24,174 19,182 341,678 56.1

2001 24,501 19,616 373,304 52.5

2002 23,941 18,928 387,772 48.8

2003 24,119 19,099 393,327 48.6

2004 23,970 18,591 406,147 45.8

2005 23,457 18,051 425,887 42.4

2006 23,535 18,504 440,516 42.0

2007 24,664 19,266 452,945 42.5

2008 25,636 20,159 476,652 42.3

2009 26,057 20,624 493,100 41.8

2010 26,816 21,316 487,627 43.7

2011 28,479 22,902 514,637 44.5

2012 29,542 24,033 482,822 49.8

2013 30,005 24,334 487,286 49.9
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Figure 2-2 A) Total Producing Crude Oil Wells and Average Well Productivity, 1990-

2011. B) Total Producing Natural Gas Wells and Average Well Productivity, 1990-2013.

Domestic exploration and development for oil has continued during the last two decades.

From 2002 to 2010, crude oil well drilling showed significant increases, although the 1992-2004

period showed relatively low levels of crude drilling activity compared to periods before and 

after (Table 2-6). The drop in 2009 showed a departure from this trend, likely due to the 

recession experienced in the U.S.

Meanwhile, natural gas drilling has increased significantly during the 1990-2010 period.

Like crude oil drilling, 2009 and 2010 saw a relatively low level of natural gas drillings. The

success rate of wells (producing wells versus dry wells) has also increased gradually over time 

from 75 percent in 1990, to 86 percent in 2000, to a peak of 90 percent in 2009 (Table 2-6). The 

increasing success rate reflects improvements in exploration technology, as well as technological 

0

1,000

2,000

3,000

4,000

5,000

0

100

200

300

400

500

600

700

Crude Oil (bbl)/Well

Producing Wells

A). Crude Oil Wells

Producing Wells (1000s) Avg. Well Productivity (bbl/well)

0

100,000

200,000

300,000

400,000

500,000

600,000

0

10

20

30

40

50

60

70

Natural Gas 

(MMcf)/Well

Producing Wells

B). Natural Gas Wells

Avg. Well Productivity (MMcf/year) Producing Wells
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2-17

improvements in well drilling and completion. Similarly, well average depth has also increased 

by during this period (Table 2-6).

Table 2-6 Crude Oil and Natural Gas Exploratory and Development Wells and 

Average Depth, 1990-2010

Wells Drilled

Year Crude Oil Natural Gas Dry Holes Total

Successful 

Wells (%)

Average 

Depth (ft)

1990 12,445 11,126 8,496 32,067 75 4,881

1991 12,035 9,611 7,882 29,528 75 4,920

1992 9,019 8,305 6,284 23,608 75 5,202

1993 8,764 10,174 6,513 25,451 75 5,442

1994 7,001 9,739 5,515 22,255 77 5,795

1995 7,827 8,454 5,319 21,600 77 5,636

1996 8,760 9,539 5,587 23,886 79 5,617

1997 10,445 11,186 5,955 27,586 79 5,691

1998 6,979 11,127 4,805 22,911 80 5,755

1999 4,314 11,121 3,504 18,939 83 5,090

2000 8,090 17,051 4,146 29,287 86 4,961

2001 8,888 22,072 4,598 35,558 87 5,087

2002 6,775 17,342 3,754 27,871 87 5,232

2003 8,129 20,722 3,982 32,833 88 5,426

2004 8,789 24,186 4,082 37,057 89 5,547

2005 10,779 28,590 4,653 44,022 89 5,508

2006 13,385 32,838 5,206 51,429 90 5,613

2007 13,371 32,719 4,981 51,071 90 6,064

2008 16,633 32,246 5,423 54,302 90 5,964

2009* 11,190 18,088 3,525 32,803 90 6,202

2010* 15,753 16,696 4,162 36,611 89 6,108

Source: U.S. Energy Information Administration

* Average Depth values for 2009-2010 are estimates.

Produced water is an important byproduct of the oil and natural gas industry, as 

management, including reuse and recycling, of produced water can be costly and challenging.

Texas, California, Wyoming, Oklahoma, and Kansas were the top five states in terms of 

produced water volumes in 2007 (Table 2-7Table 2-7). These estimates do not include estimates 

of flowback water from hydraulic fracturing activities (ANL 2009).
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Table 2-7 U.S. Onshore and Offshore Oil, Gas, and Produced Water Generation, 2007

State 

Crude Oil

(1000 bbl) 

Total Gas 

(bcf) 

Produced Water

(1000 bbl) 

Total Oil and 

Natural Gas 

(1000 bbls oil 

equivalent) 

Barrels Produced 

Water per Barrel 

Oil Equivalent

Alabama 5,028 285 119,004 55,758 2.13

Alaska 263,595 3,498 801,336 886,239 0.90

Arizona 43 1 68 221 0.31

Arkansas 6,103 272 166,011 54,519 3.05

California 244,000 312 2,552,194 299,536 8.52

Colorado 2,375 1,288 383,846 231,639 1.66

Florida 2,078 2 50,296 2,434 20.66

Illinois 3,202 no data 136,872 3,202 42.75

Indiana 1,727 4 40,200 2,439 16.48

Kansas 36,612 371 1,244,329 102,650 12.12

Kentucky 3,572 95 24,607 20,482 1.20

Louisiana 52,495 1,382 1,149,643 298,491 3.85

Michigan 5,180 168 114,580 35,084 3.27

Mississippi 20,027 97 330,730 37,293 8.87

Missouri 80 no data 1,613 80 20.16

Montana 34,749 95 182,266 51,659 3.53

Nebraska 2,335 1 49,312 2,513 19.62

Nevada 408 0 6,785 408 16.63

New Mexico 59,138 1,526 665,685 330,766 2.01

New York 378 55 649 10,168 0.06

North Dakota 44,543 71 134,991 57,181 2.36

Ohio 5,422 86 6,940 20,730 0.33

Oklahoma 60,760 1,643 2,195,180 353,214 6.21

Pennsylvania 1,537 172 3,912 32,153 0.12

South Dakota 1,665 12 4,186 3,801 1.10

Tennessee 350 1 2,263 528 4.29

Texas 342,087 6,878 7,376,913 1,566,371 4.71

Utah 19,520 385 148,579 88,050 1.69

Virginia 19 112 1,562 19,955 0.08

West Virginia 679 225 8,337 40,729 0.20

Wyoming 54,052 2,253 2,355,671 455,086 5.18

State Total 1,273,759 21,290 20,258,560 5,063,379 4.00

Federal 

Offshore 467,180 2,787 587,353 963,266 0.61

Tribal Lands 9,513 297 149,261 62,379 2.39

Federal Total 476,693 3,084 736,614 1,025,645 0.72

U.S. Total 1,750,452 24,374 20,995,174 6,089,024 3.45

Source: Argonne National Laboratory and Department of Energy (2009). Natural gas production converted to 

barrels oil equivalent to facilitate comparison using the conversion of 0.178 barrels of crude oil equals 1000 

cubic feet natural gas. Totals may not sum due to independent rounding.

As can be seen in Table 2-7Table 2-7, the amount of water produced is not necessarily 

correlated with the ratio of water produced to the volume of oil or natural gas produced. Texas, 
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Alaska and Wyoming were the three largest producers in barrels of oil equivalent (boe) terms, 

but had relatively low rates of water production compared to more Midwestern states such as 

Illinois, Missouri, Indiana, and Kansas. Figure 2-3Figure 2-3 shows the distribution of produced 

water management practices in 2007.

Figure 2-3 U.S. Produced Water Volume by Management Practice, 2007

More than half of the water produced (51 percent) was re-injected to enhance resource recovery 

through maintaining reservoir pressure or hydraulically pushing oil from the reservoir. Another 

third (34 percent) was injected, typically into wells whose primary purpose is to sequester 

produced water. A small percentage (three percent) is discharged into surface water when it 

meets water quality criteria. The destination of the remaining produced water (11 percent, the 

difference between the total managed and total generated) is uncertain (ANL, 2009).

The movement of crude oil and natural gas primarily takes place via pipelines. Total 

crude oil pipeline mileage has decreased during the 1990-2011 period (Table 2-8Table 2-8), 

appearing to follow the downward supply trend shown in Table 2-4Table 2-4. While exhibiting 

some variation, pipeline mileage transporting refined products remained relatively constant.

51%

34%

3%

11%

Injection for

Enhanced Recovery 

Injection or

Disposal 

Surface Discharge 

Unknown

Source: Argonne National Laboratory 
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Table 2-8 U.S. Oil and Natural Gas Pipeline Mileage, 2010-2013

Natural Gas Pipelines (miles)

Distribution 

mains

Distribution 

Service

Transmission 

pipelines Gathering lines Total

2010 1,229,501 872,377 304,775 19,640 2,426,293

2011 1,238,683 881,886 305,036 19,364 2,444,969

2012 1,247,115 892,209 303,333 16,524 2,459,181

2013 1,254,686 894,605 302,827 17,435 2,469,553

Source: U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Office of 

Pipeline Safety, Annual Report Mileage Summary Statistics, available at 

http://phmsa.dot.gov/pipeline/library/data-stats as of December 29, 2014. 

Table 2-8Table 2-8 splits natural gas pipelines into four types: distribution mains, 

distribution service, transmission pipelines, and gathering lines. Gathering lines are low-volume 

pipelines that gather natural gas from production sites to deliver directly to gas processing plants 

or compression stations that connect numerous gathering lines to transport gas primarily to 

processing plants. Transmission pipelines move large volumes of gas to or from processing 

plants to distribution points. From these distribution points, the gas enters a distribution system 

that delivers the gas to final consumers.

2.4.3 Domestic Consumption

Historical crude oil sector-level consumption trends for 1990 through 2012 are shown in 

Table 2-9
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Table 2-9 and Figure 2-4Figure 2-4. Total consumption rose gradually until 2008 when 

consumption dropped as a result of the economic recession. The share of residential, commercial, 

industrial, and electric power on a percentage basis declined during this period, while the share 

of total consumption by the transportation sector rose from 64 percent in 1990 to 71 percent in 

2012.

Table 2-9 Crude Oil Consumption by Sector, 1990-2012

Percent of Total

Total

(million barrels)

Residential and 

Commercial Industrial

Transportation

Sector

Electric 

Power

1990 6,178 7.3 25.1 64.3 3.3

1991 6,068 7.3 24.9 64.7 3.2

1992 6,209 7.1 26.1 64.3 2.6

1993 6,277 6.9 25.3 65.0 2.9

1994 6,439 6.6 26.0 64.8 2.6

1995 6,402 6.4 25.7 66.0 1.9

1996 6,627 6.7 26.1 65.2 2.0

1997 6,726 6.3 26.4 65.1 2.2

1998 6,837 5.7 25.4 65.8 3.1

1999 7,053 6.1 25.6 65.5 2.8

2000 6,984 4.6 25.1 67.6 2.6

2001 6,963 4.6 25.1 67.4 2.9

2002 6,990 4.2 25.2 68.3 2.2

2003 7,091 4.6 24.8 67.9 2.7

2004 7,399 4.4 25.3 67.7 2.6

2005 7,530 5.8 24.2 67.3 2.6

2006 7,506 5.0 24.8 68.9 1.4

2007 7,517 5.1 24.1 69.5 1.4

2008 7,095 5.5 23.0 70.4 1.1

2009 6,849 5.5 22.2 71.4 1.0

2010 6,994 5.2 22.8 71.0 0.9

2011 7,013 5.0 23.2 71.1 0.7

2012 6,902 5.0 23.4 71.1 0.5

Source: U.S. Energy Information Administration.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-22

Figure 2-4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990-

2011

Natural gas consumption has increased over the last twenty years. From 1990 to 2012,

total U.S. consumption increased by an average of about 1 percent per year (Table 2-10 and 

Figure 2-5). Over the same period, industrial consumption of natural gas declined, whereas 

electric power generation increased its consumption quite dramatically, an important trend in the 

industry as many utilities increasingly use natural gas for peak generation or switch from coalbased to natural gas-based electricity generation. The residential, commercial, and transportation 

sectors maintained their consumption levels at more or less constant levels during this time 

period.

0%

10%

20%

30%

40%

50%

60%

70%

80%

Consumption (% of total)

Residential and Commercial Industrial

Transportation Sector Electric Power
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-23

Table 2-10 Natural Gas Consumption by Sector, 1990-2012

Percent of Total

Total (tcf) Residential Commercial Industrial

Electric 

Power Transportation

1990 19.93 22.0 13.1 45.3 16.2 3.3

1991 19.56 23.2 13.9 42.8 17.0 3.1

1992 20.23 23.1 13.8 43.1 17.0 2.9

1993 20.80 23.8 13.8 42.7 16.7 3.0

1994 21.27 22.8 13.6 42.0 18.3 3.2

1995 22.25 21.8 13.6 42.4 19.0 3.2

1996 22.67 23.1 14.0 42.9 16.8 3.2

1997 22.88 21.8 14.1 43.0 17.8 3.3

1998 22.32 20.3 13.4 42.9 20.6 2.9

1999 22.43 21.1 13.6 40.9 21.5 2.9

2000 23.31 21.3 13.6 39.9 22.3 2.8

2001 22.21 21.4 13.6 37.9 24.1 2.9

2002 23.02 21.2 13.7 37.5 24.7 3.0

2003 22.03 23.0 14.4 37.5 22.2 2.8

2004 21.99 22.1 14.2 37.9 23.0 2.7

2005 21.62 22.3 13.9 35.7 25.3 2.9

2006 21.37 20.4 13.2 35.9 27.6 2.9

2007 22.78 20.7 13.2 34.6 28.6 2.9

2008 22.95 21.3 13.7 34.4 27.6 3.0

2009 22.89 20.9 13.6 32.5 29.9 3.1

2010 24.06 19.9 12.9 33.7 30.6 3.0

2011 24.38 19.3 12.9 33.7 31.0 3.0

2012 25.64 16.3 11.3 33.4 36.1 3.0

Source: U.S. Energy Information Administration.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-24

Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-2012

2.4.4 International Trade

Until 2006, net trade of crude oil and refined petroleum products increased, showing 

increased substitution of imports for domestic production, as well as imports satisfying growing 

consumer demand in the U.S. (Table 2-11). Since then, however, imports have been declining 

while exports have been rising, leading to significant declines in net trade or crude oil and 

petroleum products.

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

Consumption (% of total)

Residential Commercial Industrial

Electric Power Transportation
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-25

Table 2-11 Total Crude Oil and Petroleum Products Trade (Million Bbl), 

1990-2013

Imports Exports Net Imports

Crude 

Oil

Petroleum 

Products Total

Crude 

Oil

Petroleum 

Products Total

Crude 

Oil

Petroleum 

Products Total 

1990 2,151 775 2,926 40 273 313 2,112 502 2,614

1991 2,111 673 2,784 42 323 365 2,068 350 2,418

1992 2,226 661 2,887 32 315 348 2,194 345 2,539

1993 2,477 669 3,146 36 330 366 2,441 339 2,780

1994 2,578 706 3,284 36 308 344 2,542 398 2,940

1995 2,639 586 3,225 35 312 346 2,604 274 2,878

1996 2,748 721 3,469 40 319 359 2,708 403 3,110

1997 3,002 707 3,709 39 327 366 2,963 380 3,343

1998 3,178 731 3,908 40 305 345 3,137 426 3,564

1999 3,187 774 3,961 43 300 343 3,144 474 3,618

2000 3,320 874 4,194 18 362 381 3,301 512 3,813

2001 3,405 928 4,333 7 347 354 3,398 581 3,979

2002 3,336 872 4,209 3 356 359 3,333 517 3,849

2003 3,528 949 4,477 5 370 375 3,523 579 4,102

2004 3,692 1119 4,811 10 374 384 3,682 745 4,427

2005 3,696 1310 5,006 12 414 425 3,684 896 4,580

2006 3,693 1310 5,003 9 472 481 3,684 838 4,523

2007 3,661 1255 4,916 10 513 523 3,651 742 4,393

2008 3,581 1146 4,727 10 649 659 3,570 497 4,068

2009 3,290 977 4,267 16 723 739 3,274 255 3,528

2010 3,363 942 4,305 15 843 859 3,348 98 3,446

2011 3,261 913 4,174 17 1073 1,090 3,244 -160 3,084

2012 3,121 758 3,879 25 1148 1,173 3,096 -390 2,706

2013 2,821 777 3,598 49 1273 1,322 2,773 -496 2,277

Source: U.S. Energy Information 

Administration.

Natural gas imports also increased steadily from 1990 to 2007 in volume and percentage 

terms (Table 2-12Table 2-12). The years 2007 through 2012 saw imported natural gas 

constituting a lower percentage of domestic natural gas consumption. Until recent years, industry 

analysts forecast that LNG imports would continue to grow as a percentage of U.S. consumption.

However, it is possible that increasingly accessible domestic unconventional gas resources, such 

as shale gas and coalbed methane, might reduce the need for the U.S. to import natural gas, 

either via pipeline or shipped LNG.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-26

Table 2-12 Natural Gas Imports and Exports, 1990-2013

Total Imports 

(bcf)

Total Exports 

(bcf)

Net Imports

(bcf)

Percent of U.S. 

Consumption

1990 1,532 86 1,447 7.3

1991 1,773 129 1,644 8.4

1992 2,138 216 1,921 9.5

1993 2,350 140 2,210 10.6

1994 2,624 162 2,462 11.6

1995 2,841 154 2,687 12.1

1996 2,937 153 2,784 12.3

1997 2,994 157 2,837 12.4

1998 3,152 159 2,993 13.4

1999 3,586 163 3,422 15.3

2000 3,782 244 3,538 15.2

2001 3,977 373 3,604 16.2

2002 4,015 516 3,499 15.2

2003 3,944 680 3,264 14.8

2004 4,259 854 3,404 15.5

2005 4,341 729 3,612 16.7

2006 4,186 724 3,462 16.2

2007 4,608 822 3,785 16.6

2008 3,984 963 3,021 13.2

2009 3,751 1,072 2,679 11.7

2010 3,741 1,137 2,604 10.8

2011 3,468 1,506 1,962 8.0

2012 3,138 1,619 1,519 5.9

2013 2,883 1,572 1,311 N/A

Source: U.S. Energy Information Administration.

2.4.5 Forecasts

In this section, we provide forecasts of well drilling activity and crude oil and natural gas

domestic production, imports, and prices. The forecasts are from the 2014 Annual Energy 

Outlook produced by EIA, the most current forecast information available from EIA. As will be 

discussed in detail in Section 7, to analyze the impacts of the proposed NSPS on the national 

energy economy, we use the National Energy Modeling System (NEMS) that was used to 

produce the 2014 Annual Energy Outlook.

Table 2-13 present forecasts of successful wells drilled in the U.S. from 2010 to 2040.

Crude oil well forecasts for the lower 48 states show a rise up to the year 2025 then a gradual 

decline until 2040.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-27

Table 2-13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2040

Totals

Year Crude Oil Natural gas

2010 19,316 19,056

2011 23,048 14,355

2012 26,749 11,011

2013 25,248 11,507

2014 22,274 14,099

2015 22,706 14,076

2016 22,552 15,004

2017 22,355 15,773

2018 22,421 18,340

2019 22,525 20,188

2020 24,765 20,396

2021 25,017 23,427

2022 25,400 24,945

2023 25,981 24,999

2024 26,917 24,745

2025 27,763 24,831

2026 26,258 25,445

2027 25,830 26,895

2028 25,270 28,341

2029 24,801 29,019

2030 24,310 28,799

2031 23,972 29,681

2032 23,607 31,406

2033 23,283 31,749

2034 23,057 32,882

2035 22,740 33,278

2036 22,494 33,456

2037 22,343 33,536

2038 22,075 33,944

2039 21,911 34,001

2040 21,750 33,656

Source: U.S. Energy Information Administration, Annual Energy Outlook 2014. 

Meanwhile, show increases for natural gas drilling in the lower 48 states from the present to 

2040, more than doubling during this 25-year period.

Table 2-14Table 2-14 presents forecasts of domestic crude oil production, reserves, 

imports and 6 depicts these trends graphically.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-28

Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2011-2040

Domestic Production (million bbls)

Total 

Domestic

Lower 

48 

Onshore

Lower 

48 

Offshore Alaska

Other 

Crude 

Supply

Net 

Imports

Total 

Crude 

Supply 

(million 

barrels)

Lower 48 

End of 

Year 

Reserves 

(million 

bbls)

Lower 48 

Average 

Wellhead 

Price (2012 

dollars per 

barrel)

2011 2,065 1,336 520 209 97 3,244 7,472 9,161 98.12

2012 2,370 1,679 498 193 32 3,078 7,850 9,018 94.94

2013 2,819 2,132 500 186 85 2,687 8,409 9,360 97.54

2014 3,113 2,396 544 173 59 2,355 8,640 10,054 98.50

2015 3,299 2,534 595 169 0 2,250 8,848 10,224 93.15

2016 3,483 2,581 733 169 0 2,105 9,071 10,957 89.76

2017 3,488 2,598 719 172 0 2,122 9,099 11,073 88.23

2018 3,495 2,607 716 172 0 2,120 9,110 11,228 88.87

2019 3,507 2,620 721 166 0 2,102 9,116 11,410 90.82

2020 3,487 2,632 695 160 0 2,112 9,086 11,599 92.93

2021 3,437 2,632 654 151 0 2,149 9,024 11,652 95.30

2022 3,390 2,624 625 142 0 2,169 8,950 11,721 97.81

2023 3,355 2,610 611 134 0 2,181 8,890 11,830 100.25

2024 3,312 2,594 591 126 0 2,203 8,826 11,898 102.65

2025 3,287 2,570 598 119 0 2,209 8,782 12,050 104.90

2026 3,224 2,517 595 112 0 2,259 8,707 12,192 106.89

2027 3,164 2,474 586 105 0 2,312 8,640 12,237 109.28

2028 3,108 2,429 581 99 0 2,356 8,573 12,299 111.00

2029 3,059 2,381 585 93 0 2,397 8,515 12,367 113.00

2030 3,031 2,330 614 88 0 2,422 8,484 12,564 114.69

2031 2,978 2,284 611 83 0 2,475 8,431 12,585 116.70

2032 2,947 2,237 610 100 0 2,505 8,398 12,612 118.92

2033 2,936 2,195 617 124 0 2,518 8,390 12,650 121.24

2034 2,914 2,155 618 142 0 2,554 8,383 12,642 123.50

2035 2,873 2,114 622 138 0 2,610 8,356 12,622 125.59

2036 2,830 2,068 628 135 0 2,666 8,327 12,618 127.47

2037 2,810 2,028 651 131 0 2,703 8,324 12,687 129.33

2038 2,759 1,987 654 117 0 2,781 8,299 12,656 131.59

2039 2,749 1,949 694 105 0 2,797 8,294 12,859 134.45

2040 2,730 1,909 726 95 0 2,826 8,287 12,938 137.63

Source: U.S. Energy Information Administration, Annual Energy Outlook, 2014

Table 2-14Table 2-14 also shows forecasts of proved reserves in the lower 48 states. The 

reserves forecast shows steady growth from 2010 to 2040, an increase of 25 percent overall. This 

increment is larger than the forecast increase in production from the lower 48 states during this 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-29

period, 12 percent, showing reserves are forecast to grow more rapidly than production. Table 

2-14Table 2-14 also shows average wellhead prices increasing more than 100 percent from 2010 

to 2040, from $76.78 per barrel to $160.38 per barrel in 2011 dollar terms.

Figure 2-5 Forecast of Domestic Crude Oil Production and Net Imports, 2010-2040

Table 2-15 shows domestic natural gas production is forecast to increase until 2040.

Meanwhile, imports of natural gas via pipeline are expected to be eliminated during the forecast 

period, from 1.68 tcf in 2011 to -2.43 in 2040 tcf. Imports of LNG are also eliminated during the 

forecast period, from 0.28 tcf in 2011 to -3.37 tcf in 2040. Total supply, then, increases about 33

percent, from 22.55 tcf in 2011 to 37.54 tcf in 2040. 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Crude Oil (Million bbl)

Total Domestic Net Imports

Lower 48 Onshore Lower 48 Offshore

Alaska
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-30

Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price

2.5 Industry Costs

2.5.1 Finding Costs

Real costs of drilling oil and natural gas wells have increased significantly over the past 

two decades, particularly in recent years. Cost per well has increased by an annual average of 

Dry Gas 

Productio

n

Supplemen

tal Natural 

Gas

Net 

Imports 

(Pipeline)

Net 

Imports 

(LNG)

Total 

Supply

Lower 48 End 

of Year Dry 

Reserves 

(tcf)

Average Henry Hub 

Spot Price (2012 

dollars per million 

Btu)

2011 22.55 0.06 1.68 0.28 24.57 324.6 4.07

2012 24.06 0.06 1.37 0.15 25.64 320.1 2.75

2013 24.19 0.06 1.22 0.12 25.59 329.1 3.60

2014 24.28 0.07 1.21 0.14 25.69 332.5 3.74

2015 24.63 0.06 1.05 0.04 25.78 337.0 3.74

2016 25.68 0.06 0.92 -0.16 26.50 341.8 4.14

2017 26.38 0.06 0.64 -0.61 26.47 344.5 4.40

2018 27.20 0.06 0.45 -1.11 26.61 346.1 4.80

2019 28.19 0.06 0.22 -1.62 26.85 348.6 4.66

2020 29.09 0.06 0.00 -1.93 27.23 352.5 4.38

2021 29.70 0.06 -0.13 -2.17 27.47 354.6 4.67

2022 30.19 0.06 -0.32 -2.17 27.77 358.0 4.82

2023 30.92 0.06 -0.51 -2.37 28.11 362.2 4.96

2024 31.44 0.06 -0.62 -2.57 28.31 365.1 5.12

2025 31.86 0.06 -0.84 -2.57 28.52 368.5 5.23

2026 32.47 0.06 -0.97 -2.77 28.79 372.4 5.36

2027 33.07 0.06 -1.14 -2.97 29.02 375.4 5.49

2028 33.65 0.06 -1.28 -3.17 29.27 378.4 5.59

2029 34.09 0.06 -1.42 -3.35 29.39 380.6 5.78

2030 34.43 0.06 -1.57 -3.37 29.56 382.6 6.03

2031 34.66 0.06 -1.67 -3.37 29.69 385.2 6.17

2032 35.04 0.06 -1.87 -3.37 29.86 387.5 6.36

2033 35.39 0.06 -1.97 -3.37 30.12 389.6 6.59

2034 35.73 0.06 -2.04 -3.37 30.38 391.9 6.74

2035 36.09 0.06 -2.16 -3.37 30.63 393.6 6.92

2036 36.36 0.06 -2.25 -3.37 30.80 394.7 7.18

2037 36.68 0.06 -2.31 -3.37 31.06 397.5 7.23

2038 37.04 0.06 -2.39 -3.37 31.34 399.6 7.26

2039 37.36 0.06 -2.48 -3.37 31.57 401.6 7.42

2040 37.54 0.06 -2.43 -3.37 31.81 402.6 7.65

Domestic Production 

(tcf) Net Imports (tcf)

Source: U.S. Energy Information Administration, Annual Energy Outlook, 2014
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-31

about 15 percent, and cost per foot has increased on average of about 13 percent per year (Figure 

2-6Figure 2-6).

Figure 2-6 Costs of Crude Oil and Natural Gas Wells Drilled, 1981-2008

The average finding costs compiled and published by EIA add an additional level of detail to 

drilling costs, in that finding costs incorporate the costs more broadly associated with adding 

proved reserves of crude oil and natural gas. These costs include exploration and development 

costs, as well as costs associated with the purchase or leasing of real property. EIA publishes

finding costs as running three-year averages, in order to better compare these costs, which occur 

over several years, with annual average lifting costs. Figure 2-7Figure 2-7 shows average 

domestic onshore and offshore and foreign finding costs for the sample of U.S. firms in EIA’s 

Financial Reporting System (FRS) database from 1981 to 2009. The costs are reported in 2009

dollars on a barrel of oil equivalent basis for crude oil and natural gas combined. The average 

domestic finding costs dropped from 1981 until the mid-1990s. Interestingly, in the mid-1990s, 

domestic onshore and offshore and foreign finding costs converged for a few years. After this 

period, offshore finding costs rose faster than domestic onshore and foreign costs.

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

1981 1984 1987 1990 1993 1996 1999 2002 2005 2008

Drilling Costs Per Well ($2005)

0

100

200

300

400

500

600

700

800

Drilling Costs Per Foot ($2005)

Dollars per Well (2005 dollars) Dollars per Foot (2005 dollars)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-32

Figure 2-7 Finding Costs for FRS Companies, 1981-2009

After 2000, average finding costs rose sharply, with the finding costs for domestic onshore and 

offshore and foreign proved reserves diverging onto different trajectories. Note the drilling costs 

in Figure 2-6Figure 2-6 and finding costs in Figure 2-7Figure 2-7 present similar trends overall. 

2.5.2 Lifting Costs

Lifting costs are the costs to produce crude oil or natural gas once the resource has been 

found and accessed. EIA’s definition of lifting costs includes costs of operating and maintaining 

wells and associated production equipment. Direct lifting costs exclude production taxes or 

royalties, while total lifting costs includes taxes and royalties. Like finding costs, EIA reports 

average lifting costs for FRS firms in 2009 dollars on a barrel of oil equivalent basis. Total lifting 

costs are the sum of direct lifting costs and production taxes. Figure 2-8Figure 2-8 depicts direct 

lifting cost trends from 1981 to 2009 for domestic and foreign production.

0

10

20

30

40

50

60

70

80

$2008/boe

U.S. Onshore U.S. Offshore Foreign
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-33

Figure 2-8 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2009 (3-

year Running Average)

Direct lifting costs (excludes taxes and royalties) for domestic production rose a little more than 

$2 per barrels of oil equivalent from 1981 to 1985, then declined almost $5 per barrel of oil 

equivalent from 1985 until 2000. From 2000 to 2009, domestic lifting costs increased sharply, 

just over $8 per barrel of oil equivalent. Foreign lifting costs diverged from domestic lifting costs 

from 1981 to 1991, as foreign lifting costs were lower than domestic costs during this period.

Foreign and domestic lifting costs followed a similar track until they again diverged in 2004, 

with domestic lifting again becoming more expensive. Combined with finding costs, the total 

finding and lifting costs rose significantly in from 2000 to 2009.

2.5.3 Operating and Equipment Costs

The EIA report, “Oil and Gas Lease Equipment and Operating Costs 1994 through 

2009”

11, contains indices and estimated costs for domestic oil and natural gas equipment and 

production operations. The indices and cost trends track costs for representative operations in six 

regions (California, Mid-Continent, South Louisiana, South Texas, West Texas, and Rocky 

 

11 U.S. Energy Information Administration. “Oil and Gas Lease Equipment and Operating Costs 1994 through 

2009.” September 28, 2010. 

<http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/curren

t/coststudy.html> Accessed February 2, 2011.

0

2

4

6

8

10

12

14 $2008/boe

Domestic Foreign
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-34

Mountains) with producing depths ranging from 2000 to 16,000 feet and low to high production 

rates (for example, 50,000 to 1 million cubic feet per day for natural gas). 

Figure 2-9Figure 2-9 depicts crude oil operating costs and equipment costs indices for 

1976 to 2009, as well as the crude oil price in 1976 dollars. The indices show that crude oil 

operating and equipment costs track the price of oil over this time period, while operating costs 

have risen more quickly than equipment costs. Operating and equipment costs and oil prices rose 

steeply in the late 1970s, but generally decreased from about 1980 until the late 1990s.

Figure 2-9 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and 

Crude Oil Price (in 1976 dollars), 1976-200912

Oil costs and prices again generally rose between 2000 to present, with a peak in 2008. The 2009 

index values for crude oil operating and equipment costs are 154 and 107, respectively.

 

12 The last release date for EIA’s Oil and Gas Lease Equipment and Operating Costs analysis was September 2010. 

Updates have been discontinued.

0

20

40

60

80

100

120

140

160

180

200

1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009

Cost Index (1976=100)

0

5

10

15

20

25

30

35

40

45

50

Oil Price ($/bbl, 1976 Dollars)

Crude Oil Operating Costs

Crude Oil Equipment Cost Index

Crude Oil Price ($/bbl, 1976 Dollars)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-35

Figure 2-10 Natural Operating Costs and Equipment Costs Indices (1976=100) and 

Natural Gas Price, 1976-2009

Figure 2-10Figure 2-10 depicts natural gas operating and equipment costs indices, as well as 

natural gas prices. Similar to the cost trends for crude oil, natural gas operating and equipment 

costs track the price of natural gas over this time period, while operating costs have risen more 

quickly than equipment costs. Operating and equipment costs and gas prices also rose steeply in 

the late 1970s, but generally decreased from about 1980 until the mid-1990s. The 2009 index 

values for natural gas operating and equipment costs are 137 and 112, respectively.

2.6 Firm Characteristics

A regulatory action to reduce pollutant discharges from facilities producing crude oil and 

natural gas will potentially affect the business entities that own the regulated facilities. In the oil 

and natural gas production industry, facilities comprise those sites where plant and equipment 

extract, process, and transport extracted streams recovered from the raw crude oil and natural gas

resources. Companies that own these facilities are legal business entities that have the capacity to 

conduct business transactions and make business decisions that affect the facility.

0

20

40

60

80

100

120

140

160

1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009

Cost Index (1976=100)

0

1

1

2

2

3

3

4

4

5

5 Natural Gas Price ($/MMcf, 1976 Dollars)

Natural Gas Operating Costs

Natural Gas Equipment Costs

Natural Gas Price ($/Mcf, 1976 Dollars)
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-36

2.6.1 Ownership

Enterprises in the oil and natural gas industry may be divided into different groups that 

include producers, transporters, and distributors. The producer segment may be further divided

between major and independent producers. Major producers include large oil and gas companies 

that are involved in each of the five industry segments: drilling and exploration, production, 

transportation, refining, and marketing. Independent producers include smaller firms that are 

involved in some but not all of the five activities.

According to the Independent Petroleum Association of America (IPAA), independent 

companies produce approximately 68 percent of domestic crude oil production of our oil, 85 

percent of domestic natural gas, and drill almost 90 percent of the wells in the U.S (IPAA, 2009).

Through the mid-1980s, natural gas was a secondary fuel for many producers. However, now it 

is of primary importance to many producers. IPAA reports that about 50 percent of its members’ 

spending in 2007 was directed toward natural gas production, largely toward production of 

unconventional gas (IPAA, 2009). Meanwhile, transporters are comprised of the pipeline 

companies, while distributors are comprised of the local distribution companies.

2.6.2 Size Distribution of Firms in Affected NAICS

As of 2014, there were 6,659 firms within the 211111 and 211112 NAICS codes, of 

which 6,535 (98 percent) were considered small entities (Table 2-16). Within NAICS 211111 

and 211112, large firms compose about 2 percent of the firms, but account for about 60 percent 

of employment listed under these NAICS. 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-37

Table 2-16 SBA Size Standards and Size Distribution of Oil and Natural Gas Firms

NAICS NAICS Description

SBA Size Standard 

(Employees or 

Annual Receipts)

Small 

Firms 

Large 

Firms

Total 

Firms

Number of Firms by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 500 6,436 87 6,523

211112 Natural Gas Liquid Extraction 500 99 37 136

213111 Drilling Oil and Gas Wells 500 1,993 48 2,041

213112 Support Activities for Oil and Gas Operations $38.5 million N/A N/A 8,119

486210 Pipeline Transportation of Natural Gas $27.5 million N/A N/A 107

Total Employment by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 500 45,641 63,313 108,954

211112 Natural Gas Liquid Extraction 500 1,733 8,272 10,005

213111 Drilling Oil and Gas Wells 500 36,663 57,843 94,506

213112 Support Activities for Oil and Gas Operations $38.5 million N/A N/A 219,827

486210 Pipeline Transportation of Natural Gas $27.5 million N/A N/A 27,151

Source: U.S. Small Business Administration Office of Advocacy. 2014.

Firm Size Data. <Available at https://www.sba.gov/advocacy/firm-size-data> Accessed January 5, 2015.

Note: "N/A" indicates where national counts of small and large firms could not be performed.

The small and large firms within NAICS 21311 are similarly distributed, with large firms 

accounting for about 2 percent of firms, but 61 percent of employment. Because there are 

relatively few firms within NAICS 486210, the Census Bureau cannot release breakdowns of 

firms by size in sufficient detail to perform similar calculation.

2.6.3 Trends in National Employment and Wages

As well as producing much of the U.S. energy supply, the oil and natural gas industry 

directly employs a significant number of people. Table 2-17Table 2-17 shows employment in oil 

and natural gas-related NAICS codes from 1990 to 2013. The overall trend shows a decline in 

total industry employment throughout the 1990s, hitting a low of 314,000 in 1999, but 

rebounding to a 2013 peak of 620,000. Crude Petroleum and Natural Gas Extraction (NAICS 

211111) and Support Activities for Oil and Gas Operations (NAICS 213112) employ the 

majority of workers in the industry.
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Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-2013

Crude 

Petroleum 

and Natural 

Gas 

Extraction 

(NAICS 

211111)

Natural Gas 

Liquid 

Extraction 

(NAICS 

211112)

Drilling of 

Oil and 

Natural Gas 

Wells 

(NAICS 

213111)

Support 

Activities 

for Oil and 

Gas Ops. 

(NAICS 

213112)

Pipeline 

Trans. of 

Crude Oil 

(NAICS 

486110)

Pipeline 

Trans. of 

Natural Gas 

(NAICS 

486210) Total

1990 182,848 8,260 52,365 109,497 11,112 47,533 411,615

1991 177,803 8,443 46,466 116,170 11,822 48,643 409,347

1992 169,615 8,819 39,900 99,924 11,656 46,226 376,140

1993 159,219 7,799 42,485 102,840 11,264 43,351 366,958

1994 150,598 7,373 44,014 105,304 10,342 41,931 359,562

1995 142,971 6,845 43,114 104,178 9,703 40,486 347,297

1996 139,016 6,654 46,150 107,889 9,231 37,519 346,459

1997 137,667 6,644 55,248 117,460 9,097 35,698 361,814

1998 133,137 6,379 53,943 122,942 8,494 33,861 358,756

1999 124,296 5,474 41,868 101,694 7,761 32,610 313,703

2000 117,175 5,091 52,207 108,087 7,657 32,374 322,591

2001 119,099 4,500 62,012 123,420 7,818 33,620 350,469

2002 116,559 4,565 48,596 120,536 7,447 31,556 329,259

2003 115,636 4,691 51,526 120,992 7,278 29,684 329,807

2004 117,060 4,285 57,332 128,185 7,073 27,340 341,275

2005 121,535 4,283 66,691 145,725 6,945 27,341 372,520

2006 130,188 4,670 79,818 171,127 7,202 27,685 420,690

2007 141,239 4,842 84,525 197,100 7,975 27,431 463,112

2008 154,898 5,183 92,640 223,635 8,369 27,080 511,805

2009 155,150 5,538 67,756 193,589 8,753 26,753 457,539

2010 153,490 4,833 74,491 201,685 8,893 26,708 470,100

2011 164,900 5,835 87,272 241,490 8,959 27,320 535,776

2012 181,473 6,529 92,340 282,447 9,348 27,595 599,732

2013 189,804 6,928 93,261 296,891 10,059 26,981 623,924

Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2013 , 

<http://www.bls.gov/cew/>

From 1990 to 2013, average wages for the oil and natural gas industry have increased.

Table 2-18Table 2-18 shows real wages (in 2012 dollars) from 1990 to 2013 for the NAICS 

codes associated with the oil and natural gas industry.
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Table 2-18 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2013 (2012

dollars)

Crude 

Petroleum 

and Natural 

Gas 

Extraction 

(211111)

Natural Gas 

Liquid 

Extraction 

(211112)

Drilling of 

Oil and 

Natural 

Gas Wells 

(213111)

Support 

Activities 

for Oil and 

Gas Ops. 

(213112)

Pipeline 

Trans. of 

Crude Oil 

(486110)

Pipeline 

Trans. of 

Natural 

Gas 

(486210) Total

1990 74,475 69,877 44,193 48,010 71,231 64,452 62,245

1991 75,980 69,993 45,593 49,578 72,277 68,228 63,886

1992 80,222 72,285 45,683 51,355 77,941 70,472 67,435

1993 81,214 72,237 47,486 52,649 76,445 70,777 67,734

1994 82,976 74,277 46,717 52,565 79,790 71,804 68,058

1995 85,341 70,873 48,462 53,294 82,717 75,418 69,634

1996 88,319 72,256 51,256 55,400 80,589 80,103 71,727

1997 94,309 83,369 54,754 58,343 82,305 86,858 75,355

1998 97,870 94,427 55,692 60,445 83,028 88,367 77,393

1999 103,235 93,852 57,216 62,756 86,626 99,119 82,969

2000 115,018 117,477 63,787 63,505 84,994 136,907 90,990

2001 116,417 116,513 64,792 64,298 87,363 128,243 89,416

2002 115,314 108,703 65,226 62,847 91,763 96,010 86,240

2003 116,161 118,322 64,095 64,368 91,788 96,109 86,714

2004 127,324 124,374 66,251 65,672 98,381 98,485 90,960

2005 133,920 134,419 74,486 70,753 96,906 95,017 95,030

2006 145,658 140,685 78,047 74,085 96,693 104,055 100,084

2007 143,266 140,329 86,705 76,099 101,516 111,476 101,724

2008 153,155 132,582 86,845 78,432 107,836 105,127 105,011

2009 141,752 131,508 85,854 74,579 106,188 106,598 102,193

2010 152,074 131,980 86,297 77,774 108,855 112,857 106,522

2011 156,035 120,939 91,885 81,441 114,710 116,266 108,863

2012 155,735 136,352 92,266 80,222 120,292 139,127 108,872

2013 153,095 122,787 92,737 80,516 116,215 116,621 107,028

Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2013, annual wages per 

employee <http://www.bls.gov/cew/>

Employees in the NAICS 211 codes earn the highest average wages in the oil and natural 

gas industry, while employees in the NAICS 213 codes have relatively lower wages. Average 

wages in natural gas pipeline transportation show the highest variation.

2.6.4 Horizontal and Vertical Integration

Because of the existence of major companies, the industry possesses a wide dispersion of 

vertical and horizontal integration. The vertical aspects of a firm’s size reflect the extent to which 

goods and services that can be bought from outside are produced in house, while the horizontal 
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aspect of a firm’s size refers to the scale of production in a single-product firm or its scope in a 

multiproduct one. Vertical integration is a potentially important dimension in analyzing firmlevel impacts because the regulation could affect a vertically integrated firm on more than one 

level. The regulation may affect companies for whom oil and natural gas production is only one 

of several processes in which the firm is involved. For example, a company that owns oil and 

natural gas production facilities may ultimately produce final petroleum products, such as motor 

gasoline, jet fuel, or kerosene. This firm would be considered vertically integrated because it is 

involved in more than one level of requiring crude oil and natural gas and finished petroleum 

products. A regulation that increases the cost of oil and natural gas production will ultimately 

affect the cost of producing final petroleum products.

Horizontal integration is also a potentially important dimension in firm-level analyses for 

any of the following reasons. A horizontally integrated firm may own many facilities of which 

only some are directly affected by the regulation. Additionally, a horizontally integrated firm 

may own facilities in unaffected industries. This type of diversification would help mitigate the 

financial impacts of the regulation. A horizontally integrated firm could also be indirectly as well 

as directly affected by the regulation. 

In addition to the vertical and horizontal integration that exists among the large firms in 

the industry, many major producers often diversify within the energy industry and produce a 

wide array of products unrelated to oil and gas production. As a result, some of the effects of

regulation of oil and gas production can be mitigated if demand for other energy sources moves 

inversely compared to petroleum product demand.

In the natural gas sector of the industry, vertical integration is less predominant than in 

the oil sector. Transmission and local distribution of natural gas usually occur at individual firms, 

although processing is increasing performed by the integrated major companies. Several natural 

gas firms operate multiple facilities. However, natural gas wells are not exclusive to natural gas 

firms only. Typically wells produce both oil and gas and can be owned by a natural gas firm or 

an oil company.

Unlike the large integrated firms that have several profit centers such as refining, 

marketing, and transportation, most independents have to rely only on profits generated at the 
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wellhead from the sale of oil and natural gas or the provision of oil and gas production-related 

engineering or financial services. Overall, independent producers typically sell their output to 

refineries or natural gas pipeline companies and are not vertically integrated. Independents may 

also own relatively few facilities, indicating limited horizontal integration.

2.6.5 Firm-level Information

The annual Oil and Gas Journal (OGJ) survey, the OGJ150, reports financial and 

operating results for public oil and natural gas companies with domestic reserves and 

headquarters in the U.S. In the past, the survey reported information on the top 300 companies, 

now the top 150. In 2012, 134 public companies are listed; in 2011there were 145 firms.

13 The 

2012 list contains four companies that were not on the list in the previous year. Also, 10 other 

companies listed in 2011do not appear on the 2012 list as a result of mergers, bankruptcies, or 

other reasons. Table 2-19Table 2-19 lists selected statistics for the top 20 companies in 2012. 

The results presented in the table reflect a decline in U.S. natural gas and natural gas liquids 

prices, weak energy demand growth, and increased capital and operating costs in 2012. 

Net income for the top 134 companies fell between 2011 and 2012 from $114.5 billion to 

$91.1 billion. Revenues for these companies fell 1.4 percent from 2011 to 2012. Even though 

earnings decreased in 2012, strong earnings from 2011 boosted available financial resources and 

the companies continued to invest. Capital and exploratory spending for the companies in 2012 

totaled $206.5 billion, up 17.1 from 2011.

The total worldwide liquids production for the 134 firms increased 6.85 percent to 2.879

billion bbl, while total worldwide gas production increased 2.4 percent to a total of 17.4 tcf (Oil 

and Gas Journal, September 2, 2013). Meanwhile, the 134 firms on the OGJ list increased both 

oil and natural gas production and reserves from 2011 to 2012. Domestic production of liquids 

increased about 19.8 percent from 2011 to 1.437 billion bbl, and natural gas production was up 

about 6.3 percent. For context, the OGJ150 domestic crude production represents about 49

percent of total domestic production (2.06 billion bbl, according to EIA). The OGJ150 natural 

gas production represents about 69 percent of total domestic production (28.5 tcf, according to 

 

13 Oil and Gas Journal. “OGJ150 Earnings Down as US Production Climbs.” September 2, 2013.
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EIA).

The OGJ also releases a period report entitled “Worldwide Gas Processing Survey”, 

which provides a wide range of information on existing processing facilities. We used a recent 

list of U.S. gas processing facilities (Oil and Gas Journal, June 7, 2010) and other resources, 

such as the American Business Directory and company websites, to best identify the parent 

company of the facilities. As of 2009, there are 579 gas processing facilities in the U.S., with a 

processing capacity of 73,767 million cubic feet per day and throughout of 45,472 million cubic 

feet per day (Table 2-20). The overall trend in U.S. gas processing capacity is showing fewer, but 

larger facilities. For example, in 1995, there were 727 facilities with a capacity of 60,533 million 

cubic feet per day (U.S. DOE, 2006).

Trends in gas processing facility ownership are also showing a degree of concentration, 

as large firms own multiple facilities, which also tend to be relatively large facilities (Table 

2-20). While we estimate 142 companies own the 579 facilities, the top 20 companies (in terms 

of total throughput) own 264 or 46 percent of the facilities. That larger companies tend to own 

larger facilities is indicated by these top 20 firms owning 86 percent of the total capacity and 88 

percent of actual throughput.
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Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012

Worldwide 

Production

US 

Production

Rank by 

Total 

Assets Company Employees

Total 

Assets

($Million)

Total 

Revenue 

($Million)

Net 

Income 

($Million)

Liquids 

(Million 

bbl)

Natural 

Gas 

(Bcf)

Liquids 

(Million 

bbl)

Natural 

Gas 

(Bcf)

Net 

Wells 

Drilled

1 ExxonMobil Corp. 76,900 333,795 482,295 47,681 625 2,992 166 1,518 1,411

2 Chevron Corp. 17,418 232,982 241,909 26,336 536 1,737 151 1,129 1,272

3 ConocoPhillips 16,900 117,144 62,004 8,498 271 1,539 120 916 1,163

4 Occidental Petroleum Corp. 12,300 64,210 24,253 4,598 201 1129 100 752 1,016

5 Apache Corp. 5,976 60,737 17,078 2,001 145 938 84 685 958

6 Anadarko Petroleum Corp. 5,200 52,589 13,411 2,445 115 916 75 565 951

7 Hess Corp. 14,775 43,441 38,373 2,063 110 839 61 440 826

8 Devon Energy Corp. 5,700 43,326 9,502 -206 103 565 57 407 769

9 Chesapeake Energy Corp. 12,000 41,611 12,316 -594 93 557 49 380 751

10 Marathon Oil Corp. 3,367 35,306 16,221 1582 78 470 45 380 699

11 EOG Resources Inc. 2,650 27,337 11,683 570 49 416 39 313 513

12 Noble Energy Inc. 2,190 17,554 4,223 1027 42 380 34 300 492

13 Murphy Oil Corp. 9,185 17,523 28,626 971 41 322 26 259 468

14 Plains Exploration and 

Production Co 906 17,298 2,565 343 34 284 25 253 439

15 Pioneer Natural Resources Co. 3,667 13,069 3,228 243 26 259 24 249 367

16 Linn Energy LLC 1,136 11,451 1,774 -387 25 253 24 249 334

17 Denbury Resources Inc. 1,432 11,139 2,456 525 24 249 24 183 315

18 Sandridge Energy Inc. 2,510 9,791 2,731 247 24 249 20 161 297

19 WPX Energy Inc. 1,200 9,456 3,189 -211 22 244 18 160 271

20 Continental Resources Inc. 753 9,140 2,573 416 20 183 18 156 263

Source: Oil and Gas Journal. “OGJ150 Earnings Down as US Production Climbs.” September 2, 2013. The annual Oil and Gas Journal (OGJ) survey, the 

OGJ150, reports financial and operating results for public oil and natural gas companies with domestic reserves and headquarters in the U.S.

Notes: The source for employment figures is Hoovers, a D&B Company.
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Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009

Rank Company

Processing 

Plants (No.)

Natural Gas 

Capacity 

(MMcf/day)

Natural Gas 

Throughput 

(MMcf/day)

1 BP PLC 19 13,378 11,420

2 DCP Midstream Inc. 64 9,292 5,586

3 Enterprise Products Operating LP— 23 10,883 5,347

4 Targa Resources 16 4,501 2,565

5 Enbridge Energy Partners LP— 19 3,646 2,444

6 Williams Cos. 10 4,826 2,347

7 Martin Midstream Partners 16 3,384 2,092

8 Chevron Corp. 23 1,492 1,041

9 Devon Gas Services LP 6 1,038 846

10 ExxonMobil Corp. 6 1,238 766

11 Occidental Petroleum Corp 7 776 750

12 Kinder Morgan Energy Partners 9 1,318 743

13 Enogex Products Corp. 8 863 666

14 Hess Corp. 3 1,060 613

15 Norcen Explorer 1 600 500

16 Copano Energy 1 700 495

17 Anadarko 18 816 489

18 Oneok Field Services 10 1,751 472

19 Shell 4 801 446

20 DTE Energy 1 800 400

TOTAL FOR TOP 20 264 63,163 40,028

TOTAL FOR ALL COMPANIES 579 73,767 45,472

Source: Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas 

Processing Capacity Ahead in 2009.” June 7, 2010, with additional analysis to determine ultimate ownership of 

plants.

The OGJ also issues a periodic report on the economics of the U.S. pipeline industry.

This report examines the economic status of all major and non-major natural gas pipeline 

companies, which amounts to 162 companies in 2011 (Oil and Gas Journal, September 2, 2013).

Table 2-21 presents the pipeline mileage, volumes of natural gas transported, operating revenue, 

and net income for the top 20 U.S. natural gas pipeline companies in 2012. Ownership of gas 

pipelines is mostly independent from ownership of oil and gas production companies, as is seen 

from the lack of overlap between the OGJ list of pipeline companies and the OGJ150. This 

observation shows that the pipeline industry is still largely based upon firms serving regional 

market.

The top 20 companies maintain about 61 percent of the total pipeline mileage and 

transport about 56 percent of the volume of the industry (Table 2-21). Operating revenues of the 
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top 20 companies equaled $12.1 billion, representing 59 percent of the total operating revenues 

for major and non-major companies. The top 20 companies also account for 59 percent of the net 

income of the industry.

Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2012

Rank Company

Transmission 

(miles)

Vol. trans 

for others 

(MMcf)

Operating 

Revenue 

($000s)

Net 

Income 

($000s)

1 Dominion Transmission Inc. 3,687 653,272 903,404 256,010

2 Texas Eastern Transmission LP 9,563 1,747,856 956,536 242,277

3 Florida Gas Transmission Co. LLC 5,336 979,857 775,375 204,968

4 Transcontinental Gas Pipe Line Co. LLC 9,378 3,274,209 1,254,154 194,573

5 Tennessee Gas Pipeline Co. 13,780 2,626,030 1,015,928 190,970

6 Columbia Gas Transmission LLC 9,708 1,305,728 813,185 186,594

7 Natural Gas Pipeline Co of America 8,911 1,511,844 687,366 176,447

8 Southern Natural Gas Co. 7,079 1,005,151 584,828 162,275

9 ETC Tiger Pipeline LLC 196 546,137 279,572 134,934

10 Northern Natural Gas Co. 14,949 928,977 587,768 134,715

11 Panhandle Eastern Pipe Line Co., LP 6,406 581,926 338,787 123,392

12 Texas Gas Transmission LLC 5,880 1,052,070 417,809 106,994

13 Kern River Gas Transmission Co. 1,718 928,206 383,393 105,447

14 Rockies Express Pipeline LLC 1,698 822,587 786,225 103,427

15 CenterPoint Energy Gas Transmission Co., 

LLC 5,954 1,143,552 437,836 103,290

16 Colorado Interstate Gas Co. 4,253 788,905 397,292 100,902

17 Dominion Cove Point LNG, LP 136 82989 281,517 97,192

18 Gulf South Pipeline Co., LP 6,484 1,115,618 470,149 93,816

19 Northern Border Pipeline Co. 1,408 1,008,857 310,869 89,767

20 Northwest Pipeline GP 3,906 658,161 437,835 87,119

TOTAL FOR TOP 20 120,430 22,761,932 12,119,828 2,895,109

TOTAL FOR ALL COMPANIES 198,279 40,759,824 20,545,763 4,888,125

Source: Oil and Gas Journal. “US Pipeline Operators Sink Revenue Growth into Expansion.” September 2, 

2013.

2.6.6 Financial Performance and Condition

From a broad industry perspective, the EIA Financial Reporting System (FRS) collects 

financial and operating information from a subset of the U.S. major energy producing companies

and reports summary information in the publication “The Performance Profiles of Major Energy 

Producers”.

14 This information is used in annual report to Congress, as well as is released to the 

 

14 The “Performance Profiles of Major Energy Producers 2009” released on February 25, 2011 is the most recent 

release of this report.
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public in aggregate form. While the companies that report information to FRS each year changes, 

EIA makes an effort to retain sufficient consistency such that trends can be evaluated. For 2009, 

there are 30 companies in the FRS15 that accounted for 43 percent of total U.S. crude oil and 

NGL production, 43 percent of natural gas production, 78 percent of U.S. refining capacity, and 

0.3 percent of U.S. electricity net generation (U.S. EIA, 2011). Table 2-22 shows a series of 

financial trends in 2008 dollars selected and aggregated from FRS firms’ financial statements.

The table shows operating revenues and expenses rising significantly from 1990 to 2008, with 

operating income (the difference between operating revenues and expenses) rising until dropping 

off significantly in 2009. Interest expenses remained relatively flat during this period.

Meanwhile, recent years have shown that other income and income taxes have played a more 

significant role for the industry. Net income has risen as well, although 2008 and 2009 saw a 

decline from previous periods, as oil and natural gas prices declined significantly during the 

latter half of 2008.

 

15 Alenco, Alon USA, Anadarko Petroleum Corporation, Apache Corporation, BP America, Inc., Chalmette, 

Chesapeake Energy Corporation, Chevron Corporation, CITGO Petroleum Corporation, ConocoPhillips, Devon 

Energy Corporation, El Paso Corporation, EOG Resources, Inc., Equitable Resources, Inc., Exxon Mobil 

Corporation, Hess Corporation, Hovensa, Lyondell Chemical Corporation, Marathon Oil Corporation, Motiva 

Enterprises, L.L.C., Occidental Petroleum Corporation, Shell Oil Company, Sunoco, Inc., Tesoro Petroleum 

Corporation, The Williams Companies, Inc., Total Holdings USA, Inc., Valero Energy Corp., Western 

Refining, WRB Refining LLC, and XTO Energy, Inc.
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Table 2-22 Selected Financial Items from Income Statements (Billion 2008 Dollars)

Year

Operating 

Revenues

Operating 

Expenses

Operating 

Income

Interest 

Expense

Other 

Income*

Income 

Taxes Net Income

1990 766.9 706.4 60.5 16.8 13.6 24.8 32.5

1991 673.4 635.7 37.7 14.4 13.4 15.4 21.3

1992 670.2 637.2 33.0 12.7 -5.6 12.2 2.5

1993 621.4 586.6 34.8 11.0 10.3 12.7 21.5

1994 606.5 565.6 40.9 10.8 6.8 14.4 22.5

1995 640.8 597.5 43.3 11.1 12.9 17.0 28.1

1996 706.8 643.3 63.6 9.1 13.4 26.1 41.8

1997 673.6 613.8 59.9 8.2 13.4 23.9 41.2

1998 614.2 594.1 20.1 9.2 11.0 6.0 15.9

1999 722.9 682.6 40.3 10.9 12.7 13.6 28.6

2000 1,114.3 1,011.8 102.5 12.9 18.4 42.9 65.1

2001 961.8 880.3 81.5 10.8 7.6 33.1 45.2

2002 823.0 776.9 46.2 12.7 7.9 17.2 24.3

2003 966.9 872.9 94.0 10.1 19.5 37.2 66.2

2004 1,188.5 1,051.1 137.4 12.4 20.1 54.2 90.9

2005 1,447.3 1,263.8 183.5 11.6 34.6 77.1 129.3

2006 1,459.0 1,255.0 204.0 12.4 41.2 94.8 138.0

2007 1,475.0 1,297.7 177.3 11.1 47.5 86.3 127.4

2008 1,818.1 1,654.0 164.1 11.4 32.6 98.5 86.9

2009 1,136.8 1,085.9 50.8 10.8 18.7 29.5 29.3

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System). * Other Income

includes other revenue and expense (excluding interest expense), discontinued operations, extraordinary items, 

and accounting changes. Totals may not sum due to independent rounding.

Table 2-23 shows in percentage terms the estimated return on investments for a variety of 

business lines, in 1998, 2003, 2008, and 2009 for FRS companies. For U.S. petroleum-related 

business activities, oil and natural gas production was the most profitable line of business 

relative to refining/marketing and pipelines, sustaining a return on investment greater than 10 

percent in 1998, 2003, and 2008, with a significant decrease in 2009. Returns to foreign oil and 

natural gas production rose above domestic production in 2008 and 2009. Electric power 

generation and sales emerged in 2008 as a highly profitable line of business for the FRS 

companies and declined significantly in 2009.
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Table 2-23 Return on Investment for Lines of Business (all FRS), for 1998, 2003, 2008, 

and 2009 (percent)

Line of Business 1998 2003 2008 2009

Petroleum 10.8 13.4 12.0 4.5

 U.S. Petroleum 10 13.7 8.2 0.4

 Oil and Natural Gas Production 12.5 16.5 10.7 3.5

 Refining/Marketing 6.6 9.3 2.6 -6.6

 Pipelines 6.7 11.5 2.4 4.7

 Foreign Petroleum 11.9 13.0 17.8 10.3

 Oil and Natural Gas Production 12.5 14.2 16.3 11

 Refining/Marketing 10.6 8.0 26.3 5.8

Downstream Natural Gas* - 8.8 5.1 9.6

Electric Power - 5.2 181.4 -32

Other Energy 7.1 2.8 -2.1 5.1

Non-energy 10.9 2.4 -5.3 2.8

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System). Note: Return on 

investment measured as contribution to net income/net investment in place. * The downstream natural gas and 

electric power lines of business were added to the EIA-28 survey form beginning with the 2003 reporting year.

The oil and natural gas industry also produces significant tax revenues for local, state, 

and federal authorities. Table 2-24 shows income and production tax trends from 1990 to 2009

for FRS companies. The column with U.S. federal, state, and local taxes paid or accrued includes 

deductions for the U.S. Federal Investment Tax Credit ($198 million in 2008)16 and the effect of 

the Alternative Minimum Tax ($34 million in 2008). Income taxes paid to state and local 

authorizes were $3,060 million in 200813, about 13 percent of the total paid to U.S. authorities.

 

16 Data was withheld in 2009 to avoid disclosure.
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Table 2-24 Income and Production Taxes, 1990-2009 (Million 2008 Dollars)

Year

US Federal, State, 

and Local Taxes 

Paid or Accrued Total Current Total Deferred

Total Income 

Tax Expense

Other 

Production 

Taxes Paid

1990 9,568 25,056 -230 24,826 4,341

1991 6,672 18,437 -3,027 15,410 3,467

1992 4,994 16,345 -4,116 12,229 3,097

1993 3,901 13,983 -1,302 12,681 2,910

1994 3,348 13,556 887 14,443 2,513

1995 6,817 17,474 -510 16,965 2,476

1996 8,376 22,493 3,626 26,119 2,922

1997 7,643 20,764 3,141 23,904 2,743

1998 1,199 7,375 -1,401 5,974 1,552

1999 2,626 13,410 140 13,550 2,147

2000 14,308 36,187 6,674 42,861 3,254

2001 10,773 28,745 4,351 33,097 3,042

2002 814 17,108 46 17,154 2,617

2003 9,274 30,349 6,879 37,228 3,636

2004 19,661 50,185 4,024 54,209 3,990

2005 29,993 72,595 4,529 77,125 5,331

2006 29,469 85,607 9,226 94,834 5,932

2007 28,332 84,119 2,188 86,306 7,501

2008 23,199 95,590 2,866 98,456 12,507

2009* -1,655 35,478 -5,988 29,490 -173

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System). 

*In 2009, data on the U.S. Federal Investment Tax Credit and U.S. State and Local Income Taxes were withheld to 

avoid disclosure.

The difference between total current taxes and U.S. federal, state, and local taxes in 

includes taxes and royalties paid to foreign countries. As can be seen in Table 2-24, foreign taxes 

paid far exceeds domestic taxes paid. Other non-income production taxes paid, which have risen 

almost three-fold between 1990 and 2008, include windfall profit and severance taxes, as well as 

other production-related taxes.

2.7 References

Andrews, et al. 2009. Unconventional Gas Shales: Development, Technology, and Policy Issues.

Congressional Research Service. R40894.

Argonne National Laboratory. 2009. Produced Water Volumes and Management Practices in the 

United States. ANL/EVS/R-09/1.

Hyne, N.J. 2001. Nontechnical Guide to Petroleum Geology, Exploration, Drilling and 

Production. Tulsa, OK: Penwell Books.
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2-50

Independent Petroleum Association of America. 2009. Profile of Independent Producers.

<http://www.ipaa.org/wpcontent/uploads/downloads/2011/12/2009ProfileOfIndependentProducers.pdf> Accessed 

March 30, 2011.

Manning, F.S. and R.E. Thompson. 1991. Oil Field Processing of Petroleum – Volume 3: 

Produced and Injection Waters. Tulsa, OK: Penn Well Books.

Oil and Gas Journal. “US Pipeline Operators Sink Revenue Growth into Expansion.” September 

2, 2013.

Oil and Gas Journal. “OGJ150 Earnings Down as US Production Climbs.” September 2, 2013.

Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push 

Global Gas Processing Capacity Ahead in 2009.” June 7, 2010.

U.S. Energy Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial 

Link between Natural Gas Production and Its Transportation to Market. 

<http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngproc

ess.pdf> Accessed February 2, 2011.

U.S. Department of Energy. 2013. Modern Shale Gas Development in the United States: An 

Update. < http://www.netl.doe.gov/File20Library/Research/Oil-Gas/shale-gas-primerupdate-2013.pdf> Accessed December 19, 2014.

U.S. Energy Information Administration (U.S. EIA). 2012. Annual Energy Review 2011 (AER). 

<http://www.eia.doe.gov/emeu/aer/contents.html>

U.S. Energy Information Administration (U.S. EIA). 2010. Oil and Gas Lease Equipment and 

Operating Costs 1994 through 2009 

<http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_

production/current/coststudy.html> Accessed March 30, 2011.

U.S. Energy Information Administration (U.S. EIA). 2013. Summary: U.S. Crude Oil, Natural 

Gas, and Natural Gas Liquids Proved Reserves 2011. 

<http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_re

serves/cr.html> Accessed September 15, 2013.

U.S. Energy Information Administration (U.S. EIA). 2011. Performance Profiles of Major 

Energy Producers 2009. <http://www.eia.gov/finance/performanceprofiles> Accessed 

September 15, 2013.

U.S. Energy Information Administration (U.S. EIA). 2014. Annual Energy Outlook 2014.

<http://www.eia.gov/forecasts/aeo/> Accessed March 17, 2014.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

2-51

U.S. Environmental Protection Agency (U.S. EPA), Office of Air Quality Planning and 

Standards. 1996. Economic Analysis of Air Pollution Regulations: Oil and Natural Gas 

Production.

<http://www.epa.gov/ttnecas1/regdata/IPs/Oil20and20NG20Production20and20NG20Tra

nsmission_IP.pdf> Accessed December 19, 2014.

U.S. Environmental Protection Agency (U.S. EPA). 2000. EPA Office of Compliance Sector 

Notebook Project: Profile of the Oil and Gas Extraction Industry. EPA/310-R-99-006.

<http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/oil

gas.pdf> Accessed December 19, 2014.

U.S. Environmental Protection Agency (U.S. EPA). 2004. Impacts to Underground Sources of 

Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. EPA/816-R-04-

003.

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis: Final 

New Source Performance Standards and Amendments to the National Emissions 

Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry.

<http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf>

Accessed December 19, 2014.
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3-1

3 EMISSIONS AND ENGINEERING COSTS

3.1 Introduction

This chapter describes the emissions and engineering cost analysis for the proposed 

NSPS. The first section discusses the emissions points and control options. The following section 

describes each step in the emissions and engineering cost analysis and presents overview results. 

Detailed tables describing the impacts for each source and option can be found at the end of the 

chapter. We provide reference to the more-detailed Technical Support Document (TSD) prepared 

by the U.S. EPA for the reader interested in a greater level of detail.17

3.2 Sector Emissions Overview

Before going into detail on emissions points and pollution controls, it is useful to provide 

estimates of overall emissions from the crude oil and natural gas industry to provide context for 

estimated reductions as a result of the proposed rule. Crude oil and natural gas production sector 

VOC emissions are approximately 2.8 million tons, according to the 2011 U.S. EPA National 

Emissions Inventory (NEI). The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-

2013 (published April 2015) estimates 2013 methane emissions from Petroleum and Natural Gas 

Systems (not including petroleum refineries and petroleum transportation) to be 182 MMt CO2

Eq. In 2013, total methane emissions from the oil and gas industry represented nearly 29 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, 2015).

It is important to note that the 2013 GHG emissions estimates do not include methane 

emissions from hydraulically fractured and re-fractured oil well completions due to lack of 

available data when the 2013 GHG Inventory estimate was developed. The estimate in this 

proposed rule includes an adjustment for hydraulically fractured oil wells, and such an 

adjustment is also being considered as a planned improvement in the 2014 Inventory (to be 

published April 2016). This adjustment would increase the 2013 Inventory methane estimate by 

 

17 U.S. EPA. 2015. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission and Distribution. Background Technical Support Document for the Proposed 

Amendments to the New Source Performance Standards.
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about 3 MMt CO2 Eq. The total methane emissions from Petroleum and Natural Gas Systems 

based on the 2013 GHG Inventory, adjusted for hydraulically fractured and re-fractured oil well 

completions, is approximately 185 MMt CO2 Eq.

3.3 Emissions Points and Pollution Controls assessed in the RIA 

A series of emissions controls were evaluated as part of the NSPS review. This section 

provides a basic description of emissions sources and the controls evaluated for each source to 

facilitate the reader’s understanding of the economic impact and benefit analyses. The reader 

who is interested in more technical detail on the engineering and cost basis of the analysis is 

referred to the relevant chapters within the TSD.

Completions of Hydraulically Fractured and Re-fractured Oil Wells: Well completion 

activities include multiple steps after the well bore hole has reached the target depth. The highest 

emissions are from venting of natural gas to the atmosphere during flowback. Flowback 

emissions are short-term in nature and occur as a specific event during completion of a new well 

or during activities that involve re-drilling or re-fracturing an existing well. The TSD separately 

considers developmental wells and exploratory wells. Developmental wells are wells drilled 

within known boundaries of a proven oil or gas field, while exploratory or “wildcat” wells are 

wells drilled in areas of new or unknown potential.

The EPA considered the same two techniques that have been proven to reduce emissions 

from well completions: reduced emissions completions (RECs) and completion combustion. The 

use of a REC not only reduces emissions but delivers natural gas product that would typically be 

vented to the sales meter. Completion combustion destroys the organic compounds. Three main 

technical barriers limit the feasibility of RECs at some wells: proximity of pipelines, pressure of 

produced gas, and inert gas concentration.

Fugitive Emissions: There are several potential sources of fugitive emissions throughout the oil 

and natural gas sector. Fugitive emissions occur when connection points are not fitted properly 

or when seals and gaskets start to deteriorate. Changes in pressure and pressure or mechanical 

stresses can also cause components or equipment to leak. Potential sources of fugitive emissions 

include agitator seals, connectors, pump diaphragms, flanges, instruments, meters, open-ended 
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lines, pressure relief devices, pump seals, valves or improperly controlled liquid storage tanks. 

These fugitive emissions do not include devices that vent as part of normal operations, such as 

gas driven pneumatic controllers or gas driven pneumatic pumps. 

The TSD considers fugitive emissions from production well sites, gathering line and 

boosting stations, and natural gas transmission/storage compressor stations. There are two 

options for reducing methane and VOC emissions from leaking components: a leak monitoring 

program based on individual component monitoring using EPA Method 21 for leak detection 

combined with a leak correction, and a leak monitoring program based on the use of OGI leak 

detection combined with leak correction. In addition, alternative frequencies for fugitive 

emissions surveys were considered: annual, semiannual, and quarterly.

Pneumatic controllers: Pneumatic controllers are automated instruments used for maintaining a 

process condition such as liquid level, pressure, pressure differential, and temperature. In many 

situations across all segments of the oil and natural gas industry, pneumatic controllers make use 

of the available high-pressure natural gas to operate or control a valve. In these “gas-driven” 

pneumatic controllers, natural gas may be released with every valve movement and/or 

continuously from the valve control pilot. Not all pneumatic controllers are gas driven. These 

“non-gas driven” pneumatic controllers use sources of power other than pressurized natural gas.

Examples include solar, electric, and instrument air. At oil and gas locations with electrical 

service, non-gas-driven controllers are typically used. Continuous bled pneumatic controllers can 

be classified into two types based on their emissions rates: (1) high-bleed controllers and (2) 

low-bleed controllers. A controller is considered to be high-bleed when the continuous bleed 

emissions are in excess of 6 standard cubic feet per hour (scfh), while low-bleed devices bleed at 

a rate less than or equal to 6 scfh. EPA evaluated the impact of replacing high-bleed controllers 

with low-bleed controllers.

Pneumatic pumps: Pneumatic pumps are devices that use gas pressure to drive a fluid by raising 

or reducing the pressure of the fluid by means of a positive displacement, a piston or set of 

rotating impellers. Gas powered pneumatic pumps are generally used at oil and natural gas 

production sites where electricity is not readily available (GRI/EPA, 1996) and can be a 

significant source of methane and VOC emissions. Pneumatic chemical and methanol injection 
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pumps are generally used to pump fairly small volumes of chemicals or methanol into wellbores, surface equipment, and pipelines. Typically, these pumps include plunger pumps with a 

diaphragm or large piston on the gas end and a smaller piston on the liquid end to enable a high 

discharge pressure with a varied but much lower pneumatic supply gas pressure. They are 

typically used semi-continuously with some seasonal variation. Pneumatic diaphragm pumps are 

another type used widely in the onshore oil and gas sector to move larger volumes of liquids per 

unit of time at lower discharge pressures than chemical and methanol injection pumps. The usage 

of these pumps is episodic including transferring bulk liquids such as motor oil, pumping out 

sumps, and circulation of heat trace medium at well sites in cold climates during winter months.

For both of these types of pumps, emissions occur when the gas used in the pump stroke 

is exhausted to enable liquid filling of the liquid chamber side of the diaphragm. Emissions are a 

function of the amount of fluid pumped, the pressure of the pneumatic supply gas, the number of 

pressure ratio’s between the pneumatic supply gas pressure and the fluid discharge pressure, and 

the mechanical inefficiency of the pump. As discussed in the white papers, we identified several 

options for reducing methane and VOC emissions: replace natural gas-assisted pump with 

instrument air pump, replace natural gas-assisted pump with solar-charged direct current pump 

(solar pumps), replace natural gas-assisted pump with electric pump, and route pneumatic pump 

emissions to a control device. EPA evaluated the impact of routing pump emissions to a preexisting on-site control device.

Centrifugal and Reciprocating Compressors: Compressors are mechanical devices that 

increase the pressure of natural gas and allow the natural gas to be transported from the 

production site, through the supply chain, and to the consumer. The types of compressors that are 

used by the oil and gas industry as prime movers are reciprocating and centrifugal compressors. 

Centrifugal compressors use either wet or dry seals.

Emissions from compressors occur when natural gas leaks around moving parts in the 

compressor. In a reciprocating compressor, emissions occur when natural gas leaks around the 

piston rod when pressurized natural gas is in the cylinder. Over time, during operation of the 

compressor, the rod packing system becomes worn and will need to be replaced to prevent 

excessive leaking from the compression cylinder. The potential control options reviewed for 
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reducing emissions from reciprocating compressors include control techniques that limit the 

leaking of natural gas past the piston rod packing. This includes replacement of the compressor 

rod packing, replacement of the piston rod, and the refitting or realignment of the piston rod.

Emissions from centrifugal compressors depend on the type of seal used: either “wet”, 

which use oil circulated at high pressure, or “dry”, which use a thin gap of high pressure gas. The 

use of dry gas seals substantially reduces emissions. In addition, they significantly reduce 

operating costs and enhance compressor efficiency. Limiting or reducing the emission from the 

rotating shaft of a centrifugal compressor using a mechanical dry seal system was evaluated. For 

centrifugal compressors equipped with wet seals, a flare was evaluated as an option for reducing 

emissions from centrifugal compressors.

3.4 Engineering Cost Analysis

In this section, we provide an overview of the engineering cost analysis used to estimate 

the additional private expenditures industry may make to comply with the proposed NSPS. A 

detailed discussion of the methodology used to estimate cost impacts is presented in the TSD, 

which is published in the Docket 

The following sections describe each step in the engineering cost analysis. First, 

representative facilities are established for each source category, including baseline emissions 

and control options. The regulatory alternatives include different variations of regulatory 

requirements considered for inclusion in the proposed standards. Then, projections are made of 

the number of incrementally affected facilities for each type of equipment or facility. National 

emissions reductions and cost estimates result from multiplying representative factors by the 

number of affected facilities in each projection year. In addition to emissions reductions, some 

control options result in natural gas recovery, which can then be combusted for useful processes 

or sold. The national cost estimates include estimated revenue from product recovery where 

applicable. Finally, national-level cost-effectiveness is calculated.

3.4.1 Control Options

For each emissions source, point, and control option, the TSD develops a representative 

facility. The characteristics of this facility include typical equipment, operating characteristics, 
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and representative factors including baseline emissions and the costs, emissions reductions, and 

product recovery resulting from each control option.

Table 3-1 shows the emissions sources, points, and controls for the fouranalyzed in three

NSPS regulatory options analyzed in this RIA, which we term Option 1, Option 2, Option 2a,

and Option 3. Option 2 was selected for proposal. The proposed Option 2 contains reduced 

emission completion (REC) and completion combustion requirements for a subset of newly 

completed oil wells that are hydraulically fractured or refractured. Option 2 also requires fugitive 

emissions survey and repair programs be performed semiannually (twice per year) at newly 

drilled or refractured oil and natural gas well sites, new or modified gathering and boosting 

stations, and new or modified transmission and storage compressor stations. Option 2 also 

requires reductions from centrifugal compressors, reciprocating compressors, pneumatic 

controllers, and pneumatic pumps throughout the oil and natural gas source category. 

The unselected Options 1, 2a, and 3 differ from the selected Option 2 with respect to the 

requirements for fugitive emissions. While Option 2 requires the fugitive emissions program all 

new and modified well sites, Option 2a does not have the fugitive requirements for low 

production sites.18 A low production site is defined by the average combined oil and natural gas 

production for the wells at the site being less than 15 barrels of oil equivalent (boe) per day.

19

Fewer sites in the program leads to lower costs and emissions reductions than under the proposed 

Option 2. Meanwhile, the less stringent Option 1 requires annual monitoring for all sites under 

the fugitive emissions program, including low production sites. Annual monitoring leads to 

lower costs, emission reductions, and natural gas recovery than the semiannual monitoring in the 

proposed Option 2. Finally, the more stringent Option 3 requires quarterly monitoring for all 

sites under the fugitive emissions program, including low production sites. More frequent 

surveys result in higher costs, higher emissions reductions, and increased natural gas recovery 

over the proposed Option 2.

 

18 In the preamble to the proposed rule, EPA is soliciting comment on excluding low production sites from the 

fugitive emissions program.

19 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels of crude oil 

equals 1000 cubic feet natural gas
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Table 3-13-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS 

Emissions Point Emissions Control Option 1 Option 2 

(proposed) Option 2a Option 3

Well Completions and Recompletions

Hydraulically Fractured 

Development Oil Wells REC or Combustion X X X X

Hydraulically Fractured 

Wildcat and Delineation 

Oil Wells

Combustion X X X X

Fugitive Emissions

Well Pads

Monitoring and 

Maintenance Annual Semiannual

Semiannual 

with Low 

Production 

Exemption

Quarterly

Gathering and Boosting 

Stations

Monitoring and 

Maintenance Semiannual Semiannual Semiannual Quarterly

Transmission Compressor 

Stations

Monitoring and 

Maintenance Semiannual Semiannual Semiannual Quarterly

Pneumatic Pumps

Well Pads Route to control X X X X

Gathering and Boosting 

Stations Route to control X X X X

Transmission and Storage 

Compressor Stations Route to control X X X X

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations Emissions limit X X X X

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations

Annual Monitoring 

and Maintenance X X X X

Centrifugal Compressors

Natural Gas Transmission 

and Storage Stations Route to control X X X X

The unselected Options 1 and 3 differ from the selected Option 2 with respect to the 

requirements for fugitive emissions. While Option 2 requires the fugitive emissions program all 

new and modified well sites, Option 1 does not have the fugitive requirements for low 

production sites.20 A low production site is defined by the average production the wells at the site 

 

20 In the preamble to the proposed rule, EPA is soliciting comment on excluding low production sites from the 

fugitive emissions program.
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producing less than 15 barrels of oil equivalent per day.

21 Fewer sites in the program leads to 

lower costs and emissions reductions than under the proposed Option 2. Meanwhile, the more 

stringent Option 3 requires quarterly monitoring for all sites under the fugitive emissions 

program, including low production sites. More frequent surveys result in higher costs, higher 

emissions reductions, and increased natural gas recovery.

3.4.2 Projection of Incrementally Affected Facilities

The second step in estimating national costs and emissions impacts of the proposed rule 

is projecting the number of incrementally affected facilities. Incrementally affected facilities are 

facilities that would be expected to change their emissions control activities as a result of the 

proposal. Facilities in states with similar state-level requirements are not included within 

incrementally affected facilities. 

The years of analysis are 2020, to represent the first full year of compliance for the 

proposal, and 2025, to represent impacts of the proposal over a longer period of time. Affected 

facilities are facilities which are new or modified since the effective year of the proposal. In 2020 

affected facilities are those which are newly established or modified in 2020. 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. In 2025, 

affected facilities include facilities newly established or modified in 2025, but also facilities 

which were newly established or modified from 2020 through 2024 and are still operating in 

2025.

The EPA has projected affected facilities using a combination of historical data from the 

U.S. GHG Inventory, and projected activity levels, taken from the Energy Information 

Administration (EIA’s) Annual Energy Outlook (AEO). The EPA derived typical counts for new 

compressors, pneumatic controllers, and pneumatic pumps by averaging the year-to-year 

increases over the past ten years in the Inventory. New and modified hydraulically fractured oil 

well completions and well sites are based on projections and growth rates consistent with the 

drilling activity in the 2014 Annual Energy Outlook. If recent decreases in oil prices lead to 

 

21 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels of crude oil 

equals 1000 cubic feet natural gas
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lower oil drilling activity in the United States, then the costs and emissions reductions resulting 

from the rule would also be reduced.

The 2014 Annual Energy Outlook was the most recent projection available at the time 

that the analysis underlying this RIA was being prepared. However, since then the 2015 Annual 

Energy Outlook has been released by the U.S. Energy Information Administration. The 2015

AEO reflects that growth in U.S. crude oil production over the last two years, along with the late2014 drop in global crude oil prices, have altered the economics of the oil market. In comparison 

to 2014 AEO reference case, the 2015 AEO reference case shows higher crude oil production (in 

2025, 18 percent% higher in 2015 AEO15), slightly lower natural gas production (in 2025, about 

4 percent% lower in 2015 AEO15), lower Brent spot and West Texas Intermediate crude oil 

prices, and lower total wells drilled in the lower 48 states (in 2025, about 20 percent% lower in 

2015 AEO15). If this RIA were updated to reflect the lower drilling activity in 2015 AEO, then 

the national costs and emissions reductions of the oil well completions and well site fugitives 

provisions of the rule would likely also be reduced. Costs and emissions reductions per facility 

would not be affected, however.[Placeholder for qualitative language about AEO2015.]

We also reviewed state regulations and permitting requirements, which require mitigation 

measures for many emission sources in the oil and natural gas sector. State regulations in 

Colorado and Wyoming both require RECs for hydraulically fractured oil and gas wells. Sources

in Colorado, Wyoming, Utah, and Ohio are subject to fugitive emissions requirementColorado, 

Wyoming, Utah, and Ohio also require fugitive emissions monitoring at well sites and 

compressor stations. Applicable facilities in these states are not included in the estimates of 

incrementally affected facilities presented in the RIA, as sources in those states are already 

subject tohave similar requirements to the federal standards. A more detailed discussion on the 

derivation of the baseline for the current proposal is presented for each emissions source is the 

TSD. The estimated counts of hydraulically-fractured and re-fracture oil well completions also 

account for the wells anticipated to be excluded from the proposed NSPS requirements because 

of a gas-to-oil ratio (GOR) of 300 or below.

Table 3-23-2 Number of Incrementally Affected Sources for the NSPS
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Emissions Sources

Incrementally Affected Sources

2020 20251

Hydraulically Fractured and Re-fractured Oil Well Completions 15,000 15,000

Fugitive Emissions2 22,000 140,000

Pneumatic Pumps 3,000 18,000

Compressors 68 410

Pneumatic Controllers 210 1,300

Total 40,000 180,000

1

In addition to newly affected sources in 2025, incrementally affected sources in 2025 include sources that become 

affected in the 2020-24 time period and are assumed to be in continued operation in 2025.

2 The number of incrementally affected sources under Option 2a1, which excludes low production well sites, 

includes about 14,000 fugitive emissions sources in 2020 and 86,000 fugitive emissions sources in 2025. Total 

incrementally affected sources under Option 2a1 are estimated at about 31,000 sources in 2020 and 120,000 sources 

in 2025.

Table 3-2 presents the estimates of the number of incrementally affected sources for this 

proposal after accounting for state regulations as described above. Note that hydraulically 

fractured and re-fractured oil well completions do not grow significantly from 2020 to 2025, 

while other sources do. This is a result of completions being a one-time activity in a given year, 

while other sources are affected and remain affected as they continue to operate, thus these 

sources accumulate over time. The estimates for that hydraulically fractured and re-fractured oil 

well completions and fugitive emissions at well sites (a large fraction of the incrementally 

affected sources under the proposed rule fugitive emissions provisions) include both new and 

modified sources. The estimates for other sources are based upon projections of new sources 

alone. While some of these sources, particularly pneumatic pumps and controllers, are likely to 

be predominantly new sources, the impact estimates may be under-estimated by the underrepresented modified sources. In the preamble to the proposed rule, the EPA solicits comments 

on these projection methods as well as solicits information that would improve our estimate of 

the turnover rates or rates of modification of relevant sources, as well as the number of wells on 

well sites.

3.4.3 Emissions Reductions

Table 3-3 summarizes the national emissions reductions for the evaluated NSPS 

emissions sources and points for 2020 and 2025. These reductions are estimated by multiplying 

the unit-level emissions reductions associated with each applicable control and facility type by 
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the number of incrementally affected sources. Table 3-1 summarizes the applicable controls, and 

Table 3-2 summarizes the affected facilities, aggregating multiple model plant types within each 

source category (e.g., oil well completions combine development and exploratory wells). The 

detailed description of emissions controls is provided in the TSD. Please note that all results have 

been rounded to two significant digits.
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Table 3-33-3 Emissions Reductions for Proposed NSPS Option 2, from Proposed NSPS, 

2020 and 2025

Source/Emissions Point

Emissions Reductions, 2020

Methane 

(short tons)

VOC 

(short 

tons)

HAP 

(short 

tons)

Methane 

(metric tons 

CO2 Eq.)

Oil Well Completions and Recompletions 140,000 110,000 14 3,100,000

Fugitive Emissions 33,000 8,700 330 750,000

Pneumatic Pumps 5,400 1,500 57 120,000

Compressors 1,600 43 1 36,000

Pneumatic Controllers 590 16 0 13,000

Total 180,000 120,000 400 4,000,000

Source/Emissions Point

Emissions Reductions, 2025

Methane 

(short tons)

VOC 

(short 

tons)

HAP 

(short 

tons)

Methane 

(metric tons 

CO2 Eq.)

Oil Well Completions and Recompletions 140,000 120,000 14 3,100,000

Fugitive Emissions 210,000 57,000 2,200 4,900,000

Pneumatic Pumps 32,000 9,000 340 740,000

Compressors 9,400 260 8 210,000

Pneumatic Controllers 3,500 97 3 80,000

Total 400,000 180,000 2,500 9,000,000

3.4.4 Product Recovery

The annualized cost estimates presented below include revenue from additional natural 

gas recovery in the production and processing segments. Several emission controls for the NSPS 

capture methane and VOC emissions that otherwise would be vented to the atmosphere. A large 

proportion of the averted methane emissions can be directed into natural gas production streams 

and sold. For environmental controls that avert the emission of saleable natural gas, we base the 

estimated revenues from averted natural gas emissions on an estimate of the amount of natural 

gas that would not be emitted during one year for the control.

The standards that result in natural gas recovery are: RECs at hydraulically fractured oil 

wells, fugitive emissions monitoring and repair, rod packing replacement in reciprocating 

compressors, and low-bleed pneumatic devices. The proposed requirements for completions at 

exploration and delineation wells, pneumatic pumps, and centrifugal compressors do not result in 

natural gas recovery. In some of these cases, alternative control strategies do result in natural gas 

recovery, but these alternative controls were not assumed as part of this analysis. For example, 
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alternatives to routing pneumatic pump emissions to a control device include substituting a solar 

or electric pump where a gas-driven pump would have otherwise been used. 

Table 3-5 summarizes natural gas recovery and revenue included in annualized cost 

calculations. When including the additional natural gas recovery in the cost analysis, we assume 

that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the wellhead.

The Energy Information Administration’s 2014 Annual Energy Outlook forecasted wellhead 

prices paid to lower 48 state producers to be $4.46/Mcf in 2020 and $5.06/Mcf in 2025. The 

$4/Mcf price assumed in this RIA is intended to reflect the AEO estimate but simultaneously be 

conservatively low.

Natural gas recovery at any point in the system provide benefits to the energy system and 

to the public. However, due to contractual arrangements, transmission and storage companies do 

not always benefit from lowering the leak rate of their operations because they do not necessarily 

own the gas, and fixed loss rates are included in long-term contracts. As a result, EPA excludes

revenue from natural gas recovery in estimating compliance costs for the transmission and 

storage segment. This approach likely overestimates the long-term compliance cost of the 

controls.

Table 3-43-4 Estimated Natural Gas Recovery (Mcf) for Proposed NSPS Option 2 in 2020 

and 2025

Source/Emissions Point

2020 2025

Gas recovery 

(Mcf)

Revenue 

from 

recovery

(2012$)

Gas recovery 

(Mcf)

Revenue 

from 

recovery

(2012$)

Oil Well Completions 6,200,000 $25,000,000 6,200,000 $25,000,000

Fugitive Emissions 1,900,000 $7,300,000 12,000,000 $47,000,000

Pneumatic Pumps 0 $0 0 $0

Compressors 76,000 $0 450,000 $0

Pneumatic Controllers 30,000 $0 180,000 $0

Total 8,200,000 $32,000,000 19,000,000 $72,000,000

As natural gas prices can increase or decrease rapidly, the estimated engineering 

compliance costs can vary when revenue from additional natural gas recovery is included. There 

is also geographic variability in wellhead prices, which can also influence estimated engineering 

costs. For the proposed option, a $1/Mcf change in the wellhead price causes a change in 
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estimated engineering compliance costs of about $8.2 million in 2020 and $19 million in 2025, 

in 2012 dollars.

3.4.5 Engineering Compliance Costs 

Table 3-6 summarizes the capital and annualized costs for the evaluated emissions 

sources and points. The detailed description of costs estimates is provided in TSD. To estimate 

total annualized engineering compliance costs, we added the annualized costs of each item 

without accounting for different expected lifetimes. This approach is mathematically equivalent 

to establishing an overall, representative project time horizon and annualizing costs after 

consideration of control options that would need to be replaced periodically within the given 

time horizon.
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Table 3-53-5 Engineering Compliance Cost Estimates for Proposed NSPS Option 2 in 

2020 and 2025

Source/Emissions Point

Compliance Costs, 2020 Compliance Costs, 2025

Capital 

Costs

Nationwide 

Annualized 

Costs 

(2012$)

Capital 

Costs

Nationwide 

Annualized 

Costs 

(2012$)

Oil Well Completions and Recompletions $150,000,000 $120,000,000 $150,000,000 $120,000,000

Fugitive Emissions $22,000,000 $47,000,000 $140,000,000 $290,000,000

Pneumatic Pumps $5,900,000 $840,000 $36,000,000 $5,100,000

Compressors $540,000 $250,000 $3,200,000 $1,500,000

Pneumatic Controllers $48,000 $5,200 $290,000 $31,000

Reporting and Recordkeeping $0 $1,400,000 $0 $4,100,000

Total $180,000,000 $170,000,000 $330,000,000 $420,000,000

Engineering capital costs were annualized using a 7 percent interest rate. Section 3.4

provides a comparison to using a 3 percent interest rate. Different emissions control options were 

annualized using expected lifetimes that were determined to be most appropriate for individual 

options. For control options evaluated for the NSPS, the following lifetimes were used:

 Reduced emissions completions and combustion devices: 1 year (more discussion of the 

selection of a one-year lifetime follows in this section)

 Fugitive emissions monitoring program design: 8 years

 Reciprocating compressors rod packing: 3.8 – 4.4 years

 Centrifugal compressors, pneumatic controllers, and pneumatic pumps: 10 years

Reporting and recordkeeping costs were drawn from the information collection requirements 

(ICR) in this proposed rule that have been submitted for approval to the Office of Management 

and Budget (OMB) under the Paperwork Reduction Act (see Chapter 5 for more detail). The 

2020 reporting and recordkeeping costs in this RIA ($1.4 million) are based on the first year ICR 

cost estimates. Meanwhile, we drew upon the first year cost in the ICR cost estimates ($4.1 

million) and applied that cost to 2025 in this RIA. 

3.4.6 Cost-Effectiveness

This section summarizes the cost-effectiveness of the proposed standards for each source 

in 2020 and 2025. The proposed NSPS includes standards for both methane and VOC reductions. 

As discussed in the preamble to this action, cost-effectiveness analysis allows comparisons of 
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relative costs and outcomes (effects) of two or more options. In general, cost-effectiveness is a 

measure of the benefit produced by resources spent. In the context of air pollution control 

options, cost-effectiveness typically refers to the annualized cost of implementing an air 

pollution control option divided by the amount of pollutant reductions realized annually. A costeffectiveness analysis is not intended to constitute or approximate a cost-benefits analysis but 

rather provides a metric of the relative cost to reduction ratios of various control options.

The estimation and interpretation of cost-effectiveness values is relatively straightforward 

when an abatement measure controls a single pollutant. Increasingly, however, air pollution 

reduction programs require reductions in emissions of multiple pollutants, and in such programs 

multipollutant controls may be employed. Consequently, there is a need for determining costeffectiveness for a control option across multiple pollutants (or classes of multiple pollutants). 

This is the case for the current proposal where EPA is proposing to directly regulate both 

methane and VOC. 

To assign the entire annualized cost to the reduction in emissions of a single pollutant 

reduced by the multipollutant control option is appropriate when reductions of the other 

pollutants are considered to cobenefits with no cost. However, under the current proposal, 

methane and VOCs are both directly regulated; therefore, reductions of each pollutant must be 

properly considered benefits, not co-benefits, and consideration of only one of the regulated 

pollutants is not appropriate.

Alternatively, all annualized costs can be allocated to each of the pollutant emission 

reductions addressed by the multipollutant control option. Unlike the approach above, no 

emission reduction is treated as a co-benefit; each emission reduction is assessed based on the 

full cost of the control. However, this approach, which is often used for assessing singlepollutant controls, evaluates emission reduction of each pollutant separately, assuming that each 

bears the entire cost, and thus inflates the control cost in the multiple of the number of additional 

pollutants being reduced. This approach therefore over-estimates the cost of obtaining emissions 

reductions with a multipollutant control as it does not recognize the simultaneity of the 

reductions achieved by the application of the control option. Another approach allocates the 

annualized cost to the sum of the individual pollutant emission reductions addressed by the 
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multipollutant control option. The multipollutant cost-effectiveness approach may be appropriate 

when each of the pollutant reductions is similar in value or impact. However, in the current 

proposal, methane and VOC have quite different health and environmental impacts, and 

therefore summing the pollutants to derive the denominator of the cost-effectiveness equation 

(i.e., assuming a ton of methane is equivalent in its impacts to a ton of VOC) is inappropriate. 

For purposes of this proposal, we have identified and are proposing to use two 

approaches for considering the cost of reducing emissions from multiple pollutants using one 

control. One approach is to assign all costs to the emission reduction of one pollutant and zero to 

all other concurrent reductions; if the cost is reasonable for reducing any of the targeted 

emissions alone, the cost of such control is clearly reasonable for the concurrent emission 

reduction of all the other pollutants because they are being reduced at no additional cost. While 

this approach assigns all costs to only a portion of the emission reduction, it does not overstate 

the cost. It also does not require unreasonable assumptions about the equivalency of the impacts 

between a ton of methane and VOC emission reduction, which is not appropriate as discussed in 

the option immediately above. In addition, this approach is simple and straight forward in 

application. If the multipollutant control is cost effective for reducing emissions of either of the 

targeted pollutant, it is clearly cost effective for reducing all other targeted emissions that are 

being achieved simultaneously.

A second approach, which we term a “multipollutant cost-effectiveness” approach, 

apportions the annualized cost across the pollutant reductions addressed by the control option in 

proportion to the relative percentage reduction of each pollutant controlled by mass. For 

example, in this proposal both methane and VOC emissions are reduced in equal proportion by 

the multipollutant control option. As a result, half of the control costs are allocated to methane, 

the other half to VOC. This approach similarly does not inflate the control cost nor requires 

unreasonable assumptions about the equivalency of the impacts between a ton of methane and 

VOC emission reduction. 

We believe that both approaches discussed above are appropriate for assessing the 

reasonableness of the multipollutant controls considered in this action. As such, in our analyses 

below, if a device is cost effective under either of these two approaches, we find it to be cost 
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3-18

effective. The EPA recognize, however, not all situations where multipollutant controls are 

applied are the same, and that other approaches, including those described above as inappropriate 

for this action, might be appropriate in other instances. 

Under the single pollutant cost-effectiveness approach, the total national compliance 

costs are divided by the emissions reductions for methane and VOC separately (Table 3-6). This 

approach does not account for the combined emissions reductions of both pollutants. 

Table 3-63-6 Engineering Compliance Cost-Effectiveness Estimates in 2020 and 2025 for 

Proposed NSPS Option 2, Single Pollutant Approach

Source/ Emissions Point

Cost-Effectiveness, 2020

(2012$)

Cost-Effectiveness, 2025

(2012$)

Methane 

($/short 

ton)

VOC 

($/short 

ton)

Methane 

($/metric 

ton CO2

Eq.)

Methane 

($/short 

ton)

VOC 

($/short 

ton)

Methane 

($/metric 

ton CO2

Eq.)

Oil Well Completions $910 $1,100 $40 $900 $1,100 $39

Fugitive Emissions $1,400 $5,300 $62 $1,400 $5,100 $60

Pneumatic Pumps $160 $560 $7 $160 $560 $7

Compressors $160 $5,600 $7 $160 $5,600 $7

Pneumatic Controllers $9 $320 $0 $9 $320 $0

Total $980 $1,400 $43 $1,100 $2,300 $47

For the multipollutant cost-effectiveness approach, costs are allocated proportionally to 

methane and VOC reductions based on the percent reduction achieved in each pollutant (Table 3-

7). Because the relevant oil and gas controls reduce methane and VOC in equal proportion, 50 

percent of costs are allocated to each emission.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

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Table 3-73-7 Engineering Compliance Cost-Effectiveness Estimates for Proposed NSPS 

Option 2 in 2020 and 2025, Multipollutant Approach

Source/ Emissions Point

Cost-Effectiveness, 2020

(2012$)

Cost-Effectiveness, 2025

(2012$)

Methane 

($/short 

ton)

VOC 

($/short 

ton)

Methane 

($/metric 

ton CO2

Eq.)

Methane 

($/short 

ton)

VOC 

($/short 

ton)

Methane 

($/metric 

ton CO2

Eq.)

Oil Well Completions $450 $540 $20 $450 $530 $20

Fugitive Emissions $710 $2,700 $31 $680 $2,500 $30

Pneumatic Pumps $78 $280 $3 $78 $280 $3

Compressors $78 $2,800 $3 $78 $2,800 $3

Pneumatic Controllers $5 $160 $0 $5 $160 $0

Total $490 $690 $22 $530 $1,200 $24

3.4.7 Comparison of Regulatory Alternatives

Table 3-8 presents a comparison of the regulatory alternatives through each step of the 

emissions analysis in 2020 and 2025.22 The requirements between the options vary with respect 

to the fugitive emissions requirements. Option 2a1 would affect fewer sources than either 

Options 1, 2, 2 oandr 3 because in Option 2a1 low-production well sites are not subject to 

fugitive emissions requirements. Further differences in methane and VOC reductions between 

the options result from differences in required fugitive emissions survey frequency. Option 1 

includes requirements for annual fugitive emissions surveys at well sites but semiannualsemiannual frequency at other sites, and Option 3 includes requirements for quarterly 

fugitive emissions surveys, as opposed the semiannual requirement in Options 21 and 2a. 

Annual, semiannual, and quarterly fugitive emissions surveys are assumed to result in respective 

reductions in emissions of 40 percent, 60 percent, and 80 percent, but affect the same number of 

sourcesAll three options would affect the same number of sources. . The differences in methane 

and VOC reductions between the options result from differences in required fugitive emissions 

 

22 The EPA also analyzed a variant of proposed Option 2 where only emissions combustion is required for 

hydraulically fractured and re-fracture oil well completions, rather than require reduced emissions completions in 

combination with combustion (RECs). This variation of the proposed Option 2 would achieve direct emission 

reduction that are equivalent to requiring RECs and combustion, but at an approximately $70 million per year 

lower cost. However, as explained in Section VIII.F of the preamble to the proposed NSPS, the EPA determined 

RECs and combustion to be the best system of emissions reduction. Section 4 of the Technical Support 

Document for the proposal presents the detailed technical analysis of the regulatory options for hydraulically 

fractured and re-fractured oil well completions.
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survey frequency. Options 1, 2, and 3 include requirements for annual, semiannual, and quarterly 

fugitive emissions surveys, which are assumed to respective reductions in emissions of 40 

percent, 60 percent, and 80 percent. Natural gas recovery also varies as a result of survey 

frequency. Variation in natural gas recovery, capital and annualized costs reflect these 

differences in the number of affected facilities and frequency of fugitive emissions 

surveys.Option 1 results in lower natural gas recovery and capital costs than the other options 

because of the requirement to flare oil well completions, as opposed to using REC when feasible 

in the proposed option. Variation between the options in capital costs are also due to oil well 

completions, because REC and flare costs are classified as capital costs. 

Table 3-83-8 Comparison of Regulatory Alternatives

Regulatory Alternative

Option 1

Option 2 

(proposed) Option 2a Option 3

Impacts in 2020

Affected Sources 40,000 40,000 31,000 40,000

Emissions Reductions

Methane Emissions Reduction (short 

tons/year) 170,000 180,000 170,000 190,000

VOC Emissions Reduction (short tons/year) 120,000 120,000 120,000 130,000

Natural Gas Recovery (Mcf) 7,700,000 8,200,000 7,700,000 8,800,000

Compliance Costs

Capital Costs (2012$) $180,000,000 $180,000,000 $170,000,000 $180,000,000

Annualized Costs (2012$) $150,000,000 $170,000,000 $150,000,000 $210,000,000

Cost-Effectiveness (Single Pollutant Approach)

Methane (2012$ / short ton) $920 $980 $920 $1,100

VOC (2012$ / short ton) $1,300 $1,400 $1,300 $1,700

Cost-Effectiveness (Multipollutant Approach)

Methane (2012$ / short ton) $460 $490 $460 $570

VOC (2012$ / short ton) $630 $690 $640 $840

Impacts in 2025

Affected Sources 180,000 180,000 120,000 180,000

Emissions Reductions

Methane Emissions Reduction (short 

tons/year) 340,000 400,000 340,000 470,000

VOC Emissions Reduction (short tons/year) 170,000 180,000 170,000 200,000

Natural Gas Recovery (Mcf) 16,000,000 19,000,000 16,000,000 23,000,000

Compliance Costs

Capital Costs (2012$) $330,000,000 $330,000,000 $280,000,000 $330,000,000

Annualized Costs (2012$) $310,000,000 $420,000,000 $320,000,000 $680,000,000

Cost-Effectiveness (Single Pollutant Approach)
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Methane (2012$ / short ton) $920 $1,100 $940 $1,400

VOC (2012$ / short ton) $1,900 $2,300 $1,900 $3,400

Cost-Effectiveness (Multipollutant Approach)

Methane (2012$ / short ton) $460 $530 $470 $720

VOC (2012$ / short ton) $940 $1,200 $960 $1,700

Because the fugitive emissions requirements contribute a large proportion of the 

proposed rule’s costs and emissions reductions, Table 3-9 presents additional analysis of the 

alternative survey and repair frequencies examined in the TSD. The TSD examines annual, semiannualsemiannual (two times per year), and quarterly survey and repair requirements. Table 3-9 

presents the emissions reductions and costs for different combinations of frequency of wellsitewell site provisions and provisions for compressor stations (gathering and boosting, 

transmission, and storage compressor stations).
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Table 3-93-9 Detailed Comparison of Regulatory Alternatives for Fugitive Emissions at 

Well Sites and Compressor Stations

Frequency of Well Site Fugitive Emissions Requirements

Annual Frequency Semi-annual Frequency Quarterly Frequency

2020 Methane VOC Methane VOC Methane VOC

Frequency of 

Fugitive 

Emissions 

Requirements for 

Compressor 

Stations

Annual Frequency 

(short tons reduced) 22,000 5,800 31,000 8,200 39,000 11,000

SemiannualSemiannual

Frequency (short 

tons reduced)

24,000 6,400 33,000 8,700 42,000 11,000

Quarterly Frequency 

(short tons reduced) 27,000 6,900 35,000 9,300 44,000 12,000

Annual Costs (2012$)

Annual Frequency 

(annual costs) $27,000,000 $45,000,000 $83,000,000

SemiannualSemiannual

Frequency (annual 

costs)

$29,000,000 $47,000,000 $84,000,000

Quarterly Frequency 

(annual costs) $32,000,000 $49,000,000 $87,000,000

Frequency of Well Site Fugitive Emissions Requirements

Annual Frequency Semi-annual Frequency Quarterly Frequency

2025 Methane VOC Methane VOC Methane VOC

Frequency of 

Fugitive 

Emissions 

Requirements for 

Compressor 

Stations

Annual Frequency 

(short tons reduced) 140,000 38,000 200,000 54,000 260,000 70,000

SemiannualSemiannual

Frequency (short 

tons reduced)

160,000 41,000 210,000 57,000 270,000 73,000

Quarterly Frequency 

(short tons reduced) 170,000 44,000 230,000 60,000 290,000 76,000

Annual Costs (2012$)

Annual Frequency 

(annual costs) $170,000,000 $280,000,000 $520,000,000

SemiannualSemiannual

Frequency (annual 

costs)

$180,000,000 $290,000,000 $530,000,000

Quarterly Frequency 

(annual costs) $200,000,000 $310,000,000 $540,000,000
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Three observations are worth noting. First, impacts fugitive emission requirements at 

well sites tend to outweigh impacts at compressor stations. This is evident as cost and emissions 

impacts rise more quicklyfast when increasing the frequency or inspections and repair at well 

sites than at compressor stations. Second, costs of the fugitive emissions program tend to scale 

linearly with increasing frequency. This results is largely explained by capital costs not 

increasing with increasing frequency, while operations and maintenance costs do increase in 

proportion to frequency. not increasing capital costs but the increased frequency increases O&M 

type costs as a multiple of survey and repair visits. ThirdLast, the control efficiency increasing 

from 40 to 60 to 80 percent for annual, semi-annualsemiannual, and quarterly, respectively, 

exhibits decreasing returns to frequency.

3.5 Compliance Costs Estimated using 3 and 7 Percent Discount Rates

Table 3-10 shows that the choice of discount rate has very minor effect on the nationwide 

annualized costs of the proposed option. 

Table 3-103-10 Annualized Costs using 3 and 7 Percent Discount Rates for the

Proposed NSPS Option 2 in 2020 and 2025

Nationwide Annualized Costs, 

2020 (2012$)

Nationwide Annualized Costs, 

2025 (2012$)

7 percent 3 percent 7 percent 3 percent

Oil Well Completions $120,000,000 $120,000,000 $120,000,000 $120,000,000

Fugitive Emissions $47,000,000 $46,000,000 $290,000,000 $290,000,000

Pneumatic Pumps $840,000 $690,000 $5,100,000 $4,200,000

Compressors $250,000 $230,000 $1,500,000 $1,400,000

Pneumatic Controllers $5,200 $4,000 $31,000 $24,000

Reporting and Recordkeeping $1,400,000 $1,400,000 $4,100,000 $4,100,000

Total $170,000,000 $170,000,000 $420,000,000 $420,000,000

The choice of discount rate has a small effect on nationwide annualized costs. The 

compliance costs related to oil well completions and fugitive emissions surveys occur in each 

year, so the interest rate has little impact on annualized costs for these sources. The annualized 

costs for pneumatic pumps, compressors, and pneumatic controllers are sensitive to interest rate, 

but these constitute a relatively small part of the total compliance cost estimates for the proposal.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

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3.6 Detailed Impacts Tables

The following tables shows the full details of the costs and emissions reduction by 

emissions sources for each regulatory option in 2020 and 2025.
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

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Table 3-113-11 Incrementally Affected Units, Emissions Reductions and Costs, Selected Proposed Option 1, 2020

Source/Emissions Point

Incrementally 

Affected 

Units

Nationwide Emissions Reductions National Costs (2012$)

Methane 

(short tons)

VOC 

(short tons)

HAP 

(short 

tons)

Methane (metric 

tons CO2 Eq.) Capital Costs

Ann. Costs With Addl. 

Revenues

Well Completions

Hydraulically Fractured 

Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000

Hydraulically Fractured 

Wildcat and Delineation Oil 

Wells

870 8,000 6,700 1 180,000 $3,200,000 $3,200,000

Fugitive Emissions

Well Pads 22,000 17,000 4,800 180 390,000 $18,000,000 $25,000,000

Gathering and Boosting 

Stations 260 5,500 1,500 57 120,000 $4,200,000 $2,800,000

Transmission Compressor 

Stations 21 1,700 47 1 39,000 $340,000 $440,000

Pneumatic Pumps

Well Pads 3,000 5,400 1,500 57 120,000 $5,900,000 $840,000

Gathering and Boosting 

Stations 0 0 0 0 0 $0 $0

Transmission and Storage 

Compressor Stations 0 0 0 0 0 $0 $0

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations 67 1,500 40 1 33,000 $470,000 $130,000

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations 1 110 3 0 2,500 $72,000 $110,000

Centrifugal Compressors

Natural Gas Transmission 

and Storage Stations 210 590 16 0 13,000 $48,000 $5,200

Reporting and Recordkeeping All 0 0 0 0 $0 $1,400,000

TOTAL 40,000 170,000 120,000 310 3,800,000 $180,000,000 $150,000,000
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Table 3-123-12 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025

Source/Emissions Point

Incrementally 

Affected Units

Nationwide Emissions Reductions National Costs (2012$)

Methane 

(short tons)

VOC 

(short tons)

HAP 

(short 

tons)

Methane (metric 

tons CO2 Eq.) Capital Costs

Ann. Costs With Addl. 

Revenues

Well Completions

Hydraulically Fractured

Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000

Hydraulically Fractured 

Wildcat and Delineation 

Oil Wells

1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000

Fugitive Emissions

Well Pads 140,000 110,000 32,000 1,200 2,600,000 $110,000,000 $160,000,000

Gathering and Boosting 

Stations 1,600 33,000 9,100 340 740,000 $25,000,000 $17,000,000

Transmission Compressor 

Stations 130 10,000 280 8 230,000 $2,100,000 $2,600,000

Pneumatic Pumps

Well Pads 18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000

Gathering and Boosting 

Stations 0 0 0 0 0 $0 $0

Transmission and Storage 

Compressor Stations 0 0 0 0 0 $0 $0

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations 400 8,800 240 7 200,000 $2,800,000 $790,000

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations 6 670 18 1 15,000 $430,000 $680,000

Centrifugal Compressors

Natural Gas Transmission 

and Storage Stations 1,300 3,500 97 3 80,000 $290,000 $31,000

Reporting and Recordkeeping All 0 0 0 0 $0 $4,100,000

TOTAL 180,000 340,000 170,000 1,900 7,700,000 $330,000,000 $310,000,000
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Table 3-133-13 Incrementally Affected Units, Emissions Reductions and Costs, Selected Proposed Option 2, 2020

Source/Emissions Point

Incrementally 

Affected 

Units

Nationwide Emissions Reductions National Costs (2012$)

Methane 

(short tons)

VOC 

(short tons)

HAP 

(short 

tons)

Methane (metric 

tons CO2 Eq.) Capital Costs

Ann. Costs With Addl. 

Revenues

Well Completions

Hydraulically Fractured 

Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000

Hydraulically Fractured 

Wildcat and Delineation Oil 

Wells

870 8,000 6,700 1 180,000 $3,200,000 $3,200,000

Fugitive Emissions

Well Pads 22,000 26,000 7,200 270 590,000 $18,000,000 $43,000,000

Gathering and Boosting 

Stations 260 5,500 1,500 57 120,000 $4,200,000 $2,800,000

Transmission Compressor 

Stations 21 1,700 47 1 39,000 $340,000 $440,000

Pneumatic Pumps

Well Pads 3,000 5,400 1,500 57 120,000 $5,900,000 $840,000

Gathering and Boosting 

Stations 0 0 0 0 0 $0 $0

Transmission and Storage 

Compressor Stations 0 0 0 0 0 $0 $0

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations 67 1,500 40 1 33,000 $470,000 $130,000

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations 1 110 3 0 2,500 $72,000 $110,000

Centrifugal Compressors

Natural Gas Transmission

and Storage Stations 210 590 16 0 13,000 $48,000 $5,200

Reporting and Recordkeeping All 0 0 0 0 $0 $1,400,000

TOTAL 40,000 180,000 120,000 400 4,000,000 $180,000,000 $170,000,000
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Table 3-143-14 Incrementally Affected Units, Emissions Reductions and Costs, ProposedSelected Option 2, 2025

Source/Emissions Point

Incrementally 

Affected Units

Nationwide Emissions Reductions National Costs (2012$)

Methane 

(short tons)

VOC 

(short tons)

HAP 

(short 

tons)

Methane (metric 

tons CO2 Eq.) Capital Costs

Ann. Costs With Addl. 

Revenues

Well Completions

Hydraulically Fractured 

Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000

Hydraulically Fractured 

Wildcat and Delineation 

Oil Wells

1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000

Fugitive Emissions

Well Pads 140,000 170,000 48,000 1,800 3,900,000 $110,000,000 $270,000,000

Gathering and Boosting 

Stations 1,600 33,000 9,100 340 740,000 $25,000,000 $17,000,000

Transmission Compressor 

Stations 130 10,000 280 8 230,000 $2,100,000 $2,600,000

Pneumatic Pumps

Well Pads 18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000

Gathering and Boosting 

Stations 0 0 0 0 0 $0 $0

Transmission and Storage 

Compressor Stations 0 0 0 0 0 $0 $0

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations 400 8,800 240 7 200,000 $2,800,000 $790,000

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations 6 670 18 1 15,000 $430,000 $680,000

Centrifugal Compressors

Natural Gas Transmission

and Storage Stations 1,300 3,500 97 3 80,000 $290,000 $31,000

Reporting and Recordkeeping All 0 0 0 0 $0 $4,100,000

TOTAL 180,000 400,000 180,000 2,500 9,000,000 $330,000,000 $420,000,000
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

3-30

Table 3-153-15 Incrementally Affected Units, Emissions Reductions and Costs, Option 2a1, 2020

Source/Emissions Point

Incrementally

Affected Units

Nationwide Emissions Reductions National Costs (2012$)

Methane (short 

tons)

VOC 

(short tons)

HAP (short 

tons)

Methane (metric 

tons CO2 Eq.) Capital Costs

Ann. Costs With Addl. 

Revenues

Well Completions

Hydraulically Fractured 

Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000

Hydraulically Fractured 

Wildcat and Delineation Oil 

Wells

870 8,000 6,700 1 180,000 $3,200,000 $3,200,000

Fugitive Emissions

Well Pads 13,000 17,000 4,600 180 380,000 $11,000,000 $26,000,000

Gathering and Boosting 

Stations 260 5,500 1,500 57 120,000 $4,200,000 $2,800,000

Transmission Compressor 

Stations 21 1,700 47 1 39,000 $340,000 $440,000

Pneumatic Pumps

Well Pads 3,000 5,400 1,500 57 120,000 $5,900,000 $840,000

Gathering and Boosting 

Stations 0 0 0 0 0 $0 $0

Transmission and Storage 

Compressor Stations 0 0 0 0 0 $0 $0

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations 67 1,500 40 1 33,000 $470,000 $130,000

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations 1 110 3 0 2,500 $72,000 $110,000

Centrifugal Compressors

Natural Gas Transmission 

and Storage Stations 210 590 16 0 13,000 $48,000 $5,200

Reporting and Recordkeeping All 0 0 0 0 $0 $1,400,000

TOTAL 31,000 170,000 120,000 310 3,800,000 $170,000,000 $150,000,000
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

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Table 3-163-16 Incrementally Affected Units, Emissions Reductions and Costs, Option 2a1, 2025

Source/Emissions Point

Incrementally 

Affected Units

Nationwide Emissions Reductions National Costs (2012$)

Methane 

(short tons)

VOC 

(short tons) HAP (short tons)

Methane (metric 

tons CO2 Eq.) Capital Costs

Ann. Costs With 

Addl. Revenues

Well Completions

Hydraulically Fractured 

Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000

Hydraulically Fractured 

Wildcat and Delineation 

Oil Wells

1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000

Fugitive Emissions

Well Pads 84,000 110,000 31,000 1,200 2,500,000 $68,000,000 $160,000,000

Gathering and Boosting 

Stations 1,600 33,000 9,100 340 740,000 $25,000,000 $17,000,000

Transmission Compressor 

Stations 130 10,000 280 8 230,000 $2,100,000 $2,600,000

Pneumatic Pumps

Well Pads 18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000

Gathering and Boosting 

Stations 0 0 0 0 0 $0 $0

Transmission and Storage 

Compressor Stations 0 0 0 0 0 $0 $0

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations 400 8,800 240 7 200,000 $2,800,000 $790,000

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations 6 670 18 1 15,000 $430,000 $680,000

Centrifugal Compressors

Natural Gas Transmission 

and Storage Stations 1,300 3,500 97 3 80,000 $290,000 $31,000

Reporting and Recordkeeping All 0 0 0 0 $0 $4,100,000

TOTAL 120,000 340,000 170,000 1,900 7,700,000 $280,000,000 $320,000,000
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

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Table 3-173-17 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020

Source/Emissions Point

Incrementally 

Affected 

Units

Nationwide Emissions Reductions National Costs (2012$)

Methane 

(short tons)

VOC 

(short tons)

HAP 

(short 

tons)

Methane (metric 

tons CO2 Eq.) Capital Costs

Ann. Costs With Addl. 

Revenues

Well Completions

Hydraulically Fractured 

Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000

Hydraulically Fractured 

Wildcat and Delineation Oil 

Wells

870 8,000 6,700 1 180,000 $3,200,000 $3,200,000

Fugitive Emissions

Well Pads 22,000 34,000 9,600 360 780,000 $18,000,000 $81,000,000

Gathering and Boosting 

Stations 260 7,300 2,000 76 170,000 $4,200,000 $5,400,000

Transmission Compressor 

Stations 21 2,300 63 2 52,000 $340,000 $780,000

Pneumatic Pumps

Well Pads 3,000 5,400 1,500 57 120,000 $5,900,000 $840,000

Gathering and Boosting 

Stations 0 0 0 0 0 $0 $0

Transmission and Storage 

Compressor Stations 0 0 0 0 0 $0 $0

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations 67 1,500 40 1 33,000 $470,000 $130,000

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations 1 110 3 0 2,500 $72,000 $110,000

Centrifugal Compressors

Natural Gas Transmission

and Storage Stations 210 590 16 0 13,000 $48,000 $5,200

Reporting and Recordkeeping All 0 0 0 0 $0 $1,400,000

TOTAL 40,000 190,000 130,000 510 4,200,000 $180,000,000 $210,000,000
*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

3-33

Table 3-183-18 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025

Source

Incrementally 

Affected Units

Nationwide Emissions Reductions National Costs (2012$)

Methane 

(short tons)

VOC 

(short tons)

HAP 

(short 

tons)

Methane (metric 

tons CO2 Eq.) Capital Costs

Ann. Costs With Addl. 

Revenues

Well Completions

Hydraulically Fractured 

Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000

Hydraulically Fractured 

Wildcat and Delineation 

Oil Wells

1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000

Fugitive Emissions

Well Pads 140,000 230,000 64,000 2,400 5,200,000 $110,000,000 $510,000,000

Gathering and Boosting 

Stations 1,600 44,000 12,000 460 990,000 $25,000,000 $32,000,000

Transmission Compressor 

Stations 130 14,000 380 11 310,000 $2,100,000 $4,700,000

Pneumatic Pumps

Well Pads 18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000

Gathering and Boosting 

Stations 0 0 0 0 0 $0 $0

Transmission and Storage 

Compressor Stations 0 0 0 0 0 $0 $0

Pneumatic Controllers -

Natural Gas Transmission 

and Storage Stations 400 8,800 240 7 200,000 $2,800,000 $790,000

Reciprocating Compressors

Natural Gas Transmission 

and Storage Stations 6 670 18 1 15,000 $430,000 $680,000

Centrifugal Compressors

Natural Gas Transmission

and Storage Stations 1,300 3,500 97 3 80,000 $290,000 $31,000

Reporting and Recordkeeping All 0 0 0 0 $0 $4,100,000

TOTAL 180,000 470,000 200,000 3,200 11,000,000 $330,000,000 $680,000,000
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-1

4 BENEFITS OF EMISSIONS REDUCTIONS

4.1 Introduction

The proposed NSPS amendments are expected to prevent new emissions from the oil and 

gas sector. For the proposed NSPS, there will be climate benefits from methane reductions, 

ozone and PM2.5 health benefits from VOC reductions, and HAP “co-benefits”. These co-benefits 

occur because the control techniques to meet the standards simultaneously reduce methane,

VOC, and HAP emissions. The proposed NSPS is anticipated to prevent 180,000 tons of 

methane, 120,000 tons of VOC, and 400 tons of HAP from new sources in 2020. In 2025, the 

NSPS would prevent 400,000 tons of methane, 180,000 tons of VOC, and 2,500 tons of HAP.

The CO2-equivalent (CO2 Eq.) methane emission reductions are estimated to be 4.0 million 

metric tons in 2020 and 9.0 million metric tons in 2025. As described in the subsequent sections, 

these pollutants are associated with substantial climate, health, and welfare effects. The only 

benefits monetized in this RIA are methane-related climate benefits. The methane-related climate 

effects are estimated to be $210 million and $550 million using a 3 percent discount rate in 2020

and 2025, respectively. The specific control techniques for the proposed NSPS are anticipated to 

have minor emissions disbenefits (e.g., increases in emissions of carbon dioxide (CO2), nitrogen 

oxides (NOX), PM, carbon monoxide (CO), and total hydrocarbons (THC)) and emission 

changes associated with the energy system impacts.

While we expect that the avoided VOC emissions will also result in improvements in air 

quality and reduce health and welfare effects associated with exposure to ozone, fine particulate 

matter (PM2.5), and HAP, we have determined that quantification of the VOC-related health 

benefits cannot be accomplished for this rule in a defensible way. This is not to imply that these

benefits do not exist; rather, it is a reflection of the difficulties in modeling the direct and indirect 

impacts of the reductions in emissions for this industrial sector with the data currently available. 

With the data available, we are not able to provide a credible 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 
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4-2

and VOC reductions.23 In this chapter, we provide a qualitative assessment of the health benefits 

associated with reducing exposure to these pollutants, as well as visibility impairment and 

ecosystem benefits. Table 4-1 summarizes the quantified and unquantified benefits in this 

analysis. 

Table 4-14-1 Climate and Human Health Effects of Emission Reductions from this 

Proposal

Category Specific Effect

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More 

Information

Improved Environment

Reduced climate 

effects

Global climate impacts from methane and 

carbon dioxide (CO2)

—1 

Marten et al.

(2015), SC-CO2

TSDs

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

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

 

23 Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the 

effect that 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 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.
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-3

Category Specific Effect

Effect Has 

Been 

Quantified

Effect Has 

Been 

Monetized

More 

Information

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

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 global 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 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 welfare effects of quantified changes 

in CO2 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.
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-4

4.2 Emission Reductions from the Proposed NSPS

As described in Section 2 of this RIA, 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 regions. For example, wells and processing plants are largely concentrated in the South 

Central, Midwest, and Southern California regions of the U.S., whereas gas compression stations 

are located all over the country. Distribution lines to customers are frequently located within 

areas of high population density.

In implementing this rule, emission controls may lead to reductions in ambient PM2.5 and 

ozone below the National Ambient Air Quality Standards (NAAQS) in some areas and assist 

other areas with attaining the NAAQS. Due to the high degree of variability in the 

responsiveness of ozone and PM2.5 formation to VOC emission reductions, we are unable to 

determine how this rule might affect attainment status without air quality modeling data.24

Because the NAAQS RIAs also calculate ozone and PM benefits, there are important differences 

worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate 

the potential costs and benefits of attaining a new air quality standard nationwide based on an 

array of emission control strategies for different sources.25 By contrast, the emission reductions 

for implementation rules, including this rule, are generally from a specific class of wellcharacterized 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 

reductions achieved under these and other promulgated rules will ultimately be reflected in the 

baseline of future NAAQS analyses, which would reduce the incremental costs and benefits 

associated with attaining the NAAQS.

 

24 The responsiveness of ozone and PM2.5 formation is discussed in greater detail in sections 4.4.1 and 4.5.1 of this 

RIA. 

25

 NAAQS RIAs hypothesize, but do not predict, the control strategies that 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.
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-5

Table 4-2 shows the direct emission reductions anticipated for this rule, across the 

regulatory options examined in the rule. It is important to note that these benefits accrue at 

different spatial scales. HAP emission reductions reduce exposure to carcinogens and other toxic 

pollutants primarily near the emission source. Reducing VOC emissions would reduce precursors 

to secondary formation of PM2.5 and ozone, which reduces exposure to these pollutants on a 

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.

Table 4-24-2 Direct Emission Reductions from the Proposed NSPS in 2020 and 2025

Pollutant Option 1 Option 2 Option 3

2020

Methane (short tons/year) 170,000 180,000 190,000

VOC (short tons/year) 120,000 120,000 130,000

HAP (short tons/year) 310 400 510

Methane (metric tons) 150,000 160,000 170,000

Methane (metric tons CO2 Eq.) 3,800,000 4,000,000 4,200,000

2025

Methane (short tons/year) 340,000 400,000 470,000

VOC (short tons/year) 170,000 180,000 200,000

HAP (short tons/year) 1,900 2,500 3,200

Methane (metric tons) 310,000 360,000 430,000

Methane (metric tons CO2 Eq.) 7,700,000 9,000,000 11,000,00

0

Pollutant Option 1 Option 2

(proposed) Option 2a Option 3

2020

Methane (short tons/year) 170,000 180,000 170,000 190,000

VOC (short tons/year) 120,000 120,000 120,000 130,000

HAP (short tons/year) 310 400 310 510

Methane (metric tons) 150,000 160,000 150,000 170,000

Methane (metric tons CO2 Eq.) 3,800,000 4,000,000 3,800,000 4,200,000

2025

Methane (short tons/year) 340,000 400,000 340,000 470,000

VOC (short tons/year) 170,000 180,000 170,000 200,000

HAP (short tons/year) 1,900 2,500 1,900 3,200

Methane (metric tons) 310,000 360,000 310,000 430,000

Methane (metric tons CO2 Eq.) 7,700,00 9,000,000 7,700,000 11,000,000
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-6

4.3 Methane

4.3.1 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 that

contributes to increased global warming and continuing climate change. Methane reacts in the 

atmosphere to form ozone and ozone 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, 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.

Processes in the oil and gas category emit significant amounts of methane. The Inventory 

of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013 (published April 2015) estimates 2013

methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries 

and petroleum transportation) to be 182 MMt CO2 Eq. In 2013, total methane emissions from the 

oil and gas industry represented nearly 29 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, 2015c).

It is important to note that the 2013 GHG emissions estimates do not include methane 

emissions from hydraulically fractured and re-fractured oil well completions due to lack of 

available data when the 2013 GHG Inventory estimate was developed. The estimate in this 
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4-7

proposed rule includes an adjustment for hydraulically fractured oil wells, and such an 

adjustment is also being considered as a planned improvement in the 2014 Inventory (to be 

published April 2016). This adjustment would increase the 2013 Inventory methane estimate by 

about 3 MMt CO2 Eq. The total methane emissions from Petroleum and Natural Gas Systems 

based on the 2013 GHG Inventory, adjusted for hydraulically fractured and re-fractured oil well 

completions, is approximately 185 MMt CO2 Eq.

Actions taken to comply with the proposed NSPS are anticipated to significantly decrease 

methane emissions from the oil and natural gas sector in the United States. The proposed NSPS 

is expected to reduce methane emissions by about 180,000 short tons or approximately 160,000 

metric tons methane (or 4.0 MMt CO2 Eq.) in 2020. In 2025, the proposed NSPS is expected to 

reduce methane emissions by about 400,000 short tons or approximately 360,000 metric tons 

methane (or 9.0 MMt CO2 Eq.). These reductions in 2020 and 2025 represent about 2 percent 

and 5 percent, respectively, of the GHG emissions for this sector (excluding petroleum refineries 

and petroleum transportation) reported in the 1990-2013 U.S. GHG Inventory (182 MMt CO2

Eq.).

We calculated the global social benefits of methane emissions reductions expected from 

the proposed NSPS using estimates of the social cost of methane (SC-CH4), a metric that 

estimates the monetary value of impacts associated with marginal changes in methane 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. The SC-CH4 estimates applied in this analysis were developed by Marten et al.

(2014) and are discussed in greater detail below.

A similar metric, the social cost of CO2 (SC-CO2), provides important context for 

understanding the Marten et al. SC-CH4 estimates. Estimates of the SC-CO2 have been used by 

EPA and other federal agencies to value the impacts of CO2 emissions changes in benefit cost 

analysis for GHG-related rulemakings since 2008. The SC-CO2 is a metric that estimates the 

monetary value of impacts associated with marginal changes in CO2 emissions in a given year. 

Similar to the SC-CH4, it includes a wide range of anticipated climate impacts, such as net 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-8

changes in agricultural productivity, 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 used to quantify the benefits of reducing CO2 emissions, or the disbenefit from increasing 

emissions, in regulatory impact analyses.

The SC-CO2 estimates were developed over many years, using the best science available, 

and with input from the public. Specifically, an interagency working group (IWG) that included 

EPA and other executive branch agencies and offices used three integrated assessment models 

(IAMs) to develop the SC-CO2 estimates and recommended four global values for use in 

regulatory analyses. The SC-CO2 estimates were first released in February 2010 and updated in 

2013 using new versions of each IAM. The 2013 update did not revisit the 2010 modeling 

decisions with regards to the discount rate, reference case socioeconomic and emission scenarios, 

and equilibrium climate sensitivity distribution. Rather, improvements in the way damages are 

modeled are confined to those that have been incorporated into the latest versions of the models 

by the developers themselves and published in the peer-reviewed literature. The 2010 SC-CO2

Technical Support Document (2010 SC-CO2 TSD) provides a complete discussion of the 

methods used to develop these estimates and the current SC-CO2 TSD presents and discusses the 

2013 update (including recent minor technical corrections to the estimates).26

The 2010 SC-CO2 TSD noted a number of limitations to the SC-CO2 analysis, including 

the incomplete way in which the IAMs capture catastrophic and non-catastrophic impacts, their 

incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of 

damages to high temperatures, and assumptions regarding risk aversion. Currently IAMs do not 

assign value to all of the important physical, ecological, and economic impacts of climate change 

recognized in the climate change literature due to a lack of precise information on the nature of 

damages and because the science incorporated into these models understandably lags behind the 

most recent research. Nonetheless, these estimates and the discussion of their limitations 

represent the best available information about the social benefits of CO2 reductions to inform 

 

26 Both the 2010 SC-CO2 TSD and the current SC-CO2 TSD are available at: 

https://www.whitehouse.gov/omb/oira/social-cost-of-carbon
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-9

benefit-cost analysis. The new versions of the models offer some improvements in these areas, 

although further work is warranted.

Accordingly, EPA and other agencies continue to engage in research on modeling and 

valuation of climate impacts with the goal to improve these estimates. The EPA and other 

agencies also continue to consider feedback on the SC-CO2 estimates from stakeholders through 

a range of channels, including public comments on Agency rulemakings that use the SC-CO2 in 

supporting analyses and through regular interactions with stakeholders and research analysts 

implementing the SC-CO2 methodology used by the IWG. In addition, OMB sought public 

comment on the approach used to develop the SC-CO2 estimates through a separate comment 

period that ended on February 26, 2014.27 

After careful evaluation of the full range of comments, the IWG continues to recommend 

the use of the SC-CO2 estimates in regulatory impact analysis. With the release of the response 

to comments, the IWG announced plans to obtain expert independent advice from the National 

Academy of Sciences to ensure that the SC-CO2 estimates continue to reflect the best available 

scientific and economic information on climate change.28 The NRC review will be informed by 

the public comments received and focus on the technical merits and challenges of potential 

approaches to improving the SC-CO2 estimates in future updates. 

Concurrent with OMB’s publication of the response to comments on SC-CO2 and 

announcement of the NRC process, OMB posted a revised TSD that includes two minor 

technical corrections to the current estimates. One technical correction addressed an inadvertent 

omission of climate change damages in the last year of analysis (2300) in one model and the 

second addressed a minor indexing error in another model. On average the revised SC-CO2

estimates are one dollar less than the mean SC-CO2 estimates reported in the November 2013 

TSD. The change in the estimates associated with the 95th percentile estimates when using a 3 

 

27 For the IWG’s response to comments, see https://www.whitehouse.gov/sites/default/files/omb/inforeg/sccresponse-to-comments-final-july-2015.pdf. 

28 See https://www.whitehouse.gov/blog/2015/07/02/estimating-benefits-carbon-dioxide-emissions-reductions. 
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percent discount rate is slightly larger, as those estimates are heavily influenced by the results 

from the model that was affected by the indexing error.

The four SC-CO2 estimates are: $13, $45, $67, and $130 per metric ton of CO2 emissions 

in the year 2020 (2012 dollars).29 The first three values are based on the average SC-CO2 from 

the three IAMs, at discount rates of 5, 3, and 2.5 percent, respectively. Estimates of the SC-CO2

for several discount rates are included because the literature shows that the SC-CO2 is sensitive 

to assumptions about the discount rate, and because no consensus exists on the appropriate rate 

to use in an intergenerational context (where costs and benefits are incurred by different 

generations). The fourth value is the 95th percentile of the SC-CO2 across all three models at a 3 

percent discount rate. It is included to represent higher-than-expected impacts from temperature 

change further out in the tails of the SC-CO2 distribution. The SC-CO2 increases over time 

because future emissions are expected to produce larger incremental damages as economies grow 

and physical and economic systems become more stressed in response to greater climate change.

A challenge particularly relevant to this proposal is that the IWG did not estimate the 

social costs of non-CO2 GHG emissions at the time the SC-CO2 estimates were developed. One 

alternative approach to value methane impacts is to use the global warming potential (GWP) to 

convert the emissions to CO2 equivalents which are then valued using the SC-CO2 estimates. 

The GWP measures the cumulative radiative forcing from a perturbation of a non-CO2

GHG relative to a perturbation of CO2 over a fixed time horizon, often 100 years. The GWP 

mainly reflects differences in the radiative efficiency of gases and differences in their 

atmospheric lifetimes. While the GWP is a simple, transparent, and well-established metric for 

assessing the relative impacts of non-CO2 emissions compared to CO2 on a purely physical basis, 

there are several well-documented limitations in using it to value non-CO2 GHG benefits, as 

discussed in the 2010 SC-CO2 TSD and previous rulemakings (e.g., U.S. EPA 2012b, 2012d).30

 

29 The current version of the SC-CO2 TSD is available at: <link to be added when available>. The TSDs present 

SC-CO2 in $2007. The estimates were adjusted to 2012$ using the GDP Implicit Price Deflator (1.0804). Also 

available at: http://www.bea.gov/iTable/index_nipa.cfm. The SC-CO2 values have been rounded to two 

significant digits. Unrounded numbers from the 2013 SCC TSD were adjusted to 2012$ and used to calculate 

the CO2 benefits.

30 See also Reilly and Richards, 1993; Schmalensee, 1993; Fankhauser, 1994; Marten and Newbold, 2012.
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In particular, several recent studies found that GWP-weighted benefit estimates for methane are 

likely to be lower than the estimates derived using directly modeled social cost estimates for 

these gases. Gas comparison metrics, such as the GWP, are designed to measure the impact of 

non-CO2 GHG emissions relative to CO2 at a specific point along the pathway from emissions to 

monetized damages (depicted in Figure 4-1), and this point may differ across measures. 

Source: Marten et al. 2015

Figure 4-1 Path from GHG Emissions to Monetized Damages

The GWP is not ideally suited for use in benefit-cost analyses to approximate the social 

cost of non-CO2 GHGs because it ignores important nonlinear relationships beyond radiative 

forcing in the chain between emissions and damages. These can become relevant because gases 

have different lifetimes and the SC-CO2 takes into account the fact that marginal damages from 

an increase in temperature are a function of existing temperature levels. Another limitation of gas 

comparison metrics for this purpose is that some environmental and socioeconomic impacts are 

not linked to all of the gases under consideration, or radiative forcing for that matter, and will 

therefore be incorrectly allocated. For example, the economic impacts associated with increased 

agricultural productivity due to higher atmospheric CO2 concentrations included in the SC-CO2

would be incorrectly allocated to methane emissions with the GWP-based valuation approach.

Also of concern is the fact that the assumptions made in estimating the GWP are not 

consistent with the assumptions underlying SC-CO2 estimates in general, and the SC-CO2

estimates developed by the IWG more specifically. For example, the 100-year time horizon 

usually used in estimating the GWP is less than the approximately 300-year horizon the IWG

used in developing the SC-CO2 estimates. The GWP approach also treats all impacts within the 

time horizon equally, independent of the time at which they occur. This is inconsistent with the 

role of discounting in economic analysis, which accounts for a basic preference for earlier over 

later gains in utility and expectations regarding future levels of economic growth. In the case of 

methane, which has a relatively short lifetime compared to CO2, the temporal independence of 
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the GWP could lead the GWP approach to underestimate the SC-CH4 with a larger downward 

bias under higher discount rates (Marten and Newbold, 2012).31

EPA sought public comments on the valuation of non-CO2 GHG impacts in previous 

rulemakings (e.g., U.S. EPA 2012b, 2012d). In general, the commenters strongly encouraged 

EPA to incorporate the monetized value of non-CO2 GHG impacts into the benefit cost analysis, 

however they noted the challenges associated with the GWP-approach, as discussed above, and 

encouraged the use of directly-modeled estimates of the SC-CH4 to overcome those challenges. 

EPA had cited several researchers that had directly estimated the social cost of non-CO2

emissions using IAMs but noted that the number of such estimates was small compared to the 

large number of SC-CO2 estimates available in the literature. EPA found considerable variation 

among these published estimates in terms of the models and input assumptions they employ 

(U.S. EPA, 2012d). These studies differed in the emissions perturbation year, employed a wide

range of constant and variable discount rate specifications, and considered a range of baseline 

socioeconomic and emissions scenarios that have been developed over the last 20 years. 

Furthermore, at the time, none of the other published estimates of the social cost of non-CO2

GHG were consistent with the SC-CO2 estimates developed by the IWG, and most were likely 

underestimates due to changes in the underlying science since their publication.

Therefore, EPA concluded that the GWP approach would serve as an interim method of 

analysis until directly modeled social cost estimates for non-CO2 GHGs, consistent with the SCCO2 estimates developed by the IWG, were developed. EPA presented GWP-weighted estimates 

in sensitivity analyses rather than the main benefit-cost analyses.32

 

31 We note that the truncation of the time period in the GWP calculation could lead to an overestimate of SC-CH4

for near term perturbation years when the SC-CO2 is based on a sufficiently low or steeply declining discount 

rate.

32 For example, the 2012 New Source Performance Standards and Amendments to the National Emissions 

Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry are expected to reduce methane

emissions by 900,000 metric tons annually, see http://www.gpo.gov/fdsys/pkg/FR-2012-08-16/pdf/2012-

16806.pdf. Additionally, the 2017-2025 Light-duty Vehicle Greenhouse Gas Emission Standards and Corporate

Average Fuel Economy Standards, promulgated jointly with the National Highway Traffic Safety 

Administration, is expected to reduce methane emissions by over 100,000 metric tons in 2025 increasing to 

nearly 500,000 metric tons in 2050, see http://www.gpo.gov/fdsys/pkg/FR-2012-10-15/pdf/2012-21972.pdf
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Since then, a paper by Marten et al. (2014) provided the first set of published SC-CH4

estimates in the peer-reviewed literature that are consistent with the modeling assumptions 

underlying the SC-CO2 estimates.33 Specifically, the estimation approach of Marten et al. used 

the same set of three IAMs, five socioeconomic and emissions scenarios, equilibrium climate 

sensitivity distribution, three constant discount rates, and aggregation approach used by the IWG 

to develop the SC-CO2 estimates. The aggregation method involved distilling the 45 distributions

of the SC-CH4 produced for each emissions year into four estimates: the mean across all models 

and scenarios using a 2.5 percent, 3 percent, and 5 percent discount rate, and the 95th percentile 

of the pooled estimates from all models and scenarios using a 3 percent discount rate. The 

atmospheric lifetime and radiative efficacy of methane used by Marten et al. is based on the 

estimates reported by the IPCC in their Fourth Assessment Report (AR4, 2007), including an 

adjustment in the radiative efficacy of methane to account for its role as a precursor for 

tropospheric ozone and stratospheric water. These values represent the same ones used by the 

IPCC in AR4 for calculating GWPs. At the time Marten et al. developed their estimates of the 

SC-CH4, AR4 was the latest assessment report by the IPCC. The IPCC updates GWP estimates 

with each new assessment, and in the most recent assessment, AR5, the latest estimate of the 

methane GWP ranged from 28-36, compared to a GWP of 25 in AR4. The updated values reflect 

a number of changes: changes in the lifetime and radiative efficiency estimates for CO2, changes 

in the lifetime estimate for methane, and changes in the correction factor applied to methane’s 

GWP to reflect the effect of methane emissions on other climatically important substances such 

as tropospheric ozone and stratospheric water vapor. In addition, the range presented in the latest 

IPCC report reflects different choices regarding whether to account for how biogenic and fossil 

methane have different carbon cycle effects, and for whether to account for climate feedbacks on 

the carbon cycle for both methane and CO2 (rather than just for CO2 as was done in AR4).34,35

 

33 Marten et al. (2015) also provided the first set of SC-N20 estimates that are consistent with the assumptions 

underlying the SC-CO2 estimates.

34 Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment 

Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, 

S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, 

Cambridge, United Kingdom and New York, NY, USA.

35 Note that this proposal uses a GWP value for methane of 25 for CO2 equivalency calculations, consistent with 

the GHG emissions inventories and the IPCC Fourth Assessment Report (AR4).
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Marten et al. (2014) discuss these estimates, (SC-CH4 estimates presented below in Table 

4-3Table 4-3), and compare them with other recent estimates in the literature.36 The authors 

noted that a direct comparison of their estimates with all of the other published estimates is 

difficult, given the differences in the models and socioeconomic and emissions scenarios, but 

results from three relatively recent studies offer a better basis for comparison (see Hope (2006), 

Marten and Newbold (2012), Waldhoff et al. (2014)). Marten et al. found that in general the SCCH4 estimates from their 2014 paper are higher than previous estimates. The higher SC-CH4

estimates are partially driven by the higher effective radiative forcing due to the inclusion of 

indirect effects from methane emissions in their modeling. Marten et al., similar to other recent 

studies, also find that their directly modeled SC-CH4 estimates are higher than the GWPweighted estimates. More detailed discussion of the SC-CH4 estimation methodology, results and 

a comparison to other published estimates can be found in Marten et al.

Table 4-34-3 Social Cost of Methane (SC-CH4), 2012 – 2050a[in 2012$ per metric ton] 

(Source: Marten et al., 2015

b

)

Year

SC-CH4

5 Percent

Average

3 Percent

Average

2.5 Percent

Average

3 Percent

95th percentile

2012 $430 $1,000 $1,400 $2,800

2015 $490 $1,100 $1,500 $3,000

2020 $580 $1,300 $1,700 $3,500

2025 $700 $1,500 $1,900 $4,000

2030 $820 $1,700 $2,200 $4,500

2035 $970 $1,900 $2,500 $5,300

2040 $1,100 $2,200 $2,800 $5,900

2045 $1,300 $2,500 $3,000 $6,600

2050 $1,400 $2,700 $3,300 $7,200

a The values are emissions-year specific and are defined in real terms, i.e., adjusted for inflation using the GDP 

implicit price deflator.

b The estimates in this table have been adjusted to reflect the minor technical corrections to the SC-CO2 estimates 

described above. See Corrigendum to Marten et al. (2014) for more details

http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550. 

 

36 Marten et al. (2015) estimates are presented in 2007 dollars. These estimates were adjusted for inflation using 

National Income and Product Accounts Tables, Table 1.1.9, Implicit Price Deflators for Gross Domestic 

Product (US Department of Commerce, Bureau of Economic Analysis), 

http://www.bea.gov/iTable/index_nipa.cfm (1.0804) Accessed 3/3/15.
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The application of directly modeled estimates from Marten et al. (2014) to benefit-cost 

analysis of a regulatory action is analogous to the use of the SC-CO2 estimates. Specifically, the 

SC-CH4 estimates in Table 4-3 are used to monetize the benefits of reductions in methane 

emissions expected as a result of the proposed rulemaking. Forecast changes in methane 

emissions in a given year, expected as a result of the proposed regulatory action, are multiplied 

by the SC-CH4 estimate for that year. To obtain a present value estimate, the monetized stream 

of future non-CO2 benefits are discounted back to the analysis year using the same discount rate 

used to estimate the social cost of the non-CO2 GHG emission changes. In addition, the 

limitations for the SC-CO2 estimates discussed above likewise apply to the SC-CH4 estimates, 

given the consistency in the methodology. 

EPA recently conducted a peer review of the application of the Marten et al. (2014) nonCO2 social cost estimates in regulatory analysis and received responses that supported this 

application. Three reviewers considered seven charge questions that covered issues such as 

EPA’s interpretation of the Marten et al. estimates, the consistency of the estimates with the SCCO2 estimates, EPA’s characterization of the limits of the GWP-approach to value non-CO2

GHG impacts, and the appropriateness of using the Marten et al. estimates in regulatory impact 

analyses. The reviewers agreed with EPA’s interpretation of Marten et al.’s estimates; generally 

found the estimates to be consistent with the SC-CO2 estimates; and concurred with the 

limitations of the GWP approach, finding directly modeled estimates to be more appropriate. 

While outside of the scope of the review, the reviewers briefly considered the limitations in the 

SC-CO2 methodology (e.g., those discussed earlier in this section) and noted that because the 

SC-CO2 and SC-CH4 methodologies are similar, the limitations also apply to the resulting SCCH4 estimates. Two of the reviewers concluded that use in RIAs of the SC-CH4 estimates 

developed by Marten et al. and published in the peer-reviewed literature is appropriate, provided 

that the Agency discuss the limitations, similar to the discussion provided for SC-CO2 and other 

economic analyses. All three reviewers encouraged continued improvements in the SC-CO2

estimates and suggested that as those improvements are realized they should also be reflected in 

the SC-CH4 estimates, with one reviewer suggesting the SC-CH4 estimates lag this process. EPA 

supports continued improvement in the SC-CO2 estimates developed by the U.S. government and 

agrees that improvements in the SC-CO2 estimates should also be reflected in the SC-CH4

estimates. The fact that the reviewers agree that the SC-CH4 estimates are generally consistent 
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with the SC-CO2 estimates that are recommended by OMB’s guidance on valuing CO2 emissions 

reductions, leads EPA to conclude that use of the SC-CH4 estimates is an analytical improvement 

over excluding methane emissions from the monetized portion of the benefit cost analysis.

In light of the favorable peer review and past comments urging EPA to value non-CO2

GHG impacts in its rulemakings, the Agency has used the Marten et al. (2014) SC-CH4 estimates 

to value methane impacts expected from this proposed rulemaking and has included those 

benefits in the main benefits analysis. EPA seeks comments on the use of these directly modeled 

estimates, from the peer-reviewed literature, for the social cost of non-CO2 GHGs in this RIA. 

The methane benefits are presented below in Table 4-4 for years 2020 and 2025 across 

regulatory options. Applying this approach to the methane reductions estimated for the proposed 

NSPS option, the 2020 methane benefits vary by discount rate and range from about $93 million 

to approximately $550 million; the mean SC-CH4 at the 3 percent discount rate results in an 

estimate of about $210 million in 2020. The methane benefits increase for the proposed option in 

2025 and likewise vary by discount rate, ranging from about $250 million to approximately $1.4

billion in that year; the mean SC-CH4 at the 3-percent discount rate results in an estimate of 

about $550 million in 2025.

Table 4-44-4 Estimated Global Benefits of Methane Reductions* (in millions, 2012$) 

Discount rate and 

statistic

Option 1 Option 2 

(proposed) Option 2a Option 3

2020 2025 2020 2025 2020 2025 2020 2025

Million metric tonnes 

of methane reduced 0.15 0.31 0.16 0.36 0.15 0.31 0.17 0.43

Million metric tonnes 

of CO2 Eq. 3.8 7.7.4 4.0 9.0 3.8 7.7 4.2 11

5% (average) $89 $220 $93 $250 $88 $220 $99 $300

3% (average) $200 $470 $210 $550 $200 $460 $220 $640

2.5% (average) $260 $600 $280 $700 $260 $600 $290 $830

3% (95th percentile) $530 $1,200 $550 $1,400 $520 $1,200 $590 $1,700

*The SC-CH4 values are dollar-year and emissions-year specific. SC-CH4 values represent only a partial accounting 

of climate impacts.

The vast majority of this proposal’s climate-related benefits are associated with methane 

reductions, but some climate-related impacts are expected from the proposal’s secondary air 

impacts. The secondary impacts are discussed in Section 4.7. 
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Methane is also a precursor to ozone. In remote areas, methane is a dominant precursor to 

tropospheric ozone formation (U.S. EPA, 2013). Approximately 40 percent of the global annual 

mean ozone increase since preindustrial times is believed to be due to anthropogenic methane 

(HTAP, 2010). Projections of future emissions also indicate that methane is likely to be a key 

contributor to ozone concentrations in the future (HTAP, 2010). Unlike NOX and VOCs, which 

affect ozone concentrations regionally and at hourly time scales, methane emissions affect ozone 

concentrations globally and on decadal time scales given methane’s relatively long atmospheric 

lifetime (HTAP, 2010). Reducing methane emissions, therefore, can reduce global background 

ozone concentrations, human exposure to ozone, and the incidence of ozone-related health 

effects (West et al., 2006, Anenberg et al., 2009). These benefits are global and occur in both 

urban and rural areas. Reductions in background ozone concentrations can also have benefits for 

agriculture and ecosystems (UNEP/WMO, 2011). Studies show that controlling methane 

emissions can reduce global ozone concentrations and climate change simultaneously, but 

controlling other shorter-lived ozone precursors such as NOX, carbon monoxide, or non-methane 

VOCs have larger local health benefits from greater reductions in local ozone concentrations 

(West and Fiore, 2005; West et al., 2006; Fiore et al., 2008; Dentener et al., 2005; Shindell et al., 

2005, 2012; UNEP/WMO, 2011). The health, welfare, and climate effects associated with ozone 

are described in the preceding sections. Without detailed air quality modeling, we are unable to 

estimate the effect that reducing methane will have on ozone concentrations at particular 

locations.

Recently, a paper was published in the peer-reviewed scientific literature that presented a 

range of estimates of the monetized ozone-related mortality benefits of reducing methane 

emissions (Sarofim et al. 2015). For example, under their base case assumptions using a 3% 

discount rate, Sarofim et al. find global ozone-related mortality benefits of methane emissions 

reductions to be $790 per tonne of methane in 2020, with 10.6%, or $80, of this amount resulting 

from mortality reductions in the United States. The methodology used in this study is consistent 

in some (but not all) aspects with the modeling underlying the SC-CO2 and SC-CH4 estimates 

discussed above, and required a number of additional assumptions such as baseline mortality 

rates and mortality response to ozone concentrations. The Sarofim et al. (2015) study may have 

implications for this benefits analysis as it provides a potential approach to estimating the ozone 

related mortality benefits resulting from the methane reductions expected from this proposed 
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rulemaking. The EPA requests comment on Sarofim et al.’s approach to estimating the ozone 

related mortality benefits of methane emissions reductions, including technical considerations in 

applying their methodology to this regulatory impact analysis.

4.4 VOC as a PM2.5 precursor

This rulemaking would reduce emissions of VOC, which are a precursor to PM2.5. 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). Therefore, reducing these 

emissions would reduce PM2.5 formation, human exposure to PM2.5, and the incidence of PM2.5-

related health effects. However, we have not quantified the PM2.5-related benefits in this analysis.

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. 

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 PM2.5 benefits associated with reducing VOC emissions. 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.

4.4.1 PM2.5 health effects and valuation

Reducing VOC emissions would reduce PM2.5 formation, human exposure, and the 

incidence of PM2.5-related health effects. Reducing exposure to PM2.5 is associated with 

significant human health benefits, including avoiding mortality and respiratory morbidity.
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Researchers have associated PM2.5- exposure with adverse health effects in numerous 

toxicological, clinical and epidemiological studies (U.S. EPA, 2009a). When adequate data and 

resources are available, EPA generally quantifies several health effects associated with exposure 

to PM2.5 (e.g., U.S. EPA (2011g)). These health effects include premature mortality for adults 

and infants; cardiovascular morbidity, such as heart attacks; respiratory morbidity, such as 

asthma attacks and acute and chronic bronchitis; which result in hospital and ER visits, lost work 

days, restricted activity days, and respiratory symptoms. Although EPA has not quantified these 

effects in previous benefits analyses, the scientific literature suggests that exposure to PM2.5 is 

also associated with adverse effects on birth weight, pre-term births, pulmonary function, other 

cardiovascular effects, and other respiratory effects (U.S. EPA, 2009a).

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.

Previous studies have estimated the monetized benefits-per-ton of reducing VOC 

emissions associated with the effect that those emissions have on ambient PM2.5 levels and the 

health effects associated with PM2.5 exposure (Fann, Fulcher, and Hubbell, 2009), and these 

estimates can provide useful context for this rulemaking. Using the estimates in Fann, Fulcher, 

and Hubbell (2009), the monetized benefit-per-ton of reducing VOC emissions in nine urban 

areas of the U.S. ranges from $560 in Seattle, WA to $5,700 in San Joaquin, CA, with a national 

average of $2,400. These estimates assume a 50 percent reduction in VOC, the Laden et al.

(2006) mortality function (based on the Harvard Six Cities study, a large cohort epidemiology 

study in the Eastern U.S., an analysis year of 2015, a 3 percent discount rate, and 2006$).

Additional benefit-per-ton estimates are available from this dataset using alternate assumptions 

regarding the relationship between PM2.5 exposure and premature mortality from empirical 

studies and supplied by experts (e.g., Pope et al., 2002; Laden et al., 2006; Roman et al., 2008).
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EPA generally presents a range of benefits estimates derived from the American Cancer Society 

cohort (e.g., Pope et al., 2002; Krewski et al., 2009) to the Harvard Six Cities cohort (e.g., Laden 

et al., 2006; Lepuele et al., 2012) because the studies are both well-designed and extensively 

peer reviewed, and EPA provides the benefit estimates derived from expert opinions in Roman et 

al. (2008) as a characterization of uncertainty. As shown in Table 4-5Table 4-5, the range of 

VOC benefits that reflects the range of epidemiology studies and the range of the urban areas is 

$300 to $7,500 per ton of VOC reduced (2012$).

37 Since these estimates were presented in the 

2012 Oil and Gas NSPS RIA (U.S. EPA, 2012b), we updated our methods to apply more recent 

epidemiological studies for these cohorts (i.e., Krewski et al., 2009; Lepuele et al., 2012) as well 

as additional updates to the morbidity studies and population data.38 Because these updates would 

not lead to significant changes in the benefit-per-ton estimates for VOC, we have not updated 

them here.

While these ranges of benefit-per-ton estimates provide useful context, the geographic 

distribution of VOC emissions from the oil and 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 lead EPA to conclude that the available VOC benefit per ton estimates are not 

appropriate to calculate monetized benefits of this rule, even as a bounding exercise.

 

37 We also converted the estimates from Fann, Fulcher, and Hubbell (2009) to 2012$ and applied EPA’s current 

value of a statistical life (VSL) estimate. For more information regarding EPA’s current VSL estimate, please 

see Section 5.6.5.1 of the RIA for the PM NAAQS RIA (U.S. EPA, 2012c). EPA continues to work to update 

its guidance on valuing mortality risk reductions. 

38 For more information regarding these updates, please see Section 5.3 of the RIA for the final PM NAAQS (U.S. 

EPA, 2012c).
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Table 4-54-5 Monetized Benefits-per-Ton Estimates for VOC based on Previous Modeling in 2015 (2012$)

Area Pope et al.

(2002)

Laden et al.

(2006)

Expert 

A

Expert 

B

Expert 

C

Expert 

D

Expert 

E

Expert 

F

Expert 

G

Expert 

H

Expert 

I

Expert 

J

Expert 

K

Expert 

L

Atlanta $660 $1,600 $1,700 $1,300 $1,300 $920 $2,100 $1,200 $780 $980 $1,300 $1,000 $260 $1,000

Chicago $1,600 $4,000 $4,200 $3,300 $3,200 $2,300 $5,300 $3,000 $1,900 $2,400 $3,200 $2,600 $640 $2,500

Dallas $320 $790 $830 $650 $630 $450 $1,000 $580 $380 $480 $630 $510 $130 $490

Denver $770 $1,900 $2,000 $1,500 $1,500 $1,100 $2,400 $1,400 $910 $1,100 $1,500 $1,200 $300 $910

NYC/ Philadelphia $2,300 $5,600 $5,900 $4,600 $4,500 $3,200 $7,300 $4,100 $2,700 $3,400 $4,500 $3,600 $890 $3,300

Phoenix $1,100 $2,700 $2,800 $2,200 $2,100 $1,500 $3,500 $2,000 $1,300 $1,600 $2,100 $1,700 $420 $1,600

Salt Lake $1,400 $3,300 $3,500 $2,700 $2,700 $1,900 $4,400 $2,500 $1,600 $2,000 $2,700 $2,200 $570 $2,100

San Joaquin $3,100 $7,500 $7,900 $6,100 $6,000 $4,300 $9,700 $5,500 $3,600 $4,500 $6,000 $4,900 $1,400 $4,600

Seattle $300 $730 $770 $570 $590 $420 $950 $540 $350 $440 $580 $470 $120 $350

National average $1,300 $3,200 $3,400 $2,600 $2,600 $1,800 $4,200 $2,300 $1,500 $1,900 $2,500 $2,100 $520 $1,900

* These estimates assumed a 50 percent reduction in VOC emissions, an analysis year of 2015, and a 3 percent discount rate. All estimates are rounded to two 

significant digits. These estimates have been adjusted from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currency year and EPA’s current VSL 

estimate. However, these estimates have not been updated to reflect recent epidemiological studies for mortality studies, morbidity studies, or population data.

Using a discount rate of 7 percent, the benefit-per-ton estimates would be approximately 9 percent lower. Assuming a 75 percent reduction in VOC emissions 

would increase the benefit-per-ton estimates by approximately 4 percent to 52 percent. Assuming a 25 percent reduction in VOC emissions would decrease the 

benefit-per-ton estimates by 5 percent to 52 percent. EPA generally presents a range of benefits estimates derived from the expert functions from Roman et al.

(2008) as a characterization of uncertainty.
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4.4.2 Organic PM welfare effects

According to the previous residual risk assessment for this sector (U.S. EPA, 2012a), 

persistent and bioaccumulative HAP reported as emissions from oil and 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 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 

aquatic food webs was demonstrated in high elevation mountain lakes with no other 

anthropogenic contaminant sources.

The recently completed Western Airborne Contaminants Assessment Project (WACAP) 

is the most comprehensive database on contaminant transport and PM depositional effects 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, an elevational 

gradient in PM deposition exists with greater accumulation in higher altitude areas, and 

contaminants accumulate in proximity to individual agriculture and industry sources, which is 
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counter to the original working hypothesis that most of the contaminants would originate from 

Eastern Europe and Asia.

4.4.3 Visibility Effects

Reducing secondary formation of PM2.5 from VOC emissions would improve 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 generally higher concentrations of fine particles, particularly sulfates, and higher 

average relative humidity levels. Visibility has direct significance to 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. Without air quality modeling, we are unable to 

estimate visibility related benefits, nor are we able to determine whether VOC emission 

reductions would be likely to have a significant impact on visibility in urban areas or Class I 

areas.

4.5 VOC as an Ozone Precursor

This rulemaking would reduce emissions of VOC, which are also precursors to secondary 

formation of 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 

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). Therefore, reducing these emissions 

would reduce ozone formation, human exposure to ozone, and the incidence of ozone-related 

health effects. However, we have not quantified the ozone-related benefits in this analysis for 

several reasons. First, previous rules have shown that the monetized benefits associated with 

reducing ozone exposure are generally smaller than PM-related benefits, even when ozone is the 

pollutant targeted for control (U.S. EPA, 2010a, 2014b). Second, the complex non-linear 

chemistry of ozone formation introduces uncertainty to the development and application of a 
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benefit-per-ton estimate, particularly for sectors with substantial new growth. Third, the impact 

of reducing VOC emissions is spatially heterogeneous depending 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 ozone benefits associated with reducing VOC emissions. Due to the high degree of 

variability in the responsiveness of ozone formation to VOC emission reductions and data 

limitations regarding the location of new and modified well sites, we are unable to estimate the 

effect that reducing VOC will have on ambient ozone concentrations without air quality 

modeling.

4.5.1 Ozone health effects and valuation

Reducing ambient ozone concentrations is associated with significant human health 

benefits, including mortality and 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 

generally quantifies 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, school loss days, as well as 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.

In a recent EPA analysis, EPA estimated that reducing 15,000 tons of VOC from 

industrial boilers resulted in $3.6 to $15 million (2008$) of monetized benefits from reduced 

ozone exposure (U.S. EPA, 2011b).39 After updating the currency year to 2012$, this implies a 

 

39 While EPA has estimated the ozone benefits for many scenarios, most of these scenarios also reduce NOX

emissions, which make it difficult to isolate the benefits attributable to VOC reductions.
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benefit-per-ton for ozone of $260 to $1,070 per ton of VOC reduced. Since EPA conducted the 

analysis of industrial boilers, EPA published the Integrated Science Assessment for Ozone (U.S. 

EPA, 2013), the Health Risk and Exposure Assessment for Ozone (U.S. EPA, 2014a), and the 

RIA for the proposed Ozone NAAQS (U.S. EPA, 2014b). Therefore, the ozone mortality studies 

applied in the boiler analysis, while current at that time, do not reflect the most updated literature 

available. The selection of ozone mortality studies used to estimate benefits in RIAs was 

revisited in the RIA for the proposed Ozone NAAQS. Applying the more recent studies would 

lead to benefit-per-ton estimates for ozone within the range shown here. While these ranges of 

benefit-per-ton estimates provide useful context, the geographic distribution of VOC emissions 

from the oil and gas sector are not consistent with emissions modeled in the boiler analysis.

Therefore, we do not believe that those estimates to provide useful estimates of the monetized 

benefits of this rule, even as a bounding exercise.

4.5.2 Ozone vegetation effects

Exposure to ozone has been 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 or impair the 

intended use of the plant or ecosystem. Such effects are considered adverse to the public welfare 

and can include reduced growth and/or biomass production in sensitive trees, reduced yield and 

quality of crops, visible foliar injury, species composition shift, and changes in ecosystems and 

associated ecosystem services.

4.5.3 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). A recent United Nations Environment Programme (UNEP) study 
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reports that the threefold increase in ground level ozone during the past 100 years makes it the 

third most important contributor to human contributed climate change behind CO2 and methane.

This quantifiable influence of ground level ozone on climate leads to increases in global surface 

temperature and changes in hydrological cycles. 

4.6 Hazardous Air Pollutant (HAP) Benefits

When looking at exposures from all air toxic sources of outdoor origin across the U.S., we 

see that emissions declined by approximately 42 percent since 1990. However, despite this 

decline, the 2005 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, 2011d).40 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, U.S. EPA conducts the NATA.41 The most recent NATA was conducted for 

calendar year 2005 and was released in March 2011. 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

4) Characterizing potential public health risk due to inhalation of air toxics including both 

cancer and noncancer effects

Based on the 2005 NATA, EPA estimates that about 5 percent of census tracts 

nationwide have increased cancer risks greater than 100 in a million. The average national cancer 

risk is about 50 in a million. Nationwide, the key pollutants that contribute most to the overall 

 

40 The 2005 NATA is available on the Internet at http://www.epa.gov/ttn/atw/nata2005/.

41 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 2005 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. (2011) 2005 National-Scale 

Air Toxics Assessment. http://www.epa.gov/ttn/atw/nata2005/
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cancer risks are formaldehyde and benzene. 42,43 Secondary formation (e.g., formaldehyde 

forming from other emitted pollutants) was the largest contributor to cancer risks, while 

stationary, mobile and background sources contribute almost equal portions of the remaining

cancer risk.

Noncancer health effects can result from chronic,44 subchronic,45 or acute46 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 2005 

NATA, about three-fourths 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 2005 NATA indicate that acrolein is the primary driver for noncancer 

respiratory risk.

Figure 4-2 and Figure 4-3 depict the 2005 NATA estimated census tract-level 

carcinogenic risk and noncancer respiratory hazard from the assessment. It is important to note 

that large reductions in HAP emissions may not necessarily translate into significant reductions 

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 double acrolein 

emissions on a national basis in EPA’s 2005 National Emissions Inventory (NEI). However, the 

Integrated Risk Information System (IRIS) reference concentration (RfC) for acrolein is 

considerably lower than that for acetaldehyde, suggesting that acrolein could be potentially more 

 

42 Details on EPA’s approach to characterization of cancer risks and uncertainties associated with the 2005 NATA 

risk estimates can be found at http://www.epa.gov/ttn/atw/nata1999/riskbg.html#Z2.

43 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/ttn/atw/nata/roy/page16.html.

44 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).

45 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).

46 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.
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toxic than acetaldehyde. 47 Thus, it is important to account for the toxicity and exposure, as well 

as the mass of the targeted emissions. 

Figure 4-223 Figure 4-2 2005 NATA Model Estimated Census Tract Carcinogenic Risk 

from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics 

Inventory

 

47 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://cfpub.epa.gov/ncea/iris/compare.cfm.
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Figure 4-3 2005 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk 

from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics 

Inventory

Due to methodology and data limitations, we were unable to estimate the benefits 

associated with the hazardous air pollutants that would be reduced 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 

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 
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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 

benefit analysis is to describe the benefits most likely to occur from a reduction in pollution, use 

of high-end, conservative risk estimates would overestimate the benefits of the regulation. While 

we used high-end risk estimates in past analyses, advice from the EPA’s Science Advisory Board 

(SAB) recommended that we avoid using high-end estimates in benefit analyses (U.S. EPASAB, 2002). Since this 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 benefits of reductions in cancer incidences requires 

several important inputs, including central estimates of cancer risks, estimates of exposure to 

carcinogenic HAP, and estimates of the value of an avoided case of cancer (fatal and non-fatal). 

Due to methodology and data limitations, we did not attempt to monetize the health benefits of 

reductions in HAP in this analysis. Instead, we provide a qualitative analysis of the health effects 

associated with the HAP anticipated to be reduced by this rule. EPA remains committed to 

improving methods for estimating HAP benefits by continuing to explore additional concepts of 

benefits, including changes in the distribution of risk. 
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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 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 avoid or reduce 2,500 tons of HAP in 2025.

With the data available, it was not possible to estimate the tons of each individual HAP that 

would be reduced.

4.6.1 Benzene

The EPA’s IRIS database lists benzene as a known human carcinogen (causing leukemia) 

by all routes of exposure, and concludes that exposure is associated with additional health 

effects, including genetic changes in both humans and animals and increased proliferation of 

bone marrow cells in mice.48,49,50 EPA states in its IRIS database that data indicate a causal 

relationship between benzene exposure and acute lymphocytic leukemia and suggest a 

relationship between benzene exposure and chronic non-lymphocytic leukemia and chronic 

lymphocytic leukemia. The International Agency for Research on Carcinogens (IARC) has 

determined that benzene is a human carcinogen and the U.S. Department of Health and Human 

Services has characterized benzene as a known human carcinogen.51,52 A number of adverse 

 

48 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.

49 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. 

50 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.

51 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.

52 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens 

available at: http://ntp.niehs.nih.gov/go/16183.
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noncancer health effects including blood disorders, such as preleukemia and aplastic anemia, 

have also been associated with long-term exposure to benzene.53,54 The most sensitive noncancer 

effect observed in humans, based on current data, is the depression of the absolute lymphocyte 

count in blood.55,56 In addition, recent work, including studies sponsored by the Health Effects 

Institute (HEI), provides evidence that biochemical responses are occurring at lower levels of 

benzene exposure than previously known.57,58,59,60EPA’s IRIS program has not yet evaluated these 

new data.

4.6.2 Toluene61

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 

 

53 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197.

54 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541-554.

55 Rothman, N., G.L. Li, M. Dosemeci, W.E. Bechtold, G.E. Marti, Y.Z. Wang, M. Linet, L.Q. Xi, W. Lu, M.T. 

Smith, N. Titenko-Holland, L.P. Zhang, W. Blot, S.N. Yin, and R.B. Hayes (1996) Hematotoxicity among 

Chinese workers heavily exposed to benzene. Am. J. Ind. Med. 29: 236-246.

56 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene 

(Noncancer Effects). Research and Development, National Center for Environmental Assessment, Washington, 

DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm.

57 Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; Cohen, B.; Melikian, A.; Eastmond, D.; Rappaport, S.; Li, H.; 

Rupa, D.; Suramaya, R.; Songnian, W.; Huifant, Y.; Meng, M.; Winnik, M.; Kwok, E.; Li, Y.; Mu, R.; Xu, B.; 

Zhang, X.; Li, K. (2003). HEI Report 115, Validation & Evaluation of Biomarkers in Workers Exposed to 

Benzene in China.

58 Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohen, et al. (2002). Hematological changes among Chinese 

workers with a broad range of benzene exposures. Am. J. Industr. Med. 42: 275-285.

59 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels 

of Benzene. Science 306: 1774-1776.

60 Turtletaub, K.W. and Mani, C. (2003). Benzene metabolism in rodents at doses relevant to human exposure from 

Urban Air. Research Reports Health Effect Inst. Report No.113.

61 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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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 

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.

4.6.3 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.62 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.63

4.6.4 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 

 

62 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.

63 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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petroleum and is found in gasoline and diesel fuels. Acute (short-term) exposure to ethylbenzene

in humans results in respiratory effects such as throat irritation and chest constriction, and 

irritation of the eyes, and neurological effects such as dizziness. Chronic (long-term) exposure of 

humans to ethylbenzene may cause eye and lung irritation, with possible adverse effects on the 

blood. Animal studies have reported effects on the blood, liver, and kidneys and endocrine 

system from chronic inhalation exposure to ethylbenzene. No information is available on the 

developmental or reproductive effects of ethylbenzene in humans, but animal studies have 

reported developmental effects, including birth defects in animals exposed via inhalation. Studies 

in rodents reported increases in the percentage of animals with tumors of the nasal and oral 

cavities in male and female rats exposed to ethylbenzene via the oral route.64,65 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).66,67 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.

 

64 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.

65 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.

66 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.

67 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.
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4.6.5 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.68 Other reported effects include labored 

breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and 

kidneys.69 Long-term inhalation exposure to xylenes in humans has been associated with a 

number of effects in the nervous system including headaches, dizziness, fatigue, tremors, and 

impaired motor coordination.70 EPA has classified mixed xylenes in Category D, not classifiable 

with respect to human carcinogenicity.

4.6.6 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 the EPA 

has classified hexane in Group D, not classifiable as to human carcinogenicity.71

 

68 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.

69 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.

70 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.

71 U.S. EPA. 2005. Guidelines for Carcinogen Risk Assessment. EPA/630/P-03/001B. Risk Assessment Forum, 

Washington, DC. March. Available on the Internet at <http://www.epa.gov/ttn/atw/cancer_guidelines_final_3-

25-05.pdf>.
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4.6.7 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.72

4.7 Secondary Air Emissions Impacts

The control techniques to meet the standards are associated with several types of secondary 

emissions impacts, which may partially offset the direct benefits of this rule. Table 4-7 shows the 

estimated secondary emissions impacts. Relative to the direct emission reductions anticipated 

from this rule, the magnitude of these secondary air pollutant impacts is small.

Table 4-64-6 Secondary Air Pollutant Impacts (short tons per year)

2020

Emissions Category CO2 NOX PM CO THC

Total Hydraulically Fractured and Refractured Oil Well Completions 580,000 300 10 1,600 620

Fugitive Emissions minimal minimal minimal minimal minimal

Pneumatic Pumps 24,000 12 0 66 25

Pneumatic Controllers 0 0 0 0 0

Compressors 550 0 0 2 1

Total 2020 610,000 310 10 1,700 640

2025

Emissions Category CO2 NOX PM CO THC

Total Hydraulically Fractured and Refractured Oil Well Completions 610,000 310 11 1,700 640

Fugitive Emissions minimal minimal minimal minimal minimal

Pneumatic Pumps 140,000 72 0 400 150

Pneumatic Controllers 0 0 0 0 0

Compressors 3,300 2 0 9 3

Total in 2025 750,000 380 11 2,100 790

In addition, Table 4-7 presents summary-level secondary emissions impacts across 

regulatory options. Note that tThe secondary emision impacts for regulatoryall three options are 

 

72 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris
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equal across the optionsthe same. This result holds because the only requirements varied across 

the options is the coverage (Option 2a1 excludes low production well sites) or frequency 

(Moving from Option 1 to Option increasesOption 3 requires annual monitoring the frequency 

of survey and repair under the fugitive emissions requirement) and secondary emissions from the 

fugitive emissionsunder the fugitive emissions program. requirements are expected to be 

minimal. We are not estimating the monetized disbenefits of the secondary emissions of CO2

because much of the methane that would have been released in the absence of the flare would 

have eventually oxidized into CO2 in the atmosphere. Note that the CO2 produced from the 

methane oxidizing in the atmosphere is not included in the calculation of the SC-CH4.

However, EPA does recognize that because the growth rate of the SC-CO2 estimates are 

lower than their associated discount rates, the estimated impact of CO2 produced in the future 

from oxidized methane would be less than the estimated impact of CO2 released immediately 

from flaring, which would imply a small disbenefit associated with flaring. Assuming an average 

methane oxidation period of 8.7 years, consistent with the lifetime used in IPCC AR4, the 

disbenefits associated with destroying one metric ton of methane and releasing the CO2

emissions in 2020 instead of being released in the future via the methane oxidation process is 

estimated to be $5 to $25 per metric ton CH4 depending on the SC-CO2 value or 0.7 percent to 

0.9 percent of the SC-CH4 estimates per metric ton for 2020. The analogous estimates for 2025 

are $7 to $34 per metric ton CH4 or 0.8 percent to 1.0 percent of the SC-CH4 estimates per metric 

ton for 2025.73 While EPA is not accounting for the CO2 disbenefits at this time, we request 

comment on the appropriateness of the monetization of such impacts using the SC-CO2 and 

aspects of the calculation.

Table 4-7 provides a summary of the direct and secondary emissions changes. Based on 

this summary and analysis above, the net impact of both the direct and secondary impacts of this 

proposal would be an improvement in ambient air quality, which would reduce potency of 

 

73 To calculate the disbenefits associated the complete destruction of a ton of CH4 through flaring, EPA took the 

difference between the SC-CO2 at the time of the flaring and in 8.7 years and discounted that value to the time 

of the flaring using the same discount rate as used to estimate the SC-CO2. This value was then scaled by 44/16 

to account for the relative mass of carbon contained in a ton of CH4 versus a ton of CO2. The value of the SCCO2 8.7 years after flaring was estimated by linearly interpolating between the annual SC-CO2 estimates 

reported in the TSD and inflated to 2012 dollars.
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greenhouse gas emissions, reduce exposure to various harmful pollutants, improve visibility 

impairment, and reduce vegetation damage. 

Table 4-74-7 Summary of Emissions Changes Across Options (short tons per year, except 

where noted)

Option 1

Option 2 

(proposed) Option 2a Option 3

Pollutant 2020 2025 2020 2025 2020 2025 2020 2025

Change in 

Direct 

Emissions

Methane 170,000 340180,000 180,000 400,000 170,000 340,000 190,000 470,000

VOC 120,000 1702,000 120,000 180,000 120,000 170,000 130,000 200,000

HAP 310 1,9400 400 2,500 310 1,900 510 3,200

Change in 

Secondary 

Emissions

CO2 610,000 750,000 610,000 750,000 610,000 750,000 610,000 750,000

NOx 310 380 310 380 310 380 310 380

PM 10 11 10 11 10 11 10 11

CO 1,700 2,100 1,700 2,100 1,700 2,100 1,700 2,100

THC 640 790 640 790 640 790 640 790

Net 

Change in 

CO2 Eq. 

Emissions 

CO2 Eq. 

(million 

short 

tons)

4.21 8.52 4.4 9.9 4.4 9.9 4.7 12

CO2 Eq. 

(million 

metric 

tons)

3.87 7.74 4.0 9.0 3.8 7.7 4.2 11

Note: Totals may not sum due to independent rounding.

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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.
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5-1

5 STATUTORY AND EXECUTIVE ORDER REVIEWS

5.1 Executive Order 12866, Regulatory Planning and Review and Executive Order 

13563, Improving Regulation and Regulatory Review

Under section 3(f)(1) Executive Order 12866 (58 FR 51735, October 4, 1993), this action 

is an “economically significant regulatory action” because it is likely to have an annual effect on 

the economy of $100 million or more. Accordingly, the EPA submitted this action to the Office 

of Management and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 FR 

3821, January 21, 2011) and any changes made in response to OMB recommendations have been 

documented in the docket for this action. Tables 6-1 through 6-4 shows the results of the cost and 

benefits analysis for this proposed rule. 

5.2 Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for 

approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 

44 U.S.C. 3501, et seq. The ICR document prepared by the EPA has been assigned EPA ICR 

Numbers ####.## (40 CFR part 60, subpart OOOOa). You can find a copy of the ICR in the 

docket for this rule, and it is briefly summarized here. 

The information to be collected for the proposed NSPS is based on notification, 

recordkeeping and reporting requirements in the NSPS which are mandatory for all operators 

subject to national emission standards. These recordkeeping and reporting requirements are 

specifically authorized by section 114 of the CAA (42 U.S.C. 7414). All information submitted 

to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of 

confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, 

subpart B. 

These proposed rules would require maintenance inspections of the control devices, but 

would not require any notifications or reports beyond those required by the General Provisions. 

The recordkeeping requirements require only the specific information needed to determine 

compliance. For sources subject to the proposed NSPS, burden changes associated with these 

amendments result from the respondents’ annual reporting and recordkeeping burden associated 
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with this proposed rule for this collection (averaged over the first 3 years after the effective date 

of the standards). The burden is estimated to be 92,450 labor hours at a cost of $3,156,605 per 

year. The average hours and cost per regulated entity subject to the NSPS for oil and natural gas 

affected facilities would be 3.9 hours per response and $1,237 per response, based on an average 

of 2,552 operators responding per year providing 92,450 responses per year. Burden is defined at 

5 CFR 1320.3(b).

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. 

Submit your comments on the Agency’s need for this information, the accuracy of the 

provided burden estimates and any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. You may also send your ICRrelated comments to OMB’s Office of Information and Regulatory Affairs via email to 

RIA_submissions@omb.eop.gov, Attention: Desk Officer for the EPA. Since OMB is required 

to make a decision concerning the ICR between 30 and 60 days after receipt, OMB must receive 

comments no later than [insert date 30 days after publication in the Federal Register]. The EPA 

will respond to any ICR-related comments in the final rule. 

5.3 Regulatory Flexibility Act

[Placeholder for Initial Regulatory Flexibility Analysis]

5.4 Unfunded Mandates Reform Act

This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C. 

1531–1538, and does not significantly or uniquely affect small governments. The action imposes 

no enforceable duty on any state, local or tribal governments or the private sector.

5.5 Executive Order 13132: Federalism

This action does not have federalism implications. It will not have substantial direct 
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effects on the states, on the relationship between the national government and the states, or on 

the distribution of power and responsibilities among the various levels of government. These 

final rules primarily affect private industry and would not impose significant economic costs on 

state or local governments.

5.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments

This action has tribal implications. However, it will neither impose substantial direct 

compliance costs on federally recognized tribal governments, nor preempt tribal law. The 

majority of the units impacted by this rulemaking on tribal lands are owned by private entities, 

and tribes will not be directly impacted by the compliance costs associated with this rulemaking. 

There would only be tribal implications associated with this rulemaking in the rare case where a 

unit is owned by a tribal government or a tribal government is given delegated authority to 

enforce the rulemaking. 

The EPA consulted with tribal officials under the EPA Policy on Consultation and 

Coordination with Indian Tribes early in the process of developing this regulation to permit them 

to have meaningful and timely input into its development. Additionally, the EPA has conducted 

meaningful involvement with tribal stakeholders throughout the rulemaking process. We 

provided an update on the methane strategy on the January 29, 2015 NTAA and EPA Air Policy 

call. As required by section 7(a), the EPA’s Tribal Consultation Official has certified that the 

requirements of the Executive Order have been met in a meaningful and timely manner. A copy 

of the certification is included in the docket for this action.

Consistent with previous actions affecting the oil and natural gas sector, there is 

significant tribal interest because of the growth of the oil and natural gas production in Indian 

country. The EPA specifically solicits additional comment on this proposed action from tribal 

officials.
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5.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks

This action is subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it 

is an economically significant regulatory action as defined by Executive Order 12866, and the 

EPA believes that the environmental health or safety risk addressed by this action has a 

disproportionate effect on children. Accordingly, the agency has evaluated the environmental 

health and welfare effects of climate change on children. 

GHGs including methane contribute to climate change and are emitted in significant 

quantities by the oil and gas sector. The EPA believes that the GHG emission reductions 

resulting from implementation of these final guidelines will further improve children’s health. 

The assessment literature cited in the EPA’s 2009 Endangerment Finding concluded that 

certain populations and life stages, including children, the elderly, and the poor, are most 

vulnerable to climate-related health effects. The assessment literature since 2009 strengthens 

these conclusions by providing more detailed findings regarding these groups’ vulnerabilities 

and the projected impacts they may experience.

These assessments describe how children’s unique physiological and developmental 

factors contribute to making them particularly vulnerable to climate change. Impacts to children 

are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental 

health effects resulting from extreme weather events. In addition, children are among those 

especially susceptible to most allergic diseases, as well as health effects associated with heat 

waves, storms, and floods. Additional health concerns may arise in low income households, 

especially those with children, if climate change reduces food availability and increases prices, 

leading to food insecurity within households.

5.8 Executive Order 13211: Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use

Executive Order 13211 (66 FR 28355, May 22, 2001) provides that agencies will prepare 

and submit to the Administrator of the Office of Information and Regulatory Affairs, Office of 
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5-5

Management and Budget, a Statement of Energy Effects for certain actions identified as 

“significant energy actions.” Section 4(b) of Executive Order 13211 defines “significant energy 

actions” as any action by an agency (normally published in the Federal Register) that 

promulgates or is expected to lead to the promulgation of a final rule or regulation, including 

notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: 

(1)(i) that is a significant regulatory action under Executive Order 12866 or any successor order, 

and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; 

or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs 

as a significant energy action.

This action is not a “significant energy action” as defined in Executive Order 13211 (66 

FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. The basis for these determinations follows. 

The EPA used the National Energy Modeling System (NEMS) to estimate the impacts of 

the proposed rule on the United States energy system. The NEMS is a publically-available model 

of the United States energy economy developed and maintained by the Energy Information 

Administration of the DOE and is used to produce the Annual Energy Outlook, a reference 

publication that provides detailed forecasts of the United States energy economy. 

We estimate that natural gas and crude oil production levels remains essentially 

unchanged in 2020, while slight declines are estimated for 2020 for both natural gas (about 4 

billion cubic feet (bcf) or about 0.01 percent) and crude oil production (about 2,000 barrels per 

day or 0.03 percent). Wellhead natural gas prices for onshore lower 48 production are not 

estimated to change in 2020, but are estimated to increase about $0.007 per Mcf or 0.14 percent 

in 2025. Meanwhile, well crude oil prices for onshore lower 48 production are not estimated to 

change, despite the incidence of new compliance costs from the proposed NSPS. Meanwhile, net 

imports of natural gas are estimated to decline slightly in 2020 (by about 1 bcf or 0.05 percent) 

and in 2025 (by about 3 bcf or 0.09 percent). Crude oil imports are estimated to not change in 

2020 and increase by about 1,000 barrels per day (or 0.02 percent) in 2025.

Additionally, the NSPS establishes several performance standards that give regulated 

entities flexibility in determining how to best comply with the regulation. In an industry that is 
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geographically and economically heterogeneous, this flexibility is an important factor in 

reducing regulatory burden. For more information on the estimated energy effects of this 

proposed rule, please see Section 7 of this RIA.

5.9 National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 

(NTTAA), Public Law No. 104–113 (15 U.S.C. 272 note) directs the EPA to use voluntary 

consensus standards (VCS) in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. VCS are technical standards (e.g., materials

specifications, test methods, sampling procedures, and business practices) that are developed or 

adopted by VCS bodies. NTTAA directs the EPA to provide Congress, through OMB, 

explanations when the Agency decides not to use available and applicable VCS.

The proposed rule involves technical standards. Therefore, the requirements of the 

NTTAA apply to this action. We are proposing 40 CFR part 60, subpart OOOOa to allow 

ANSI/ASME PTC 19.10–1981, Flue and Exhaust Gas Analyses (Part 10) to be used in lieu of 

EPA Methods 3B, 6, 6A, 6B, 15A and 16A manual portions only and not the instrumental 

portion. This standard is available from the American Society of Mechanical Engineers (ASME), 

Three Park Avenue, New York, NY 10016–5990. 

The EPA welcomes comments on this aspect of the proposed rulemaking and, 

specifically, invites the public to identify potentially-applicable VCS and to explain why such 

standards should be used in this regulation.

5.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations

The EPA believes the human health or environmental risk addressed by this action will 

not have potential disproportionately high and adverse human health or environmental effects on 

minority, low-income or indigenous populations. The EPA has determined this because the 

rulemaking increases the level of environmental protection for all affected populations without 
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having any disproportionately high and adverse human health or environmental effects on any 

population, including any minority, low-income or indigenous populations. The EPA has 

provided meaningful participation opportunities for minority, low-income, indigenous 

populations and tribes during the pre-proposal period by conducting community calls and 

webinars. Additionally, the EPA will conduct outreach for communities after the rulemaking is 

finalized.
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6-1

6 COMPARISON OF BENEFITS AND COSTS

Tables 6-1 though Table 6-43 present the summary of the benefits, costs, and net benefits 

for the NSPS across regulatory options. , where Table 6-1 presents the proposed option, Table 6-

2 presents a less stringent regulatory option, and Table 6-3 presents a more stringent regulatory 

option. Table 6-54 provides a summary of the direct and secondary emissions changes for each 

regulatory option.

Table 6-16-1 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 

(Proposed Option) in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits1 $200 million $470 million

Total Costs2 $150 million $310 million

Net Benefits3 $40 43 million $160 million

Non-monetized Benefits

Non-monetized climate benefits Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 120,000 tons of VOC 

reduced

Health effects of PM2.5 and ozone 

exposure from 170,000 tons of VOC 

reduced

Health effects of HAP exposure from 

310 tons of HAP reduced

Health effects of HAP exposure from 

1,900 tons of HAP reduced

Health effects of ozone exposure from 

170,000 tons of methane

Health effects of ozone exposure from 

340,000 tons of methane

Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes 

of this table, we show the benefits associated with the model average a 3 percent discount rate. However, we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the 

additional benefit estimates range from $89 million to $530 million in 2020 and $220 million to $1,200 million in 

2025 for the proposed option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for 

details.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.
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Table 6-26-2 Summary of the Monetized Benefits, Costs, and Net Benefits for the 

Proposed Option 2 (Proposed Option) in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits1 $210 million $550 million

Total Costs2 $170 million $420 million

Net Benefits3 $35 million $120 million

Non-monetized Benefits

Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 120,000 tons of VOC 

reduced

Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 180,000 tons of VOC 

reduced

Health effects of HAP exposure

from 400 tons of HAP reduced

Health effects of ozone exposure 

from 180,000 tons of methane

Health effects of HAP exposure from 

2,500 tons of HAP reduced

Health effects of ozone exposure 

from 400,000 tons of methane

Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes 

of this table, we show the benefits associated with the model average a 3 percent discount rate. However, we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the 

additional benefit estimates range from $93 million to $550 million in 2020 and $250 million to $1,400 million in 

2025 for the proposed option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 4.0 million metric tons in 2020 and 9.0 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for 

details.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.
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Table 6-36-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 

2athe Less Stringent Option in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits1 $200 million $460 million

Total Costs2 $150 million $320 million

Net Benefits3 $42 million $150 million

Non-monetized Benefits

Non-monetized climate benefits Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 120,000 tons of VOC 

reduced

Health effects of PM2.5 and ozone 

exposure from 170,000 tons of VOC 

reduced

Health effects of HAP exposure from 

310 tons of HAP reduced

Health effects of HAP exposure from 

1,900 tons of HAP reduced

Health effects of ozone exposure from 

170,000 tons of methane

Health effects of ozone exposure from 

340,000 tons of methane

Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes 

of this table, we show the benefits associated with the model average at a 3 percent discount rate. However we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the 

additional benefit estimates range from $88 million to $520 million in 2020 and $220 million to $1,200 million in 

2025 for this less stringent option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.
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Table 6-46-4 Summary of the Monetized Benefits, Costs, and Net Benefits for the More 

Stringent Option Option 3 in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits1 $220 million $640 million

Total Costs2 $210 million $680 million

Net Benefits3 $7.6 million -$35 million

Non-monetized Benefits

Non-monetized climate benefits Non-monetized climate benefits

Health effects of PM2.5 and ozone 

exposure from 130,000 tons of VOC 

reduced

Health effects of PM2.5 and ozone 

exposure from 200,000 tons of VOC 

reduced

Health effects of HAP exposure from 

510 tons of HAP reduced

Health effects of HAP exposure from 

3,200 tons of HAP reduced

Health effects of ozone exposure from 

190,000 tons of methane

Health effects of ozone exposure from 

470,000 tons of methane

Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) 

(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes 

of this table, we show the benefits associated with the model average at a 3 percent discount rate. However we 

emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the 

additional benefit estimates range from $99 million to $590 million in 2020 and $300 million to $1,700 million in 

2025 for this more stringent option, as shown in Section 4.3. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are 4.2 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control 

technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue 

from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for 

the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not 

change when using a 3 percent discount rate.

3 Estimates may not sum due to independent rounding.
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Table 6-5 Summary of Emissions Changes across Options for the NSPS in 2020 and 

2025 (short tons per year, unless otherwise noted)

Option 1

Option 2 

(proposed) Option 2a Option 3

Pollutant 2020 2025 2020 2025 2020 2025 2020 2025

Change in 

Direct 

Emissions

Methane 170,000 180,000 180,000 400,000 170,000 340,000 190,000 470,000

VOC 120,000 12,000 120,000 180,000 120,000 170,000 130,000 200,000

HAP 290 400 400 2,500 310 1,900 510 3,200

Change in 

Secondary 

Emissions

CO2 610,000 750,000 610,000 750,000 610,000 750,000 610,000 750,000

NOx 310 380 310 380 310 380 310 380

PM 10 11 10 11 10 11 10 11

CO 1,700 2,100 1,700 2,100 1,700 2,100 1,700 2,100

THC 640 790 640 790 640 790 640 790

Net Change 

in CO2 Eq. 

Emissions 

CO2 Eq. 

(million 

short tons)

4.1 8.2 4.4 9.9 4.4 9.9 4.7 12

CO2 Eq. 

(million 

metric 

tons)

3.7 7.4 4.0 9.0 3.8 7.7 4.2 11
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7-1

7 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS

7.1 Introduction

This section includes three sets of analyses for the proposed NSPS:

 Energy System Impacts

 Initial Regulatory Flexibility Analysis

 Employment Impacts

7.2 Energy System Impacts Analysis 

We use the National Energy Modeling System (NEMS) to estimate the impacts of the 

proposed NSPS on the U.S. energy system. The impacts we estimate include changes in drilling 

activity, price and quantity changes in the production and consumption of crude oil and natural 

gas, and changes in international trade of crude oil and natural gas. We evaluate whether and to 

what extent the increased production costs imposed by the proposed rule might alter the mix of 

fuels consumed at a national level. A brief conceptual discussion about our energy system 

impacts modeling approach is necessary before going into detail on NEMS, how we 

implemented the regulatory impacts, and presenting results.

Economically, it is possible to view the recovered natural gas as an explicit output or as 

contributing to an efficiency gain in production at the producer level. For example, the analysis 

for the proposed rule shows that performing reduced emissions completions on hydraulicallyfractured oil wells contributes about 75 percent of the natural gas captured by emissions controls

in 2020 and about 32 percent of captured natural gas in 2025. The fugitive emissions program at 

well sites is expected to capture about 18 percent of the natural gas captured by emissions 

controls in 2020 and about 52 percent of captured natural gas in 2025. 

The assumed $4/Mcf price for natural gas is the price paid to producers at the wellhead.

In the natural gas industry, production is metered at or very near to the wellhead, and producers 

are paid based upon this metered production. Depending on the situation, the gas captured by a 

REC is sent through a temporary or permanent meter. Payments for the gas are typically made 

within 30 days.
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In the engineering cost analysis, it is necessary to estimate the expected costs and 

revenues from implementing emissions controls at the unit level. Because of this, we estimate the 

net costs as expected costs minus expected revenues for representative units. On the other hand, 

NEMS models the profit maximizing behavior of representative project developers at a drilling 

project level. The net costs of the regulation alter the expected discounted cash flow of drilling 

and implementing oil and gas projects, and the behavior of the representative drillers adjusts 

accordingly. While in the regulatory case natural gas drilling has become more efficient because 

of the gas recovery, project developers still interact with markets for which supply and demand 

are simultaneously adjusting. Consequently, project development adjusts to a new equilibrium.

While we believe the cost savings as measured by revenues from selling recovered gas 

(engineering costs) and measured by cost savings from averted production through efficiency 

gains (energy economic modeling) are approximately the same, it is important to note that the 

engineering cost analysis and the national-level cost estimates do not incorporate economic 

feedbacks such as supply and demand adjustments.

7.2.1 Description of the Department of Energy National Energy Modeling System

NEMS is a model of U.S. energy economy developed and maintained by the Energy 

Information Administration of the U.S. Department of Energy (DOE). NEMS is used to produce 

the Annual Energy Outlook, a reference publication that provides detailed forecasts of the energy 

economy from the current year to 2040. DOE first developed NEMS in the 1980s, and the model 

has undergone frequent updates and expansion since. DOE uses the modeling system extensively 

to produce issue reports, legislative analyses, and respond to Congressional inquiries.

EIA is legally required to make the NEMS system source code available and fully 

documented for the public. The source code and accompanying documentation is released 

annually when a new Annual Energy Outlook is produced. Because of the availability of the 

NEMS model, numerous agencies, national laboratories, research institutes, and academic and 

private-sector researchers have used NEMS to analyze a variety of issues.

NEMS models the dynamics of energy markets and their interactions with the broader 

U.S. economy. The system projects the production of energy resources such as oil, natural gas, 

coal, and renewable fuels, the conversion of resources through processes such as refining and 
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7-3

electricity generation, and the quantity and prices for final consumption across sectors and 

regions. The dynamics of the energy system are governed by assumptions about energy and 

environmental policies, technological developments, resource supplies, demography, and 

macroeconomic conditions. An overview of the model and complete documentation of NEMS 

can be found at < http://www.eia.gov/forecasts/aeo/>.

NEMS is a large-scale, deterministic mathematical programming model. NEMS 

iteratively solves multiple models, linear and non-linear, using nonlinear Gauss-Seidel methods 

(Gabriel et al. 2001). What this means is that NEMS solves a single module, holding all else 

constant at provisional solutions, then moves to the next model after establishing an updated 

provisional solution.

NEMS provides what EIA refers to as “mid-term” projections to the year 2040. For this 

RIA, we draw upon the same assumptions and model used in the Annual Energy Outlook 2014.74

The RIA baseline is consistent with that of the Annual Energy Outlook 2014 which is used 

extensively in Section 2 in the Industry Profile. 

7.2.2 Inputs to National Energy Modeling System

To model potential impacts associated with the proposed rule, we modified oil and gas 

production costs within the Oil and Gas Supply Module (OGSM) of NEMS and domestic and 

Canadian natural gas production within the Natural Gas Transmission and Distribution Module 

(NGTDM). The OGSM projects domestic oil and gas production from onshore, offshore, 

Alaskan wells, as well as having a smaller-scale treatment of Canadian oil and gas production 

(U.S. EIA, 2014). The treatment of oil and gas resources is detailed in that oil, shale oil, 

conventional gas, shale gas, tight sands gas, and coalbed methane (CBM) are explicitly modeled.

New exploration and development is pursued in the OGSM if the expected net present value of 

extracted resources exceeds expected costs, including costs associated with capital, exploration, 

development, production, and taxes. Detailed technology and reservoir-level production 

economics govern finding and success rates and costs. 

 

74 Assumptions for the 2014 Annual Energy Outlook can be found at 

<http://www.eia.gov/forecasts/aeo/assumptions/>.
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The structure of the OGSM is amenable to analyzing potential impacts of the proposed 

NSPS. We are able to target additional expenditures for environmental controls required by the 

NSPS on new exploratory and developmental oil and gas production activities. We model the 

impacts of additional environmental costs, as well as the impacts of additional product recovery.

We explicitly model the additional natural gas recovered when implementing the proposed rule.

While the oil production simulated by the OGSM is sent to the refining module (the 

Liquid Fuels Market Module), simulated natural gas production is sent to a transmission and 

distribution network captured in the NGTDM. The NGTDM balances gas supplies and prices 

and “negotiates” supply and consumption to determine a regional equilibrium between supply, 

demand and prices, including imports and exports via pipeline or LNG. Natural gas is 

transported through a simplified arc-node representation of pipeline infrastructure based upon 

pipeline economics.

7.2.2.1 Compliance Costs for Oil and Gas Exploration and Production

As the NSPS affects new emissions sources, we chose to estimate impacts on new 

exploration and development projects by adding costs of environmental regulation to the 

algorithm that evaluates the profitability of new projects. Additional NSPS costs associated with 

reduced emission completions for hydraulically fractured oil well completions are added to the 

drilling and completion costs of oil wells in the OGSM. 

Other costs are operations and maintenance-type costs and are added to fixed operation 

and maintenance (O&M) expenses associated with new projects. The additional expenses are 

estimated and entered on a per well basis, depending on whether the costs would apply to oil 

wells or natural gas wells. We base the per well cost estimates on the engineering costs. Because 

we model natural gas recovery, we do not include revenues from additional product recovery in 

these costs. This approach is appropriate given the structure of the NEMS algorithm that 

estimates the net present value of drilling projects.

One caveat in introducing new cost requirements into the model is that potential barriers 

to obtaining capital may not be adequately incorporated in the model. However, in general, 

potential barriers to obtaining additional capital should be reflected in the annualized cost via 
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7-5

these barriers increasing the cost of capital. With this in mind, assuming the estimates of capital 

costs and product recovery are valid, the NEMS results will reflect barriers to obtaining the 

required capital. A caveat to this is that the estimated unit-level capital costs of controls that are 

newly required at a national-level as a result of the regulation may not incorporate potential 

additional transitional costs as the supply of control equipment adjusts to new demand.

Table 7-1 shows the incremental compliance that accrue to new drilling projects as a 

result of producers having to comply with the NSPS, across sources anticipated in 2020 and 

2025. We estimate those costs as a function of new wells expected to be drilled in a 

representative year. To arrive at estimates of the per well costs, we first identify whether costs

will apply primarily to crude oil wells, to natural gas wells, or to both crude oil and natural gas 

wells.

Based on the baseline projections of successful completions in 2020, we used 35,404 new 

crude oil wells and 8,456 new natural gas wells as the basis of these calculations. We then divide 

the estimated compliance costs for the given emissions point by the appropriate number of 

expected new wells in the year of analysis. The result yields an approximation of per well 

compliance costs. We assume this approximation is representative of the incremental cost faced 

by a producer when evaluating a prospective drilling project (Table 1).

Hydraulically fractured oil wells completions and fugitives at oil and natural gas well 

sites differ slightly from this approach. Drilling and completion costs of new hydraulically 

fractured oil wells are incremented by the weighted average of the cost of performing a REC 

with completion combustion and completion combustion alone. The resulting cost is itself 

weighted by the proportion of new hydraulically fractured oil wells estimated to be affected by 

the regulation (70 percent).

Meanwhile, assuming there is an average of two wells per wells site (see TSD for more 

details), new oil and gas wells face an increased annual cost of one-half of implementing the well 

site fugitive emission requirements.
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Table 7-17-1 Per Well Costs for Environmental Controls Entered into NEMS (2012$)

Emissions Sources/Points

Wells Applied 

To in NEMS

Annualized 

Cost per Unit 

(2012$)

Per New 

Well Costs 

Applied in 

NEMS 

(2012$)

Gas 

Recovery 

per Unit 

(Mcf)

Per New 

Well Gas 

Recovery 

Applied in 

NEMS 

(Mcf)

Well Completions

Hydraulically Fractured Oil 

Well Completions

New 

Hydraulically 

Fractured Oil

Wells

$17,182 / $3723 $7,067 0 0

Fugitive Emissions

Oil Production Well Sites New Oil Wells $2,144 $1,072 38 19

Natural Gas Production 

Well Sites New Gas Wells $2,144 $1,072 158 79

Gathering and Boosting 

Stations New Gas Wells $14,028 $430 1,222 37

Transmission Stations New Gas Wells $13,879 $10 1,938 1

Storage Facilities New Gas Wells $21,049 $37 5,107 9

Reciprocating Compressors

Transmission Stations New Gas Wells $1,748 $5 1,122 3

Storage Facilities New Gas Wells $2,077 $11 1,130 6

Centrifugal Compressors

Storage Facilities New Gas Wells $114,146 $13 0 0

Pneumatic Controllers -

Transmission and Storage 

Stations New Gas Wells $25 $1 0 0

Pneumatic Pumps

Well Sites New Wells $285 $19 0 0

Reporting and Recordkeeping New Wells $1,381,023* $31 0 0

*Note: reporting and recordkeeping costs are assumed to be equally allocated across all new wells.

7.2.2.2 Adding Averted Methane Emissions into Natural Gas Production

A result of controlling methane and VOC emissions from oil and natural gas production 

is that methane that would otherwise be lost to the atmosphere can be directed into the natural 

gas production stream. We chose to model methane capture in NEMS as an increase in natural 

gas industry productivity, ensuring that, within the model, natural gas reservoirs are not 

decremented by production gains from methane capture. We add estimates of the quantities of 

methane captured (or otherwise not vented or combusted) to the base quantities that the OGSM 

model supplies to the NGTDM model. We subdivide the estimates of commercially valuable 

averted emissions by region and well type in order to more accurately portray the economics of 

implementing the environmental technology. Adding the averted methane emissions in this 
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7-7

manner has the effect of moving the natural gas supply curve to the right an increment consistent 

with the technically achievable emissions transferred into the production stream as a result of the 

proposed NSPS.

We enter the increased natural gas recovery into NEMS on a per-well basis for new 

natural gas wells, following an estimation procedure similar to that of entering compliance costs 

into NEMS on a per-well basis for new wells (Table 7-1). For this analysis, however, we were 

unable to incorporate the natural gas recovery from performing RECs on hydraulically fractured 

oil well completions or from other emissions control activities at oil well sites. We hope to make 

this modification in the RIA for the final rule.

7.2.3 Energy System Impacts

As mentioned earlier, we estimate 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. In each of these estimates, we present estimates for the baseline years of 2020 and 

2025 and predicted results for 2020 and 2025 under the proposal. We also presented impacts 

over the 2020 to 2025 time period. For context, we provide estimates of production activities in 

2012. With the exception of examining crude oil and natural gas trade, we focus the analysis on 

onshore oil and natural gas production activities in the continental (lower 48) U.S. We do this 

because off-shore production is not affected by the proposed NSPS and the bulk of the proposed 

rule’s impacts are expected in the continental U.S.

We first report estimates of impacts on crude oil and natural gas drilling activities and 

production. Table 7-2 presents estimates of successful onshore natural gas and crude oil wells 

drilled in the continental U.S. 
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Table 7-27-2 Successful Oil and Gas Wells Drilled (Onshore, Lower 48 States)

Projection, 2020 Projection, 2025 Projection, 2020-25

2012 Baseline NSPS Baseline NSPS Baseline NSPS

Successful Wells Drilled

Natural Gas 10,965 20,298 20,299 24,727 24,800 142,764 142,638

Crude Oil 26,517 24,660 24,660 27,648 27,638 155,201 155,202

Total 37,482 44,959 44,959 52,375 52,438 297,965 297,840

% Change in Successful Wells Drilled from Baseline

Natural Gas 0.00% 0.30% -0.09%

Crude Oil 0.00% -0.04% 0.00%

Total 0.00% 0.12% -0.04%

Results show that the proposed NSPS will have a relatively small impact on onshore well 

drilling in the lower 48 states. Drilling remains essentially unchanged in 2020, but increases for 

natural gas wells in 2025, while decreasing for crude oil wells in 2025. The increase in natural 

gas well drilling in 2025 is somewhat counter-intuitive as production costs have been increased 

under the proposed NSPS. However, given NEMS is a dynamic, multi-period model, it is 

important to examine changes over multiple time periods. Natural gas well drilling over the 2020 

to 2025 period decreases but about 120 wells total. Crude oil drilling, over the same six-year, 

period remains at the same levels.

Table 7-3 shows estimates of the changes in the domestic production of natural gas and 

crude oil under the proposed NSPS.

Table 7-37-3 Annual Domestic Natural Gas and Crude Oil Production (Onshore, Lower 

48 States)

Projection, 2020 Projection, 2025 Projection, 2020-25

2012 Baseline NSPS Baseline NSPS Baseline NSPS

Domestic Production

Natural Gas (trillion cubic feet) 22.075 26.577 26.576 28.931 28.927 167.585 167.576

Crude Oil (million barrels/day) 4.599 7.234 7.234 7.064 7.062 7.174 7.173

Natural Gas 0.00% -0.01% -0.01%

Crude Oil 0.00% -0.03% -0.01%
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7-9

As indicated by the estimated change in the new well drilling activities, the analysis

shows that the proposed NSPS will have a relatively small impact on onshore natural gas and 

crude oil production in the lower 48 states. Again, production levels Drilling remains essentially 

unchanged in 2020, while slight declines are estimated for 2020 for both natural gas (about 4 

billion cubic feet (bcf) or about 0.01 percent) and crude oil production (about 2,000 barrels per 

day or 0.03 percent). Total production over the 2020 to 2025 is also estimated to decline for 

natural gas (by about 9 bcf or 0.01 percent) and crude oil (by about 1,000 barrels per day or 

about 0.01 percent)

Note this analysis estimates no increase in domestic natural gas production, despite some 

environmental controls anticipated to be used in response to the proposed rule capture natural gas 

that would otherwise be emitted (8.2 bcf in 2020 and 19 bcf in 2025). There are two sources for 

this difference. First, we were unable to incorporate into the model the natural gas recovery from 

performing RECs on hydraulically fractured oil well completions or from other emissions control 

activities at oil well sites. Second, NEMS models the adjustment of energy markets to the new

slightly more costly natural gas and crude oil productive activities. At the new post-rule 

equilibrium, producers implementing emissions controls are still anticipated to capture and sell 

the captured natural gas, and this natural gas might offset other production, but not so much as to 

make overall production increase from the baseline projections.

Table 7-4 presents estimates of national average wellhead natural gas and crude oil prices 

for onshore production in the lower 48 states. 

Table 7-47-4 Average Natural Gas and Crude Oil Wellhead Price (Onshore, Lower 48 

States, 2012$)

Projection, 2020 Projection, 2025 Projection, 2020-25

2012 Baseline NSPS Baseline NSPS Baseline NSPS

Lower 48 Average Wellhead Price

Natural Gas (2012$ per Mcf) 2.562 4.458 4.458 5.064 5.071 4.670 4.673

Crude Oil (2012$ per barrel) 94.938 92.913 92.913 104.889 104.887 98.932 98.931

% Change in Lower 48 Average Wellhead Price from Baseline

Natural Gas 0.00% 0.14% 0.06%

Crude Oil 0.00% 0.00% 0.00%
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7-10

Wellhead natural gas prices for onshore lower 48 production are not estimated to change 

in 2020, but are estimated to increase about $0.007 per Mcf or 0.14 percent in 2025. The 

production weighted average price over the 2020 to 2025 period is estimated to increase by 

$0.003 per Mcf or about 0.06 percent. Meanwhile, well crude oil prices for onshore lower 48 

production are not estimated to change, despite the incidence of new compliance costs from the 

proposed NSPS. This is likely result of both the relatively small scale of the costs of the new 

compliance requirements, as well as the fact that oil prices are more a function of global prices 

that are natural gas prices.

Meanwhile, as shown in Table 7-5, net imports of natural gas are estimated to decline 

slightly in 2020 (by about 1 bcf or 0.05 percent), 2025 (by about 3 bcf or 0.09 percent), and 

across the 2020 to 2025 period (by about 4 bcf total or about 0.03 percent). Crude oil imports are 

estimated to not change in 2020, increase by about 1,000 barrels per day (or 0.02 percent) in 

2025 or by about 2,000 barrels per day (or about 0.02 percent) on average during the 2020 to 

2025 time period.

Table 7-57-5 Net Imports of Natural Gas and Crude Oil

Projection, 2020 Projection, 2025 Projection, 2020-25

2012 Baseline NSPS Baseline NSPS Baseline NSPS

Net Imports

Natural Gas (trillion cubic feet) 1.515 -1.901 -1.900 -3.211 -3.208 -15.371 -15.367

Crude Oil (million barrels/day) 8.432 5.781 5.781 6.004 6.005 5.914 5.916

% Change in Net Imports

Natural Gas -0.05% -0.09% -0.03%

Crude Oil 0.00% 0.02% 0.02%

7.3 Initial Regulatory Flexibility Analysis

[Placeholder]

7.4 Employment Impact Analysis

In addition to addressing the costs and benefits of the proposed rule, EPA has analyzed 
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7-11

the impacts of this rulemaking on employment, which are presented in this section.75 While a 

standalone analysis of employment impacts is not included in a standard cost-benefit analysis, 

such an analysis is of particular concern in the current economic climate given continued interest 

in the employment impact of regulations such as this proposed rule. Executive Order 13563, 

states, “Our regulatory system must protect public health, welfare, safety, and our environment 

while promoting economic growth, innovation, competitiveness, and job creation.” 76 A 

discussion of compliance costs, including reporting and recordkeeping requirements, is included 

in Section 3of this RIA. This analysis uses detailed engineering information on labor 

requirements for each of the control strategies identified in this proposed rule in order to estimate 

partial employment impacts for affected entities in the oil and gas industry. These bottom-up, 

engineering-based estimates represent only one portion of potential employment impacts within 

the regulated industry, and do not represent estimates of the net employment impacts of this rule.

First, this section presents an overview of the various ways that environmental regulation can 

affect employment. 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. The section concludes with partial employment 

impact estimates that rely on engineering-based information for labor requirements for each of 

the control strategies identified by the proposed rule.

7.4.1 Employment Impacts of Environmental Regulation

From an economic perspective labor is an input into producing goods and services; if a 

regulation requires that more labor be used to produce a given amount of output, that additional 

labor is reflected in an increase in the cost of production. Moreover, when the economy is at full 

employment, we would not expect an environmental regulation to have an impact on overall 

employment because labor is being shifted from one sector to another. On the other hand, in 

periods of high unemployment, employment effects (both positive and negative) are possible.

 

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).

76 Executive Order 13563 (January 21, 2011). Improving Regulation and Regulatory Review. Section 1. General 

Principles of Regulation, Federal Register, Vol. 76, Nr. 14, p. 3821.
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For example, an increase in labor demand due to regulation may result in a short-term net 

increase in overall employment as workers are hired by the regulated sector to help meet new 

requirements (e.g., to install new equipment) or by the environmental protection sector to 

produce new abatement capital resulting in hiring previously unemployed workers. When 

significant numbers of workers are unemployed, the opportunity costs associated with displacing 

jobs in other sectors are likely to be higher. And, in general, if a regulation imposes high costs 

and does not increase the demand for labor, it may lead to a decrease in employment. The 

responsiveness of industry labor demand depends on how these forces all interact. Economic 

theory indicates that the responsiveness of industry labor demand depends on a number of 

factors: price elasticity of demand for the product, substitutability of other factors of production, 

elasticity of supply of other factors of production, and labor’s share of total production costs. 

Berman and Bui (2001) put this theory in the context of environmental regulation, and suggest 

that, for example, if all firms in the industry are faced with the same compliance costs of 

regulation and product demand is inelastic, then industry output may not change much at all.

Regulations set in motion new orders for pollution control equipment and services. New 

categories of employment have been created in the process of implementing environmental 

regulations. When a regulation is promulgated, one typical response of industry is to order 

pollution control equipment and services in order to comply with the regulation when it becomes 

effective. On the other hand, the closure of plants that choose not to comply – and any changes in 

production levels at plants choosing to comply and remain in operation - occur after the 

compliance date, or earlier in anticipation of the compliance obligation. Environmental 

regulation may increase revenue and employment in the environmental technology industry. 

While these increases represent gains for that industry, they translate into costs to the regulated 

industries required to install the equipment.

Environmental regulations support employment in many basic industries. Regulated firms 

either hire workers to design and build pollution controls directly or purchase pollution control 

devices from a third party for installation. Once the equipment is installed, regulated firms hire 

workers to operate and maintain the pollution control equipment—much like they hire workers 

to produce more output. In addition to the increase in employment in the environmental 

protection industry (via increased orders for pollution control equipment), environmental 
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7-13

regulations also support employment in industries that provide intermediate goods to the 

environmental protection industry. The equipment manufacturers, in turn, order steel, tanks, 

vessels, blowers, pumps, and chemicals to manufacture and install the equipment. Currently in 

most cases there is no scientifically defensible way to generate sufficiently reliable estimates of 

the employment impacts in these intermediate goods sectors.

Berman and Bui (2001) demonstrate using standard neoclassical microeconomics that 

environmental regulations have an ambiguous effect on employment in the regulated sector. The 

theoretical results imply that the effect of environmental regulation on employment in the 

regulated sector is an empirical question and both sets of authors tested their models empirically 

using different methodologies. Berman and Bui (2001) developed an innovative approach to 

examine how an increase in local air quality regulation that reduces nitrogen oxides (NOX) 

emissions affects manufacturing employment in the South Coast Air Quality Management 

District (SCAQMD), which incorporates Los Angeles and its suburbs. During the time frame of 

their study, 1979 to 1992, the SCAQMD enacted some of the country’s most stringent air quality 

regulations. Using SCAQMD’s local air quality regulations, Berman and Bui identify the effect 

of environmental regulations on net employment in the regulated industries.77 The authors find 

that “while regulations do impose large costs, they have a limited effect on employment” 

(Berman and Bui, 2001, p. 269). Their conclusion is that local air quality regulation “probably 

increased labor demand slightly” but that “the employment effects of both compliance and 

increased stringency are fairly precisely estimated zeros, even when exit and dissuaded entry 

effects are included” (Berman and Bui, 2001, p. 269).78

While there is an extensive empirical, peer-reviewed literature analyzing the effect of 

environmental regulations on various economic outcomes including productivity, investment, 

competitiveness as well as environmental performance, there are only a few papers that examine 

the impact of environmental regulation on employment, but this area of the literature has been 

growing. As stated previously in this RIA section, empirical results from Berman and Bui (2001) 

suggest that new or more stringent environmental regulations do not have a substantial impact on 

 

77 Berman and Bui include over 40 4-digit SIC industries in their sample.

78 Including the employment effect of exiting plants and plants dissuaded from opening will increase the estimated 

impact of regulation on employment.
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net employment (either negative or positive) in the regulated sector. Similarly, Ferris, 

Shadbegian, and Wolverton (2014) also find that regulation-induced net employment impacts are 

close to zero in the regulated sector. Furthermore, Gray et al (2014) find that pulp mills that had 

to comply with both the air and water regulations in EPA’s 1998 “Cluster Rule” experienced 

relatively small and not always statistically significant, decreases in employment. Nevertheless, 

other empirical research suggests that more highly regulated counties may generate fewer jobs 

than less regulated ones (Greenstone 2002, Walker 2011). However, the methodology used in 

these two studies cannot estimate whether aggregate employment is lower or higher due to more 

stringent environmental regulation, it can only imply that relative employment growth in some 

sectors differs between more and less regulated areas. List et al. (2003) find some evidence that 

this type of geographic relocation, from more regulated areas to less regulated areas may be 

occurring. Overall, the peer-reviewed literature does not contain evidence that environmental 

regulation has a large impact on net employment (either negative or positive) in the long run 

across the whole economy.

While the theoretical framework laid out by Berman and Bui (2001) still holds for the 

industries affected under these emission guidelines, important differences in the markets and 

regulatory settings analyzed in their study and the setting presented here lead us to conclude that 

it is inappropriate to utilize their quantitative estimates to estimate the employment impacts from 

this proposed regulation. In particular, the industries used in these two studies as well as the 

timeframe (late 1970’s to early 1990’s) are quite different than those in this proposed NSPS. 

Furthermore, the control strategies analyzed for this RIA include implementing RECs, reducing 

fugitive emissions, and reducing emissions from pneumatic controllers, pumps, and reciprocating 

and centrifugal compressors, which are very different than the control strategies examined by 

Berman and Bui.79 For these reasons we conclude there are too many uncertainties as to the 

transferability of the quantitative estimates from Berman and Bui to apply their estimates to 

quantify the employment impacts within the regulated sectors for this regulation, though these 

studies have usefulness for qualitative assessment of employment impacts.

The preceding sections have outlined the challenges associated with estimating net 

 

79 More detail on how emission reductions expected from compliance with this rule can be obtained can be found in 

Section 3 of this RIA.
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employment effects in the regulated sector and in the environmental protection sector. These 

challenges make it very difficult to accurately produce net employment estimates for the whole 

economy that would appropriately capture the way in which costs, compliance spending, and 

environmental benefits propagate through the macro-economy. Given the difficulty with 

estimating national impacts of regulations, EPA has not generally estimated economy-wide 

employment impacts of its regulations in its benefit-cost analyses. However, in its continuing 

effort to advance the evaluation of costs, benefits, and economic impacts associated with 

environmental regulation, EPA has formed a panel of experts as part of EPA’s Science Advisory 

Board (SAB) to advise EPA on the technical merits and challenges of using economy-wide 

economic models to evaluate the impacts of its regulations, including the impact on net national 

employment.80 Once EPA receives guidance from this panel it will carefully consider this input 

and then decide if and how to proceed on economy-wide modeling of employment impacts of its 

regulations.

7.4.2 Labor Estimates Associated with Proposed Requirements

Section 2 of the RIA, in Tables 2-17 and 2-18, presents background information on 

employment and wages in the oil and natural gas industry. As well as producing much of the 

U.S. energy supply, the oil and natural gas industry directly employs a significant number of 

people. Table 2-17Table 2-17 shows employment in six oil and natural gas-related NAICS codes 

from 1990 to 2013.81 The overall trend shows a decline in total industry employment throughout 

the 1990s, hitting a low of 314,000 in 1999, but rebounding to a 2013 peak of 620,000. Crude 

Petroleum and Natural Gas Extraction (NAICS 211111) and Support Activities for Oil and Gas 

Operations (NAICS 213112) employ the majority of workers in the industry. From 1990 to 2013, 

average wages for the oil and natural gas industry have increased. Table 2-18Table 2-18 shows 

real wages (in 2012 dollars) from 1990 to 2013 for the NAICS codes associated with the oil and 

natural gas industry.

The focus of this part of the analysis is on labor requirements related to the compliance 

 

80 For further information see: 

http://yosemite.epa.gov/sab/sabproduct.nsf/0/07E67CF77B54734285257BB0004F87ED?OpenDocument

81 NAICS 211111, 21112, 213111, 213112, 486110, and 486210. 
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actions for the proposed rule, of the affected entities within the oil and natural gas sector. We do 

not estimate any potential changes in labor outside of the affected sector, and, due to data and 

methodology limitations, we do not estimate net employment impacts for the affected sector, 

apart from the partial estimate of the labor requirements related to control strategies. This 

analysis estimates the labor required to the install, operate, and maintain control equipment and 

activities, as well as to perform new reporting and recordkeeping requirements. 

It is important to highlight that unlike the typical case where to reduce output negative 

production externality (i.e., emissions) a firm often has to reduce production, many of the 

emission controls required by the proposed NSPS will simultaneously increase production and 

reduce negative externalities. That is, these controls jointly produce environmental 

improvements and increase output in the regulated sector. New labor associated with 

implementing these controls to comply with the new regulations can also be viewed as additional 

labor increasing output while reducing undesirable emissions. To the extent, however, that these 

rules may require unprofitable investments for some operators, there is a possibility that these 

producers decrease output in response and create downward pressure on labor demand, both in 

the regulated sector and on those sectors using natural gas as an input. This RIA does not include 

quantified estimates of these potential adverse effects on the labor market due to data and 

theoretical challenges, as described above.

No estimates of the labor used to manufacture or assemble pollution control equipment or 

to supply the materials for manufacture or assembly are included because EPA does not currently 

have this information. The labor requirements analysis uses a bottom-up engineering-based 

methodology to estimate employment impacts. The engineering cost analysis summarized in 

Chapter 3 of this RIA includes estimates of the labor requirements associated with implementing 

the regulations. Each of these labor changes may either be required as part of an initial effort to 

comply with the new regulation or required as a continuous or annual effort to maintain 

compliance. We estimate 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). We note that this type of FTE estimate 

cannot be used to make assumptions about the specific number of people involved or whether 

new jobs are created for new employees.
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7-17

The results of this employment analysis of the proposed NSPS are presented in Tables 7-

6 through Table 7-9 for 2020 and 2025 for individual sources regulated under this proposal. 

Table 7-10 presents summary-level labor impacts for all sources. The tables break down the 

installation, operation, and maintenance estimates by type of pollution control evaluated in the 

RIA and present both the estimated hours required and the conversion of this estimate to FTE.

The labor information is based upon the cost analysis presented in the TSD that supports this 

proposal, based upon analysis presented in the RIA developed for the 2012 NSPS and NESHAP 

Amendments for the Oil and Natural Gas Sector (U.S. EPA, 2012). In addition, for the proposed 

NSPS, reporting and recordkeeping requirements were estimated for the entire rule rather than by 

anticipated control requirements; the reporting and recordkeeping estimates are consistent with 

estimates EPA submitted as part of its Information Collection Request (ICR), the estimated costs 

of which are included in the cost estimates presented in Chapter 3. 

Table 7-6 presents estimates labor requirements for hydraulically fractured oil well 

completions. The REC and completion combustion requirements are associated with certain new 

and existing oil well completions. While individual completions occur over a short period of 

time (days to a few weeks), new wells and other existing wells are completed annually. Because 

of these reasons, we assume the REC-related labor requirements are annual.

The per unit estimates of one-time labor requirements associated with implementing 

RECs and completion combustion are drawn from the labor requirements estimated for 

implementing RECs on hydraulically fractured well completions in U.S. EPA (2012). However, 

the labor requirements in that report were based upon a completion that is assumed to last seven 

days (218 hours per completion for a REC or 22 hours labor per completion for completion

combustion). In this analysis, completion events for hydraulically fractured oil wells are assumed 

to last three days, so we multiply the seven-day requirements by 3/7 (93 hours per completion for 

a REC or 9 hours labor per completion for completion combustion).
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Table 7-67-6 Estimates of Labor Required to Comply with Proposed NSPS for 

Hydraulically Fractured Oil Well Completions, 2020 and 2025

Emissions 

Source

Emissions 

Control

Projected 

No. of 

Incr. 

Affected 

Units

Per Unit 

Onetime 

Labor 

Est. 

(hrs)

Per Unit 

Annual 

Labor 

Est. 

(hrs)

Total 

OneTime 

Labor 

Estimate 

(hrs)

Total 

Annual 

Labor 

Estimate 

(hrs)

Onetime 

FTE

Annual 

FTE

2020

Hydraulically Fractured and Re-fractured Oil Well Completions

Development 

Oil Wells

Reduced 

Emission 

Completion

6,903 0 93 0 644,937 0 310

Wildcat and 

Delineation 

Oil Wells

Completion 

Combustion 7,773 0 9 0 73,289 0 35

Total 14,676 N/A N/A 0 718,227 0 345

2025

Hydraulically Fractured and Re-fractured Oil Well Completions

Development 

Oil Wells

Reduced 

Emission 

Completion

6,901 0 93 0 644,751 0 310

Wildcat and 

Delineation 

Oil Wells

Completion 

Combustion 8,066 0 9 0 76,055 0 37

Total 14,967 N/A N/A 0 720,806 0 347

Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the 

per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum 

due to independent rounding.

Table 7-7 presents estimates of labor requirements for fugitive emissions along the

process chain. Consistent with the cost estimates for fugitive emissions presented in the TSD, we 

estimate labor associated with company-level activities and activities at field sites. Companylevel activities include one time activities such as planning the company’s fugitive emissions 

program and annual requirements such as reporting and recordkeeping. Field-level activities 

include semiannual inspection and repair of leaks as proposed. It is important to note, however, 

that the compliance costs estimates for leak inspection were based upon an estimate of the costs 

to hire a contractor to provide the inspection service, but the source providing this information 

does not have a breakdown of the labor component of the rental cost. As a result, the labor 

requirements for the fugitives program are likely underestimates.
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Table 7-77-7 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive 

Emissions, 2020 and 2025

Emissions Source/ 

Emissions 

Control

Projected 

No. of 

Incr. 

Affected 

Units

Per Unit 

Onetime 

Labor 

(hrs)

Per Unit 

Annual 

Labor

(hrs)

Total 

OneTime 

Labor

(hrs)

Total 

Annual 

Labor (hrs)

Onetime 

FTE

Annual 

FTE

2020

Well Sites

Company-level 

Activities Semiannual 

Monitoring/ 

Maintenance

1,004 118.0 0.0 118,429 0 57 0

Site-level Activities 22,080 0.0 14.1 0 311,569 0 150

Gathering and Boosting Stations

Company-level 

Activities

Semiannual 

Monitoring/ 

Maintenance

259 118.0 0.0 30,562 0 15 0

Site-level Activities 259 0.0 108.7 0 28,141 0 14

Transmission Compressor Stations

Company-level 

Activities

Semiannual 

Monitoring/ 

Maintenance

6 118.0 0.0 708 0 0 0

Site-level Activities 6 0.0 108.7 0 652 0 0

Storage Compressor Stations

Company-level 

Activities

Semiannual 

Monitoring/ 

Maintenance

15 118.0 0.0 1,770 0 1 0

Site-level Activities 15 0.0 212.9 0 3,193 0 2

Total 22,360 N/A N/A 151,469 343,555 73 165

2025

Well Sites

Company-level 

Activities

Semiannual 

Monitoring/ 

Maintenance

1,004 118.0 0.0 118,429 0 57 0

Site-level Activities 139,108 5.4 14.1 0 1,962,940 0 944

Gathering and Boosting Stations

Company-level 

Activities

Semiannual 

Monitoring/ 

Maintenance

259 118.0 0.0 30,562 0 15 0

Site-level Activities 1,554 0.0 108.7 0 168,844 0 81

Transmission Compressor Stations

Company-level 

Activities

Semiannual 

Monitoring/ 

Maintenance

6 118.0 0.0 708 0 0 0

Site-level Activities 36 0.0 108.7 0 3,911 0 2

Storage Compressor Stations

Company-level 

Activities

Semiannual

Monitoring/ 

Maintenance

15 118.0 0.0 1,770 0 1 0

Site-level Activities 90 0.0 212.9 0 19,160 0 9

Total 140,788 N/A N/A 151,469 2,154,855 73 1,036

Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the 

per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum 

due to independent rounding.
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

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Most labor required for fugitive emissions is needed at well sites in the field, which 

number in the thousands. Note that the labor requirements estimates increase from 2020 to 2025 

as the number of sites regulated under the proposed NSPS accumulates.

Table 7-8 presents labor requirement estimates for reciprocating and centrifugal 

compressors. Like the estimates for completions, the per unit labor estimates were based on U.S. 

EPA (2012). As relatively little labor is required for reciprocating compressors and relatively few 

affected centrifugal compressors are expected in the future, the estimates of both one-time and 

on-going labor requirements for compressor requirements are minimal.

Table 7-87-8 Estimates of Labor Required to Comply with Proposed NSPS for 

Reciprocating and Centrifugal Compressors, 2020 and 2025

Emissions Source

Emissions 

Control

Projected 

No. of 

Incr. 

Affected 

Units

Per Unit 

Onetime 

Labor 

Est. 

(hrs)

Per Unit 

Annual 

Labor 

Est. 

(hrs)

Total 

OneTime 

Labor 

Estimate 

(hrs)

Total 

Annual 

Labor 

Estimate 

(hrs)

Onetime 

FTE

Annual 

FTE

2020

Compressors

Reciprocating

Monitoring 

and 

Maintenance

67 1 1 67 67 0.0 0.0

Centrifugal Route to 

Control 1 355 0 355 0 0.2 0.0

Total 68 N/A N/A 422 67 0.2 0.0

2025

Compressors

Reciprocating

Monitoring 

and 

Maintenance

402 1 1 67 402 0.0 0.2

Centrifugal Route to 

Control 6 355 0 355 0 0.2 0.0

Total 408 N/A N/A 422 402 0.2 0.2

Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the 

per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum 

due to independent rounding.

Table 7-9 presents the labor requirement estimates for requirements applying to 

pneumatic controllers and pneumatic pumps. Note that pneumatic controllers have no one-time

or continuing labor requirements. While the controls do require labor for installation, operation, 

and maintenance, the required labor is less than that of the controllers that would be used absent 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-21

the regulation (U.S. EPA, 2012). In this instance, we assume the incremental labor requirements 

are zero. Meanwhile, we are currently unable to estimate the labor associated with pneumatic 

pump control activities.

Table 7-97-9 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic 

Controllers and Pumps, 2020 and 2025

Emissions 

Source

Emissions 

Control

Projected 

No. of 

Incr. 

Affected 

Units

Per Unit 

Onetime 

Labor 

Est. 

(hrs)

Per Unit 

Annual 

Labor 

Est. 

(hrs)

Total 

OneTime 

Labor 

Estimate 

(hrs)

Total 

Annual 

Labor 

Estimate 

(hrs)

Onetime 

FTE

Annual 

FTE

2020

Pneumatic 

Controllers

Emissions

Limit 210 0 0 0 0 0 0

Pneumatic 

Pumps

Route to 

Control 2,962 N/A N/A N/A N/A N/A N/A

2025

Pneumatic 

Controllers

Emissions 

Limit 1,260 0 0 0 0 0 0

Pneumatic 

Pumps

Route to 

Control 17,772 N/A N/A N/A N/A N/A N/A

Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the 

per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum 

due to independent rounding.

Table 7-10 presents the labor estimates across all emissions sources. Two main categories 

contain the majority of the labor requirements for the proposed NSPS: implementing reduced 

emissions completions (REC) at hydraulically fracture oil well completions and fugitive 

emissions detection and repair at well sites. The up-front labor requirement to comply with the 

proposed NSPS is estimated at 73 FTEs in 2020 and in 2025. The annual labor requirement to 

comply with proposed NSPS is estimated at about 530 FTEs in 2020 and 1,400 FTEs in 2025.

We note that this type of FTE estimate cannot be used to identify the specific number of people 

involved or whether new jobs are created for new employees, versus displacing jobs from other 

sectors of the economy.
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-22

Table 7-107-10 Estimates of Labor Required to Comply with Proposed NSPS, 2020 

and 2025

Emissions Source

Projected No. 

of 

Incrementally 

Affected Units 

(2020)

Total OneTime Labor 

Estimate 

(hours)

Total 

Annual 

Labor 

Estimate 

(hours)

One-time 

FTE

Annual 

FTE

2020

Hydraulically Fractured and Refractured Oil Well Completions 14,676 0 718,227 0 345

Fugitive Emissions 22,360 151,469 343,555 73 165

Pneumatic Controllers 210 0 0 0 0

Pneumatic Pumps 2,962 N/A N/A N/A N/A

Reciprocating Compressors 67 67 67 0 0

Centrifugal Compressors 1 355 0 0 0

Reporting and Recordkeeping 

Requirements All 0 40,447 0 19

Total 40,276 151,891 1,102,296 73 530

2025

Hydraulically Fractured and Refractured Oil Well Completions 14,967 0 720,806 0 347

Fugitive Emissions 140,788 151,469 2,154,855 73 1,036

Pneumatic Controllers 1,260 0 0 0 0

Pneumatic Pumps 17,772 N/A N/A N/A N/A

Reciprocating Compressors 402 67 402 0 0

Centrifugal Compressors 6 355 0 0 0

Reporting and Recordkeeping 

Requirements All 0 120,447 0 58

Total 175,195 151,891 2,996,510 73 1,441

Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the 

per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum 

due to independent rounding.

7.5 References 

Berman, E. and L. T. M. Bui. 2001. “Environmental Regulation and Labor Demand: Evidence 

from the South Coast Air Basin.” Journal of Public Economics 79(2): 265-295, docket nr. 

EPA-HQ-OAR-2011-0135 at http://www.regulations.gov

Ferris, A., R.J. Shadbegian, and A. Wolverton. 2014. “The Effect of Environmental Regulation 

on Power Sector Employment: Phase I of the Title IV SO2 Trading Program.” Journal of 

the Association of Environmental and Resource Economists 5:173-193. 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-23

Gray, W.B., R.J. Shadbegian, C. Wang, and M. Meral. 2014. “Do EPA Regulations Affect Labor 

Demand? Evidence from the Pulp and Paper Industry.” Journal of Environmental 

Economics and Management: 68, 188-202.

Greenstone, M. 2002. “The Impacts of Environmental Regulations on Industrial Activity: 

Evidence from the 1970 and 1977 Clean Air Act Amendments and the Census of 

Manufactures.” Journal of Political Economy 110(6): 1175-1219.

List, J. A., D. L. Millimet, P. G. Fredriksson, and W. W. McHone. 2003. “Effects of 

Environmental Regulations on Manufacturing Plant Births: Evidence from a Propensity 

Score Matching Estimator.” The Review of Economics and Statistics 85(4): 944-952.

U.S. Bureau of Labor Statistics.

U.S. Census Bureau (Census). 

U.S. Energy Information Administration (U.S. EIA). 2014. Oil and Gas Supply Module of the 

National Energy Modeling System: Model Documentation 2014. July 2014. 

<http://www.eia.gov/forecasts/aeo/nems/documentation/ogsm/pdf/m063(2014).pdf>

Accessed May 10, 2015.

U.S. Energy Information Administration (U.S. EIA). 2014. Model Documentation Report: 

Natural Gas Transmission and Distribution Module of the National Energy Modeling. 

June 2014. 

<http://www.eia.gov/forecasts/aeo/nems/documentation/ngtdm/pdf/m062(2014).pdf> 

Accessed May 10, 2015.

U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis: Final 

New Source Performance Standards and Amendments to the National Emissions 

Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry.

<http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf> 

Accessed December 19, 2014.U.S. Small Business Administration (U.S. SBA), Office of 

Advocacy. 2010. A Guide for Government Agencies, How to Comply with the Regulatory 

Flexibility Act, Implementing the President’s Small Business Agenda and Executive 

Order 13272.

Walker, R. 2011. “Environmental Regulation and Labor Reallocation." American Economic 

Review: 101(3):442-447.
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-24

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-15-002

August 2015