Regulatory Impact Analysis of the Proposed 

Emission Standards for New and Modified 

Sources in the Oil and Natural Gas Sector 

 
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[This page intentionally left blank] 

 
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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 

 
iv 

CONTACT INFORMATION 

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

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

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. 
v 

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 REGULATORY OPTIONS ANALYZED IN THIS RIA .......................................................................................... 1-3

1.4 SUMMARY OF RESULTS ................................................................................................................................ 1-5

1.5 ORGANIZATION OF THIS REPORT ................................................................................................................ 1-10

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 Regulatory Options ............................................................................................................................ 3-5
vi 

3.4.2 Projection of Incrementally Affected Facilities ................................................................................. 3-8

3.4.3 Emissions Reductions ...................................................................................................................... 3-11

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

3.4.5 Engineering Compliance Costs ........................................................................................................ 3-13

3.4.6 Cost-Effectiveness ........................................................................................................................... 3-14

3.4.7 Comparison of Regulatory Alternatives .......................................................................................... 3-18

3.4.8 Capital and Annualized Compliance Costs Compared to Industry-level Capital Expenditures and 

Revenues ........................................................................................................................................................ 3-20

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

3.6 DETAILED IMPACTS TABLES ...................................................................................................................... 3-24

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

4.3.1 Methane climate effects and valuation ............................................................................................... 4-5

4.4 VOC AS A PM2.5 PRECURSOR ...................................................................................................................... 4-17

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.................................................................................................................................... 4-34

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 .............................................................................................................................................. 4-39

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 (RFA) ....................................................................................................... 5-2

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

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

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

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

RISKS ..................................................................................................................................................................... 5-6

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

SUPPLY, DISTRIBUTION, OR USE ............................................................................................................................ 5-7

5.9 NATIONAL TECHNOLOGY TRANSFER AND ADVANCEMENT ACT (NTTAA) AND 1 C.F.R. PART 51 .............. 5-8

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

POPULATIONS AND LOW-INCOME POPULATIONS ................................................................................................... 5-9

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

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

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

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

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

7.3.1 Reasons why Action is Being Considered ....................................................................................... 7-11

7.3.2 Statement of Objectives and Legal Basis for Proposed Rules ......................................................... 7-11

7.3.3 Description and Estimate of Affected Small Entities ...................................................................... 7-13

7.3.4 Compliance Cost Impact Estimates ................................................................................................. 7-17

7.3.4.1 Methodology for Estimating Impacts on Small Entities......................................................... 7-17

7.3.4.2 Results .................................................................................................................................... 7-19

7.3.5 Caveats and Limitations ................................................................................................................... 7-21

7.3.6 Projected Reporting, Recordkeeping and Other Compliance Requirements ................................... 7-21

7.3.7 Related Federal Rules ...................................................................................................................... 7-22

7.3.8 Regulatory Flexibility Alternatives .................................................................................................. 7-23

7.3.8.1 Oil Well Exemptions .............................................................................................................. 7-23

7.3.8.2 Fugitives - Leak Detection Methods ...................................................................................... 7-28

7.3.8.3 Fugitives – Survey Frequency ................................................................................................ 7-29

7.3.8.4 Fugitive Emissions at Well Sites ............................................................................................ 7-30

7.3.8.5 Fugitive Emissions at Production and Processing Sites, and Compressor Stations at 

Transmission and Storage Sites ................................................................................................................. 7-30

7.3.8.6 Well Site Compressors ........................................................................................................... 7-31

7.3.8.7 Pneumatic Pumps ................................................................................................................... 7-31

7.3.8.8 Reciprocating Compressors .................................................................................................... 7-31

7.3.8.9 Centrifugal Compressors ........................................................................................................ 7-32

7.3.8.10 Pneumatic Controllers ............................................................................................................ 7-32

7.3.8.11 Recordkeeping and Reporting for High Bleed Controllers .................................................... 7-33

7.3.8.12 Liquids Unloading .................................................................................................................. 7-33

7.4 EMPLOYMENT IMPACT ANALYSIS .............................................................................................................. 7-33

7.4.1 Employment Impacts of Environmental Regulation ........................................................................ 7-34

7.4.2 Labor Estimates Associated with Proposed Requirements .............................................................. 7-38

7.5 REFERENCES .............................................................................................................................................. 7-46

 
viii 

LIST OF TABLES 

Table 1-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS .............................................. 1-4

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 3 in 2020 and 2025 (2012$) . 

 ......................................................................................................................................................... 1-10

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 ................................................................................ 2-20

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 .............................................................. 3-10

Table 3-3 Emissions Reductions for Proposed NSPS Option 2, 2020 and 2025.............................................. 3-11

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 (millions 

2012$) ......................................................................................................................................................... 3-14

Table 3-6 Single Pollutant Approach to Engineering Compliance Cost-Effectiveness Estimates in 2020 and 

2025 for Proposed NSPS Option 2 (High Impact Case for Well Site Fugitive Emissions Requirements) .............. 3-17

Table 3-7 Multipollutant Approach to Engineering Compliance Cost-Effectiveness Estimates for Proposed 

NSPS Option 2 in 2020 and 2025 (High Impact Case for Well Site Fugitive Emissions Requirements) ............... 3-18

Table 3-8 Comparison of Regulatory Alternatives .......................................................................................... 3-19

Table 3-9 NAICS-Based Capital Expenditure Data ......................................................................................... 3-20

Table 3-10 NAICS-Based Revenue Data ........................................................................................................... 3-21

Table 3-11 Comparison of Proposed NSPS Nationwide Cost by Affected Facility Cost to Industry-wide Capital 

Expenditures and Revenues ..................................................................................................................................... 3-23

Table 3-12 Annualized Costs using 3 and 7 Percent Discount Rates for Proposed NSPS Option 2 in 2020 and 

2025 (millions 2012$) ............................................................................................................................................. 3-24

Table 3-13 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020 ........................... 3-25

Table 3-14 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025 ........................... 3-26

Table 3-15 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact 

Case, 2020 ......................................................................................................................................................... 3-27
ix 

Table 3-16 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact 

Case, 2025 ......................................................................................................................................................... 3-28

Table 3-17 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact 

Case, 2020 ......................................................................................................................................................... 3-29

Table 3-18 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact 

Case, 2025 ......................................................................................................................................................... 3-30

Table 3-19 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020 ........................... 3-31

Table 3-20 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025 ........................... 3-32

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

Table 4-2 Direct Emission Reductions across NSPS Regulatory Options 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., 

2014b

) ......................................................................................................................................................... 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) .................................................................... 4-37

Table 4-7 Summary of Emissions Changes (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 3 in 2020 and 2025 (2012$) . 

 ........................................................................................................................................................... 6-3

Table 6-4 Summary of Emissions Changes across Options for the NSPS in 2020 and 2025 (short tons per year, 

unless otherwise noted) ............................................................................................................................................. 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 SBA Size Standards by NAICS Code .............................................................................................. 7-13

Table 7-7 Distribution of Estimated Compliance Costs across Sources .......................................................... 7-15

Table 7-8 No. of Completions in 2012 by Preliminary Firm Size.................................................................... 7-16

Table 7-9 No. of Completions in 2012 by Firm Size ....................................................................................... 7-16

Table 7-10 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, Low Impact Fugitive 

Emissions Case ........................................................................................................................................................ 7-17

Table 7-11 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, High Impact Fugitive 

Emissions Case ........................................................................................................................................................ 7-18

Table 7-12 Distribution of Estimated Compliance Costs1 across Firm Size Classes ......................................... 7-18

Table 7-13 Compliance Costs-to-Sales1 Ratios (Fugitive Emissions Requirements Low Impact Case) across Firm 

Size Classes for Primary Scenario and Low Oil Price Scenario2 ............................................................................. 7-20

Table 7-14 Compliance Costs-to-Sales1 Ratios (Fugitive Emissions Requirements Low Impact Case) across Firm 

Size Classes for Primary Scenario and Low Oil Price Scenario2

 ............................................................................. 7-20

Table 7-15 Estimates of Labor Required to Comply with Proposed NSPS for Hydraulically Fractured Oil Well 

Completions, 2020 and 2025 ................................................................................................................................... 7-41

Table 7-16 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, Low Impact 

Case, 2020 and 2025 ................................................................................................................................................ 7-42

Table 7-17 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, High Impact 

Case, 2020 and 2025 ................................................................................................................................................ 7-43

Table 7-18 Estimates of Labor Required to Comply with Proposed NSPS for Reciprocating and Centrifugal 

Compressors, 2020 and 2025 ................................................................................................................................... 7-44

Table 7-19 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic Controllers and Pumps, 

2020 and 2025 ......................................................................................................................................................... 7-45

Table 7-20 Estimates of Labor Required to Comply with Proposed NSPS, 2020 and 2025 .............................. 7-46

 
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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 ............................ 2-21

Figure 2-5 Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-2012 ......................... 2-24

Figure 2-6 Forecast of Domestic Crude Oil Production and Net Imports, 2010-2040 ...................................... 2-29

Figure 2-7 Costs of Crude Oil and Natural Gas Wells Drilled, 1981-2008 ....................................................... 2-31

Figure 2-8 Finding Costs for FRS Companies, 1981-2009 ............................................................................... 2-32

Figure 2-9 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2009 (3-year Running Average) .. 

 ......................................................................................................................................................... 2-33

Figure 2-10 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976 

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

Figure 2-11 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 ......................................................................... 4-10

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.............................................................................. 4-28

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
1-1 

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 
1-2 

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, the EPA is required to develop a regulatory impact 

analysis (RIA) for rules that have costs or benefits that exceed $100 million annually. The 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. 
1-3 

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 Regulatory Options Analyzed in this RIA 

In this RIA, we examine three broad regulatory options.2

 Table 1-1 shows the emissions 

 

2

 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. 
1-4 

sources, points, and controls for the three NSPS regulatory options analyzed in this RIA, which 

we term Option 1, Option 2, and Option 3. Option 2 was selected for proposal. Option 1 was 

selected for co-proposal. 

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

Emissions Point Emissions Control Option 1 Option 2 

(proposed) Option 3 

Well Completions and Recompletions 

Hydraulically Fractured 

Development Oil Wells REC / Combustion X X X 

Hydraulically Fractured Wildcat 

and Delineation Oil Wells Combustion X X X 

Fugitive Emissions 

 Well Pads Monitoring and 

Maintenance Annual Semiannual Quarterly 

Gathering and Boosting Stations Monitoring and 

Maintenance Semiannual Semiannual Quarterly 

Transmission Compressor Stations Monitoring and 

Maintenance Semiannual Semiannual Quarterly 

Pneumatic Pumps 

 Well Pads Route to control X X X 

Gathering and Boosting Stations Route to control X X X 

Transmission and Storage 

Compressor Stations Route to control X X X 

Pneumatic Controllers - 

 Natural Gas Transmission and 

Storage Stations Emissions limit X X X 

Reciprocating Compressors 

 Natural Gas Transmission and 

Storage Stations 

Annual Monitoring 

and Maintenance X X X 

Centrifugal Compressors 

 Natural Gas Transmission and 

Storage Stations Route to control X X X 

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 

 

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. 
1-5 

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. However, low production well sites are exempt from the well site 

fugitive requirements. 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.3

Option 2 also requires reductions from centrifugal compressors, reciprocating compressors, 

pneumatic controllers, and pneumatic pumps throughout the oil and natural gas source category. 

While the EPA is proposing an exclusion from fugitive emission requirements for low 

production well sites, there is uncertainty in how many well sites this exclusion might affect in 

the future. As a result, the analyses in this RIA presents a “low” impact case and “high” impact 

case for fugitive emissions requirements at well sites. The low impact case excludes from 

analysis an estimate low production sites, assuming that the fraction of wells meeting the low 

production criteria in the future will be the same as in 2012 (based on the first month of 

production data from wells newly completed or modified in 2012).The high impact case includes 

all forecasted well sites providing a bounding case where no newly completed or modified wells 

meet the low production criteria. Summary results for option 2, then, are presented as ranges. 

Options 1 and 3 differ from the Option 2 with respect to the requirements for fugitive 

emissions. Meanwhile, the co-proposed Option 1 requires annual monitoring for well sites, 

including low production sites, while maintaining semiannual requirements for others sites. 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 co-proposed Option 2. 

1.4 Summary of Results 

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

1-2 through Table 1-4. Note all dollar estimates are in 2012 dollars: 

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

emissions, including 170,000 to 180,000 tons of methane, 120,000 tons of VOCs and 310 

 

3

 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. 
1-6 

to 400 tons of hazardous air pollutants (HAP) in 2020, increasing to 340,000 to 400,000 

tons of methane, 170,000 to 180,000 tons of VOCs, and 1,900 to 2,500 tons of HAP 

prevented in 2025.4

 The CO2-equivalent (CO2 Eq.) methane emission reductions are 3.8 

to 4.0 million metric tons in 2020 and 7.7 to 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).5 The 

EPA estimates that, in 2020, the proposal will yield monetized climate benefits of $88 

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

in an estimate of about $200 to $210 million in 2020. In 2025, the EPA estimates 

monetized climate benefits of $220 million to approximately $1.4 billion; the mean SCCH4 at the 3% discount rate results in an estimate of about $460 to $550 million in 2025.6

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.7

 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: The EPA estimates the total capital cost of the proposed 

NSPS to be $170 to $180 million in 2020 and $280 to $330 million in 2025. The estimate 

of total annualized engineering costs of the proposed NSPS is $180 to $200 million in 

2020 and $370 to $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 $150 to $170 million in 2020 and $320 to 

$420 million in 2025, assuming a wellhead 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 

 

4

 Estimates are presented in short tons. 

5

 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. 

6

 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. 

7

 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. 
1-7 

engineering compliance costs of about $8 million in 2020 and $16 to $19 million in 2025, 

given the EPA estimates that about 8 million Mcf in 2020 and 16 to 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 $490 million in 2025, or $150 to $170 million in 2020 and $310 

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

included.8

• 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.9

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

unchanged in 2020, while slight declines are estimated for 2025 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: To understand the potential impact of the proposed rule of small 

entities the EPA conducted a screening analysis of the potential impacts by estimating the 

ratio of potential compliance costs to firm sales (i.e. a cost-to-sales test). Based on the 

results of this screening analysis, the EPA concluded it is not able to certify that the 

proposed rule will not have a Significant Impact on a Substantial Number of Small 

Entities (SISNOSE). As a result, the EPA initiated a Small Business Advisory Review 

panel and completed an Initial Regulatory Flexibility Analysis.

• Employment Impacts Analysis: The 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 one-time 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 50 to 70 FTEs in 

2020 and in 2025. The annual labor requirement to comply with proposed NSPS is 

estimated at about 470 to 530 FTEs in 2020 and 1,100 to 1,400 FTEs in 2025. We note 

that this type of FTE estimate cannot be used to identify the specific number of people 

 

8

 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. 

9

 The EPA only modeled the high impact case of the proposed NSPS with respect the low production exemption 

from the well site fugitive emissions requirements. As such the NEMS-based estimates of energy system impacts 

are likely high end estimates. 
1-8 

involved or whether new jobs are created for new employees, versus displacing jobs from 

other sectors of the economy. 

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

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

Option 3. The summary results for Option 2 reflects the range from the low impacts to high 

impacts case with respect the well site fugitive emissions requirements. 

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 

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.

 
1-9 

Table 1-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 

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

 2020 2025 

Total Monetized Benefits1 $200 to $210 million $460 to $550 million 

Total Costs2 $150 to $170 million $320 to $420 million 

Net Benefits3

 $35 to $42 million $120 to $150 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 170,000 to 180,000 

tons of VOC reduced 

 Health effects of HAP exposure from 

310 to 400 tons of HAP reduced 

Health effects of ozone exposure from 

170,000 to 180,000 tons of methane 

Health effects of HAP exposure from 

1,900 to 2,500 tons of HAP reduced 

Health effects of ozone exposure from 

340,000 to 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 $88 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 3.8 to 4.0 million metric tons in 2020 and 7.7 to 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.

 
1-10 

Table 1-4 Summary of the Monetized Benefits, Costs, and Net Benefits for 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.

1.5 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. 
2-1 

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 EPA’s “Economic Analysis of Air Pollution Regulations: Oil and 

Natural Gas Production” (1996), the EPA’s “Sector Notebook Project: Profile of the Oil and Gas 
2-2 

Extraction Industry” (2000), and the 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 20o

 or 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. 
2-3 

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 40o or 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). 
2-4 

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 
2-5 

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). 
2-6 

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 
2-7 

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. 
2-8 

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.
2-9 

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. 
2-10 

 

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 
2-11 

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 
2-12 

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
2-13 

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. 

 
2-14 

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 2-5). 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. 
2-15 

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 

 
2-16 

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
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 2-7). These estimates do not include estimates of 

flowback water from hydraulic fracturing activities (ANL 2009). 

 
2-18 

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. 
2-19 

 As can be seen in Table 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, 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 2-3 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 2-8), appearing to 

follow the downward supply trend shown in Table 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 
2-20 

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 2-8 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 and Figure 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 
2-21 

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. 

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

2011 

0%

10%

20%

30%

40%

50%

60%

70%

80%

Consumption (% of total)

Residential and Commercial Industrial

Transportation Sector Electric Power
2-22 

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. 

 
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. 
2-24 

Figure 2-5 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
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 2-12). 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. 

 
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. 

 
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 2-14 presents forecasts of domestic crude oil production, reserves, imports and 6 

depicts these trends graphically. 

 
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 

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 2-14 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 period, 12 
2-29 

percent, showing reserves are forecast to grow more rapidly than production. Table 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 2-6 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
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
2-31 

about 15 percent, and cost per foot has increased on average of about 13 percent per year (Figure 

2-7). 

Figure 2-7 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 2-8 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)
2-32 

Figure 2-8 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 2-7 and finding costs in Figure 2-8 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 2-9 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
2-33 

Figure 2-9 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
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 2-10 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 2-10 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)
2-35 

Figure 2-11 Natural Operating Costs and Equipment Costs Indices (1976=100) and 

Natural Gas Price, 1976-2009 

Figure 2-11 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)
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. 

 
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 2-17 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. 

 
2-38 

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 2-18 shows real wages (in 2012 dollars) from 1990 to 2013 for the NAICS codes 

associated with the oil and natural gas industry. 

 
2-39 

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 
2-40 

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 
2-41 

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 2-19 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. 
2-42 

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. 
2-43 

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

Worldwide Production 

U

Prod

Rank by 

Total 

Assets Company Employees 

Total 

Assets 

($Million) 

Total 

Revenue 

($Million) 

Net 

Income 

($Million) 

Liquids 

(Million 

bbl) 

Natural 

Gas 

(Bcf) 

Liqu

(Mill

bbl

1 ExxonMobil Corp. 76,900 333,795 482,295 47,681 625 2,992 162 Chevron Corp. 17,418 232,982 241,909 26,336 536 1,737 15

3 ConocoPhillips 16,900 117,144 62,004 8,498 271 1,539 12

4 Occidental Petroleum Corp. 12,300 64,210 24,253 4,598 201 1129 10

5 Apache Corp. 5,976 60,737 17,078 2,001 145 938 8

6 Anadarko Petroleum Corp. 5,200 52,589 13,411 2,445 115 916 7

7 Hess Corp. 14,775 43,441 38,373 2,063 110 839 68 Devon Energy Corp. 5,700 43,326 9,502 -206 103 565 59 Chesapeake Energy Corp. 12,000 41,611 12,316 -594 93 557 4

10 Marathon Oil Corp. 3,367 35,306 16,221 1582 78 470 411 EOG Resources Inc. 2,650 27,337 11,683 570 49 416 312 Noble Energy Inc. 2,190 17,554 4,223 1027 42 380 313 Murphy Oil Corp. 9,185 17,523 28,626 971 41 322 214 Plains Exploration and 

Production Co 906 17,298 2,565 343 34 284 2

15 Pioneer Natural Resources Co. 3,667 13,069 3,228 243 26 259 2

16 Linn Energy LLC 1,136 11,451 1,774 -387 25 253 2

17 Denbury Resources Inc. 1,432 11,139 2,456 525 24 249 218 Sandridge Energy Inc. 2,510 9,791 2,731 247 24 249 219 WPX Energy Inc. 1,200 9,456 3,189 -211 22 244 20 Continental Resources Inc. 753 9,140 2,573 416 20 183 

Source: Oil and Gas Journal. “OGJ150 Earnings Down as US Production Climbs.” September 2, 2013. The annual Oil and Gas JourOGJ150, reports financial and operating results for public oil and natural gas companies with domestic reserves and headquarters in 

Notes: The source for employment figures is Hoovers, a D&B Company. 
2-44 

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 
2-45 

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. 
2-46 

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. 
2-47 

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. 

 
2-48 

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. 
2-49 

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. 

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2-51 

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Accessed December 19, 2014.
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 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 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. The 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. The 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 Regulatory 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. In this RIA, we examine three broad 

regulatory options.18 Table 3-1 shows the emissions sources, points, and controls for the three 

NSPS regulatory options analyzed in this RIA, which we term Option 1, Option 2, and Option 3. 

Options 1 and 2 were selected for co-proposal. 

 

 

18 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 re-fractured oil well completions. 
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Table 3-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS 

Emissions Point Emissions Control Option 1 Option 2 

(proposed) Option 3 

Well Completions and Recompletions 

Hydraulically Fractured 

Development Oil Wells REC / Combustion X X X 

Hydraulically Fractured Wildcat 

and Delineation Oil Wells Combustion X X X 

Fugitive Emissions 

 Well Pads Monitoring and 

Maintenance Annual Semiannual Quarterly 

Gathering and Boosting Stations Monitoring and 

Maintenance Semiannual Semiannual Quarterly 

Transmission Compressor Stations Monitoring and 

Maintenance Semiannual Semiannual Quarterly 

Pneumatic Pumps 

 Well Pads Route to control X X X 

Gathering and Boosting Stations Route to control X X X 

Transmission and Storage 

Compressor Stations Route to control X X X 

Pneumatic Controllers - 

 Natural Gas Transmission and 

Storage Stations Emissions limit X X X 

Reciprocating Compressors 

 Natural Gas Transmission and 

Storage Stations 

Annual Monitoring 

and Maintenance X X X 

Centrifugal Compressors 

 Natural Gas Transmission and 

Storage Stations Route to control X X X 

The co-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. However, low production well sites are exempt from the well site 

fugitive requirements. A low production site is defined by the average combined oil and natural 
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gas production for the wells at the site being less than 15 barrels of oil equivalent (boe) per day.19

Option 2 also requires reductions from centrifugal compressors, reciprocating compressors, 

pneumatic controllers, and pneumatic pumps throughout the oil and natural gas source category. 

While the EPA is proposing an exclusion from fugitive emission requirements for low 

production well sites, there is uncertainty in how many well sites this exclusion might affect in 

the future. As a result, the analyses in this RIA presents a “low” impact case and “high” impact 

case for fugitive emissions requirements at well sites. The low impact case excludes from 

analysis an estimate low production sites, assuming that the fraction of wells meeting the low 

production criteria in the future will be the same as in 2012 (based on the first month of 

production data from wells newly completed or modified in 2012).The high impact case includes 

all forecast well sites providing a bounding case where no newly completed or modified wells 

meet the low production criteria. Summary results for option 2, then, are presented as ranges. 

Options 1 and 3 differ from the Option 2 with respect to the requirements for fugitive 

emissions. Meanwhile, the co-proposed Option 1 requires annual monitoring for well sites, 

including low production sites, while maintaining semiannual requirements for others sites. 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 co-proposed Option 2. 

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 

 

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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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. 

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 AEO), 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 

AEO). 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 be reduced. Costs and emissions reductions per facility would 

not be affected, however. 

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 
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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 requirements. 

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 to 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-tooil ratio (GOR) of 300 or below. 

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

Emissions Sources 

Incrementally Affected Sources 

2020 20251

Hydraulically Fractured and Re-fractured Oil Well Completions 15,000 15,000 

Fugitive Emissions2 14,000 to 22,000 86,000 to 140,000 

Pneumatic Pumps 3,000 18,000 

Compressors 68 410 

Pneumatic Controllers 210 1,300 

Total2 31,000 to 40,000 120,000 to 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 low end of the range in the fugitive emissions and total rows reflect the number of incrementally affected 

sources under the low impact co-proposed Option 2, which excludes low production well sites.

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 under-
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represented 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 

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. 

Table 3-3 Emissions Reductions for Proposed NSPS Option 2, 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 63,100,000 

Fugitive Emissions 24,000 to 33,000 6,200 to 8,700 230 to 330 740,000 to 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 170,000 to 180,000 120,000 310 to 400 3,800,000 to 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 150,000 to 210,000 40,000 to 57,000 1,500 to 2,200 3,500,000 to 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 340,000 to 400,000 170,000 to 180,000 2,200 to 2,500 7,700,000 to 9,000,000 
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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, 

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, the 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 
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controls. 

Table 3-4 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 

(millions 2012$) 

Gas recovery 

(Mcf) 

Revenue from 

recovery 

(millions 2012$) 

Oil Well Completions 

and Recompletions 6,200,000 $25 6,200,000 $25 

Fugitive Emissions 1,400,000 to 

1,900,000 $5.1 to $7.3 8,900,000 to 12,000,000 $33 to $47 

Pneumatic Pumps 0 $0 0 $0 

Compressors 76,000 $0 450,000 $0 

Pneumatic Controllers 30,000 $0 180,000 $0 

Total 7,700,000 to 

8,200,000 $30 to $32 16,000,000 to 19,000,000 $58 to $72 

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 

estimated engineering compliance costs of about $8 million in 2020 and $16 to $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 3-5 Engineering Compliance Cost Estimates for Proposed NSPS Option 2 in 

2020 and 2025 (millions 2012$) 

Source/Emissions Point 

Compliance Costs, 2020 Compliance Costs, 2025 

Capital 

Costs 

(2012$) 

Nationwide 

Annualized 

Costs (2012$) 

Capital 

Costs 

 (2012$) 

Nationwide 

Annualized 

Costs (2012$) 

Oil Well Completions and Recompletions $150 $120 $150 $120 

Fugitive Emissions $15 to $22 $29 to $47 $95 to $140 $180 to $290 

Pneumatic Pumps $5.9 $0.84 $36.0 $5.1 

Compressors $0.54 $0.25 $3.2 $1.5 

Pneumatic Controllers $0.048 $0.0052 $0.29 $0.031 

Reporting and Recordkeeping $0.0 $1.4 $0.0 $4.1 

Total $170 to180 $150 to $170 $280 to $330 $320 to $420 

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. 
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As discussed in the preamble to this action, cost-effectiveness analysis allows comparisons of 

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 the 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 
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annualized cost to the sum of the individual pollutant emission reductions addressed by the 

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 
3-17 

below, if a device is cost effective under either of these two approaches, we find it to be cost 

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. We only 

present the cost-effectiveness for the high impact case for fugitive emissions requirements at 

well sites. The low impact case would show lower dollar per ton estimates. 

Table 3-6 Single Pollutant Approach to Engineering Compliance Cost-Effectiveness 

Estimates in 2020 and 2025 for Proposed NSPS Option 2 (High Impact Case for Well Site 

Fugitive Emissions Requirements) 

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. 

 
3-18 

Table 3-7 Multipollutant Approach to Engineering Compliance Cost-Effectiveness 

Estimates for Proposed NSPS Option 2 in 2020 and 2025 (High Impact Case for Well Site 

Fugitive Emissions Requirements) 

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 2025.20 The requirements between the options vary with respect 

to the fugitive emissions requirements. Option 1 includes requirements for annual fugitive 

emissions surveys at well sites but semiannual frequency at other sites, and Option 3 includes 

requirements for quarterly fugitive emissions surveys, as opposed the semiannual requirement in 

Options 2. 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 sources. 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. 

 

 

20 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. 
3-19 

Table 3-8 Comparison of Regulatory Alternatives 

 

Regulatory Alternative 

Option 1 

Option 2 

(proposed) Option 3 

Impacts in 2020 

Affected Sources 40,000 31,000 to 40,000 40,000 

Emissions Reductions 

Methane Emissions Reduction (short 

tons/year) 170,000 170,000 to 180,000 190,000 

 VOC Emissions Reduction (short tons/year) 120,000 120,000 130,000 

Natural Gas Recovery (Mcf) 7,700,000 7,700,000 to 8,200,000 8,800,000 

Compliance Costs 

 Capital Costs (2012$) $180,000,000 $170,000,000 to $180,000,000 $180,000,000 

 Annualized Costs (2012$) $150,000,000 $150,000,000 to $170,000,000 $210,000,000 

Cost-Effectiveness (Single Pollutant Approach)1 

 Methane (2012$ / short ton) $920 $920 to $980 $1,100 

 VOC (2012$ / short ton) $1,300 $1,300 to $1,400 $1,700 

Cost-Effectiveness (Multipollutant Approach)1 

 Methane (2012$ / short ton) $460 $460 to $490 $570

 VOC (2012$ / short ton) $630 $640 to $690 $840 

 

Impacts in 2025 

Affected Sources 180,000 120,000 to 180,000 180,000

Emissions Reductions 

Methane Emissions Reduction (short 

tons/year) 340,000 340,000 to 400,000 470,000 

 VOC Emissions Reduction (short tons/year) 170,000 170,000 to 180,000 200,000 

Natural Gas Recovery (Mcf) 16,000,000 16,000,000 to 19,000,000 23,000,000 

Compliance Costs 

 Capital Costs (2012$) $330,000,000 $280,000,000 to $330,000,000 $330,000,000 

 Annualized Costs (2012$) $310,000,000 $320,000,000 to $420,000,000 $680,000,000 

Cost-Effectiveness (Single Pollutant Approach)1 

 Methane (2012$ / short ton) $920 $940 to $1,100 $1,400 

 VOC (2012$ / short ton) $1,900 $1,900 to $2,300 $3,400 

Cost-Effectiveness (Multipollutant Approach)1 

 Methane (2012$ / short ton) $460 $470 to $530 $720

 VOC (2012$ / short ton) $940 $960 to $1,200 $1,700 

1 Cost-effectiveness based on high impact case for well site fugitive emissions requirements. 
3-20 

3.4.8 Capital and Annualized Compliance Costs Compared to Industry-level Capital 

Expenditures and Revenues 

In order to provide another perspective on the reasonableness of the estimated cost of 

control as determined in our evaluation of "Best System of Emission Reduction" (BSER) for the 

proposed standards, we analyzed the total cost of the rule for each type of affected facility under 

two additional approaches using industry economic data. 

First, we compared the total nationwide capitals costs that would be incurred for each 

type of affected facility to comply with the proposed standards to the industry’s estimated new 

annual capital expenditures. This analysis allowed us to compare the capital costs that would be 

incurred to comply with the proposed standards to the level of new capital expenditures that the 

industry is incurring in the absence of the proposed standards. Capital expenditure data for 

relevant NAICS codes covered by the rule were obtained from the U.S. Census 2013 Annual 

Capital Expenditures Survey21. For the capital expenditures analysis, we determined the 

estimated nationwide capital costs incurred by each type of affected facility to comply with the 

proposed standards, then divided the nationwide capital costs by the new capital expenditures 

(Census data) for the appropriate NAICS code(s) to determine the percentage that the nationwide 

capital costs represent of the capital expenditures. For example, we used the total estimated 

capital cost (nationwide) for hydraulically fractured development oil well completions and 

compared that to the total capital expenditures the NAICs codes that correspond to oil and 

natural gas production segment. Table 3-9 below summarizes the capital expenditure data used 

for our analysis. 

Table 3-9 NAICS-Based Capital Expenditure Data

Oil and Natural Gas 

Segment NAICS Code NAICS Description 

Total New Expenditures 

(millions, current $) 

Production 

2111 Crude Petroleum and 

Natural Gas Extraction $158,911 

213111, 213112 Support Activities for Oil 

and Gas Operations $19,966 

Transmission and Storage 4862 Pipeline transportation of 

natural gas $12,891 

 

21 Capital Expenditures for Structures and Equipment for Companies With Employees by Industry: 2013, Table 4a. 

See http://www.census.gov/econ/aces/xls/2013/full_report.html 
3-21 

For fugitive emissions standards at well sites and compressor stations, there are no actual 

capital cost identified in the TSD. First year costs, which are corporate-based costs for these 

standards are factored into the annual costs; however, these first year costs are not actual capital 

costs and we therefore, determined that comparison of these costs to industry capital 

expenditures would be inappropriate. 

In the second approach, we compared the annualized costs that would be incurred to 

comply with the standards to the industry’s estimated annual revenues. This analysis allowed us 

determine whether the annualized costs appear reasonable as a percentage of the revenues being 

generated by the industry. The annualized costs, as calculated for the rule, include capital cost 

annualized using a seven percent discount rate plus any annually incurred cost for 

implementation of a control technology. We used annual costs without savings from natural gas 

recovery in order to present the highest costs. The annual revenue data for relevant NAICS codes 

were obtained from the U.S. Census 2012 County Business Patterns and 2012 Economic 

Census22. For the annual revenues analysis, we determined the estimated nationwide annualize 

costs incurred by each type of affected facility to comply with the proposed standards, then 

divided the nationwide annualized costs by the annual revenues (Census data) for the appropriate 

NAICS code(s) to determine the percentage that the nationwide annualized costs represent of 

annual revenues. For example, we used the total annual cost (nationwide) for hydraulically 

fractured development oil well completions and compared that to the total receipts for the NAICs 

codes that correspond to oil and natural gas production segment. Table 3-10 below summarizes 

the revenue data used for our analysis. 

Table 3-10 NAICS-Based Revenue Data 

Oil and Natural Gas 

Segment NAICS Code NAICS Description 

Estimated 

Receipts 

(millions 

2012$) 

Production 

211111 Crude Petroleum and Natural Gas Extraction $276,077 

213112 Support Activities for Oil and Gas Operations $90,646 

Processing 211112 Natural Gas Liquid Extraction $49,236 

Transmission and Storage 486210 Pipeline Transportation of Natural Gas $26,587 

 

22 Number of Firms, Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterprise 

Employment Size for the United States, All Industries: 2012. Release date: 6/22/2015. 2012 County Business 

Patterns and 2012 Economic Census. For information on confidentiality protection, sampling error, and 

nonsampling error, see http://www.census.gov/econ/susb/methodology.html. For definitions of estimated receipts 

and other definitions, see http://www.census.gov/econ/susb/definitions.html. 
3-22 

For the capital expenditures, the production segment was represented with the NAICS 

codes 21111 " Crude Petroleum and Natural Gas Extraction" and 213111 and 213112 " Support 

Activities for Oil and Gas Operations". The transmission and storage segment was represented 

with the NAICS code 4862 "Pipeline transportation of natural gas". For revenue, the production 

segment was represented with the NAICS codes 21111 " Crude Petroleum and Natural Gas 

Extraction" and 213112 " Support Activities for Oil and Gas Operations". The transmission and 

storage segment was represented with the NAICS code 486210 "Pipeline Transportation of 

Natural Gas". Although there is not a one-to-one correspondence between NAICS codes and the 

industry segments we used in the development of the analysis, we believe there is enough 

similarity to draw accurate conclusions. 

Because we are aware that different owners or operators are generally involved in the 

different industry segments, we conducted the analysis at the affected facility level to ensure 

proper characterization of the impact. We also conducted the analysis for all sources in the 

production segment and in the transmission and storage segment. Table 3-11 summarizes the 

result of our analysis. In all cases we found that the impacts of the proposed rule in comparison 

to either capital expenditures or revenues represent a fraction of one percent. 
3-23 

Table 3-11 Comparison of Proposed NSPS Nationwide Cost by Affected Facility Cost to 

Industry-wide Capital Expenditures and Revenues

Oil and Natural Gas Segment/ 

Number 

of 

Sources 

Subject 

to NSPS 

Total 

Nationwide 

Capital Costs 

(millions 

2012$) 

Total 

Nationwide 

Annual Cost 

(millions 

2012$) 

Nationwide 

Capital 

Cost / 

Capital 

Expenditur

es (%) 

Nationwide 

Annual 

Cost / 

Receipts 

Affected Facility (%) 

Production 

Hydraulically Fractured Oil Well Completions and Recompletions 

 - Development Oil Wells 13,804 $144 $144 0.08% 0.03% 

 - Exploratory/Delineation Oil 

Wells 1,166 $4 $4 0.00% 0.00% 

Gas-Driven Pumps 17,760 $36 $5 0.02% 0.00% 

Fugitives - Well Sites 138,568 NA $310 NA 0.09% 

Total Production Segment 171,298 $184 $464 0.10% 0.13% 

Transmission and Storage 

Compressors 

 - Reciprocating 402 $2.80 $0.79 0.02% 0.00% 

 - Centrifugal 6 $0.14 $0.02 0.01% 0.00% 

Pneumatic Controllers 1,260 $0.29 $0.03 0.00% 0.00% 

Fugitives - Compressor Stations 1,680 NA $27 NA 0.10% 

Total Transmission and Storage 

Segment 3,348 $3 $28 0.03% 0.11% 

Source : All cost information is from the "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 

New Source Performance Standards, 40 CFR Part 60, subpart OOOOa" available in the docket. For Hydraulically 

Fractured Oil Well Completions and Recompletions from Table 4-8, for Gas Driven Pumps from Table 7-19, for 

Fugitives - Well sites from Table 5-31, for Compressors, Reciprocating from Table 8-13,for Centrifugal from 

Table8-14, for Pneumatic controllers from- Table 6-9, and for Fugitives - Compressor Stations from Table 5-31. 

 
3-24 

3.5 Compliance Costs Estimated using 3 and 7 Percent Discount Rates 

Table 3-9 shows that the choice of discount rate has very minor effects on the nationwide 

annualized costs of the proposed option. 

Table 3-12 Annualized Costs using 3 and 7 Percent Discount Rates for Proposed NSPS 

Option 2 in 2020 and 2025 (millions 2012$) 

 

Nationwide Annualized 

Costs, 2020 (2012$) 

 

Nationwide Annualized 

Costs, 2025 (2012$) 

7 percent 3 percent 7 percent 3 percent 

Oil Well Completions and Recompletions $120 $120 $120 $120 

Fugitive Emissions $29 to $47 $29 to $46 $180 to 290 $180 to $290 

Pneumatic Pumps $0.84 $0.69 $5.1 $4.2 

Compressors $0.25 $0.23 $1.5 $1.4 

Pneumatic Controllers $0.0052 $0.0040 $0.031 $0.024 

Reporting and Recordkeeping $1.4 $1.4 $4.1 $4.1 

Total $150 to $170 $150 to $170 $320 to $420 $310 to $420 

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. 

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.
3-25 

Table 3-13 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020 

Source/Emissions Point 

Incrementally 

Affected 

Units 

 Nationwide Emissions Reductions Na

Methane 

(short tons) 

VOC 

(short tons) 

HAP 

(short 

tons) 

Methane (metric 

tons CO2 Eq.) Capital Cost

Well Completions 

Hydraulically Fractured Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,0

 Hydraulically Fractured 

Wildcat and Delineation Oil Wells 

870 8,000 6,700 1 180,000 $3,2

Fugitive Emissions 

Well Pads 22,000 17,000 4,800 180 390,000 $18,0

 Gathering and Boosting 

Stations 260 5,500 1,500 57 120,000 $4,2

 Transmission Compressor 

Stations 21 1,700 47 1 39,000 $3

Pneumatic Pumps  Well Pads 3,000 5,400 1,500 57 120,000 $5,9

 Gathering and Boosting 

Stations 0 0 0 0 0 Transmission and Storage Compressor Stations 0 0 0 0 0 

Pneumatic Controllers -  Natural Gas Transmission 

and Storage Stations 67 1,500 40 1 33,000 $4

Reciprocating Compressors  Natural Gas Transmission 

and Storage Stations 1 110 3 0 2,500 $

Centrifugal Compressors  Natural Gas Transmission 

and Storage Stations 210 590 16 0 13,000 $

Reporting and Recordkeeping All 0 0 0 0 TOTAL 40,000 170,000 120,000 310 3,800,000 $180,0
3-26 

Table 3-14 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025 

Source/Emissions Point 

Incrementally 

Affected Units 

 Nationwide Emissions Reductions Na

Methane 

(short tons) 

VOC 

(short tons) 

HAP 

(short 

tons) 

Methane (metric 

tons CO2 Eq.) Capital Cost

Well Completions 

Hydraulically Fractured Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,

 Hydraulically Fractured 

Wildcat and Delineation Oil Wells 

1,200 11,000 9,000 1 240,000 $4,

Fugitive Emissions 

Well Pads 140,000 110,000 32,000 1,200 2,600,000 $110,

 Gathering and Boosting 

Stations 1,600 33,000 9,100 340 740,000 $25,

 Transmission Compressor 

Stations 130 10,000 280 8 230,000 $2,

Pneumatic Pumps  Well Pads 18,000 32,000 9,000 340 740,000 $36,

 Gathering and Boosting 

Stations 0 0 0 0 0 Transmission and Storage Compressor Stations 0 0 0 0 0 

Pneumatic Controllers -  Natural Gas Transmission 

and Storage Stations 400 8,800 240 7 200,000 $2,

Reciprocating Compressors  Natural Gas Transmission 

and Storage Stations 6 670 18 1 15,000 $

Centrifugal Compressors  Natural Gas Transmission 

and Storage Stations 1,300 3,500 97 3 80,000 $

Reporting and Recordkeeping All 0 0 0 0 TOTAL 180,000 340,000 170,000 1,900 7,700,000 $330,0
3-27 

Table 3-15 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact Ca

Source/Emissions Point 

Incrementally 

Affected Units 

 Nationwide Emissions Reductions 

Methane (short 

tons) 

VOC 

(short tons) 

HAP (short 

tons) 

Methane (metric 

tons CO2 Eq.) Capital 

Well Completions 

Hydraulically Fractured Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140

 Hydraulically Fractured 

Wildcat and Delineation Oil Wells 

870 8,000 6,700 1 180,000 $3

Fugitive Emissions 

Well Pads 13,000 17,000 4,600 180 380,000 $11

 Gathering and Boosting 

Stations 260 5,500 1,500 57 120,000 $4

 Transmission Compressor 

Stations 21 1,700 47 1 39,000 

Pneumatic Pumps  Well Pads 3,000 5,400 1,500 57 120,000 $5

 Gathering and Boosting 

Stations 0 0 0 0 0 Transmission and Storage Compressor Stations 0 0 0 0 0 

Pneumatic Controllers -  Natural Gas Transmission 

and Storage Stations 67 1,500 40 1 33,000 

Reciprocating Compressors  Natural Gas Transmission 

and Storage Stations 1 110 3 0 2,500 

Centrifugal Compressors  Natural Gas Transmission 

and Storage Stations 210 590 16 0 13,000 

Reporting and Recordkeeping All 0 0 0 0 TOTAL 31,000 170,000 120,000 310 3,800,000 $170
3-28 

Table 3-16 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact Ca

Source/Emissions Point 

Incrementally 

Affected Units 

Nationwide Emissions Reductions 

Methane 

(short tons) 

VOC 

(short tons) HAP (short tons) 

Methane (metric 

tons CO2 Eq.) Cap

Well Completions 

Hydraulically Fractured Development Oil Wells 14,000 130,000 110,000 13 2,900,000 

 Hydraulically Fractured 

Wildcat and Delineation Oil Wells 

1,200 11,000 9,000 1 240,000 

Fugitive Emissions 

Well Pads 84,000 110,000 31,000 1,200 2,500,000 

 Gathering and Boosting 

Stations 1,600 33,000 9,100 340 740,000 

 Transmission Compressor 

Stations 130 10,000 280 8 230,000 

Pneumatic Pumps  Well Pads 18,000 32,000 9,000 340 740,000 

 Gathering and Boosting 

Stations 0 0 0 0 0 Transmission and Storage Compressor Stations 0 0 0 0 0 

Pneumatic Controllers -  Natural Gas Transmission 

and Storage Stations 400 8,800 240 7 200,000 

Reciprocating Compressors  Natural Gas Transmission 

and Storage Stations 6 670 18 1 15,000 

Centrifugal Compressors  Natural Gas Transmission 

and Storage Stations 1,300 3,500 97 3 80,000 

Reporting and Recordkeeping All 0 0 0 0 

TOTAL 120,000 340,000 170,000 1,900 7,700,000 
3-29 

Table 3-17 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact C

Source/Emissions Point 

Incrementally 

Affected 

Units 

 Nationwide Emissions Reductions Na

Methane 

(short tons) 

VOC 

(short tons) 

HAP 

(short 

tons) 

Methane (metric 

tons CO2 Eq.) Capital Cost

Well Completions 

Hydraulically Fractured Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,0

 Hydraulically Fractured 

Wildcat and Delineation Oil Wells 

870 8,000 6,700 1 180,000 $3,2

Fugitive Emissions 

Well Pads 22,000 26,000 7,200 270 590,000 $18,0

 Gathering and Boosting 

Stations 260 5,500 1,500 57 120,000 $4,2

 Transmission Compressor 

Stations 21 1,700 47 1 39,000 $3

Pneumatic Pumps  Well Pads 3,000 5,400 1,500 57 120,000 $5,9

 Gathering and Boosting 

Stations 0 0 0 0 0 Transmission and Storage Compressor Stations 0 0 0 0 0 

Pneumatic Controllers -  Natural Gas Transmission 

and Storage Stations 67 1,500 40 1 33,000 $4

Reciprocating Compressors  Natural Gas Transmission 

and Storage Stations 1 110 3 0 2,500 $

Centrifugal Compressors  Natural Gas Transmission 

and Storage Stations 210 590 16 0 13,000 $

Reporting and Recordkeeping All 0 0 0 0 

TOTAL 40,000 180,000 120,000 400 4,000,000 $180,0
3-30 

Table 3-18 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact C

Source/Emissions Point 

Incrementally 

Affected Units 

 Nationwide Emissions Reductions Na

Methane 

(short tons) 

VOC 

(short tons) 

HAP 

(short 

tons) 

Methane (metric 

tons CO2 Eq.) Capital Cost

Well Completions 

Hydraulically Fractured Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,0

 Hydraulically Fractured 

Wildcat and Delineation Oil Wells 

1,200 11,000 9,000 1 240,000 $4,3

Fugitive Emissions 

Well Pads 140,000 170,000 48,000 1,800 3,900,000 $110,0

 Gathering and Boosting 

Stations 1,600 33,000 9,100 340 740,000 $25,0

 Transmission Compressor 

Stations 130 10,000 280 8 230,000 $2,

Pneumatic Pumps  Well Pads 18,000 32,000 9,000 340 740,000 $36,0

 Gathering and Boosting 

Stations 0 0 0 0 0 Transmission and Storage Compressor Stations 0 0 0 0 0 

Pneumatic Controllers -  Natural Gas Transmission 

and Storage Stations 400 8,800 240 7 200,000 $2,

Reciprocating Compressors  Natural Gas Transmission 

and Storage Stations 6 670 18 1 15,000 $4

Centrifugal Compressors  Natural Gas Transmission 

and Storage Stations 1,300 3,500 97 3 80,000 $2

Reporting and Recordkeeping All 0 0 0 0 

TOTAL 180,000 400,000 180,000 2,500 9,000,000 $330,0
3-31 

Table 3-19 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020 

Source/Emissions Point 

Incrementally 

Affected 

Units 

 Nationwide Emissions Reductions Na

Methane 

(short tons) 

VOC 

(short tons) 

HAP 

(short 

tons) 

Methane (metric 

tons CO2 Eq.) Capital Cost

Well Completions 

Hydraulically Fractured Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,0

 Hydraulically Fractured 

Wildcat and Delineation Oil Wells 

870 8,000 6,700 1 180,000 $3,2

Fugitive Emissions 

Well Pads 22,000 34,000 9,600 360 780,000 $18,0

 Gathering and Boosting 

Stations 260 7,300 2,000 76 170,000 $4,2

 Transmission Compressor 

Stations 21 2,300 63 2 52,000 $3

Pneumatic Pumps  Well Pads 3,000 5,400 1,500 57 120,000 $5,9

 Gathering and Boosting 

Stations 0 0 0 0 0 Transmission and Storage Compressor Stations 0 0 0 0 0 

Pneumatic Controllers -  Natural Gas Transmission 

and Storage Stations 67 1,500 40 1 33,000 $4

Reciprocating Compressors  Natural Gas Transmission 

and Storage Stations 1 110 3 0 2,500 $

Centrifugal Compressors  Natural Gas Transmission 

and Storage Stations 210 590 16 0 13,000 $

Reporting and Recordkeeping All 0 0 0 0 

TOTAL 40,000 190,000 130,000 510 4,200,000 $180,0
3-32 

Table 3-20 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025 

Source 

Incrementally 

Affected Units 

 Nationwide Emissions Reductions Na

Methane 

(short tons) 

VOC 

(short tons) 

HAP 

(short 

tons) 

Methane (metric 

tons CO2 Eq.) Capital Cos

Well Completions 

Hydraulically Fractured Development Oil Wells 14,000 130,000 110,000 13 2,900,000 $140,

 Hydraulically Fractured 

Wildcat and Delineation Oil Wells 

1,200 11,000 9,000 1 240,000 $4,

Fugitive Emissions 

Well Pads 140,000 230,000 64,000 2,400 5,200,000 $110,

 Gathering and Boosting 

Stations 1,600 44,000 12,000 460 990,000 $25,

 Transmission Compressor 

Stations 130 14,000 380 11 310,000 $2,

Pneumatic Pumps  Well Pads 18,000 32,000 9,000 340 740,000 $36,

 Gathering and Boosting 

Stations 0 0 0 0 0 Transmission and Storage Compressor Stations 0 0 0 0 0 

Pneumatic Controllers -  Natural Gas Transmission 

and Storage Stations 400 8,800 240 7 200,000 $2,

Reciprocating Compressors  Natural Gas Transmission 

and Storage Stations 6 670 18 1 15,000 $

Centrifugal Compressors  Natural Gas Transmission 

and Storage Stations 1,300 3,500 97 3 80,000 $

Reporting and Recordkeeping All 0 0 0 0 

TOTAL 180,000 470,000 200,000 3,200 11,000,000 $330,
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 170,000 to 180,000 tons 

of methane, 120,000 tons of VOC, and 310 to 400 tons of HAP from new sources in 2020. In 

2025, the NSPS would prevent 340,000 to 400,000 tons of methane, 170,000 to 180,000 tons of 

VOC, and 1,900 to 2,500 tons of HAP. The CO2-equivalent (CO2 Eq.) methane emission 

reductions are estimated to be 3.8 to 4.0 million metric tons in 2020 and 7.7 to 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 $200 to 

$210 million and $460 to $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 
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 4-1 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.

(2014), 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. 
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. 
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, the 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. 
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 4-2 Direct Emission Reductions across NSPS Regulatory Options in 2020 and 

2025 

Pollutant Option 1 

Option 2 

 (proposed) Option 3 

 2020 

Methane (short tons/year) 170,000 170,000 to 180,000 190,000 

VOC (short tons/year) 120,000 120,000 130,000 

HAP (short tons/year) 310 310 to 400 510 

Methane (metric tons) 150,000 150,000 to 160,000 170,000 

Methane (metric tons CO2 Eq.) 3,800,000 3,800,000 to 4,000,000 4,200,000 

 2025 

Methane (short tons/year) 340,000 340,000 to 400,000 470,000 

VOC (short tons/year) 170,000 170,000 to 180,000 200,000 

HAP (short tons/year) 1,900 1,900 to 2,500 3,200 

Methane (metric tons) 310,000 310,000 to 360,000 430,000 

Methane (metric tons CO2 Eq.) 7,700,00 7,700,000 to 9,000,000 11,000,000 

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 
4-6 

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/m2

 of 

forcing, which is about 17 percent of all global forcing due to increases in anthropogenic GHG 

concentrations, and which makes methane the second leading long-lived climate forcer after 

CO2. However, after accounting for changes in other greenhouse substances such as ozone and 

stratospheric water vapor due to chemical reactions of methane in the atmosphere, historical 

methane emissions were estimated to have contributed to 0.97 W/m2

 of forcing today, which is 

about 30 percent of the contemporaneous forcing due to historical greenhouse gas emissions. 

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 

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 
4-7 

is expected to reduce methane emissions by about 170,000 to 180,000 short tons or 

approximately 150,000 to 160,000 metric tons methane (or 3.8 to 4.0 MMt CO2 Eq.) in 2020. In 

2025, the proposed NSPS is expected to reduce methane emissions by about 340,000 to 400,000 

short tons or approximately 310,000 to 360,000 metric tons methane (or 7.7 to 9.0 MMt CO2

Eq.). These reductions in 2020 and 2025 represent about 2 percent and 4 to 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 

the 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 

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 

the 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 
4-8 

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 

benefit-cost analysis. The new versions of the models offer some improvements in these areas, 

although further work is warranted. 

Accordingly, the 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 

 

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 
4-9 

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 

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 

 

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. 

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. 
4-10 

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

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. 2014 

Figure 4-1 Path from GHG Emissions to Monetized Damages 

 

30 See also Reilly and Richards, 1993; Schmalensee, 1993; Fankhauser, 1994; Marten and Newbold, 2012. 
4-11 

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 

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 

The 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 the 

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. 

 

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. 
4-12 

The EPA had cited several researchers that had directly estimated the social cost of nonCO2 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. The 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, the 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 

SC-CO2 estimates developed by the IWG, were developed. The EPA presented GWP-weighted 

estimates in sensitivity analyses rather than the main benefit-cost analyses.32

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 

 

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 

33 Marten et al. (2014) also provided the first set of SC-N20 estimates that are consistent with the assumptions 

underlying the SC-CO2 estimates. 
4-13 

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

 

Marten et al. (2014) discuss these estimates, (SC-CH4 estimates presented below in Table 

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 SC-CH4

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 GWP-weighted 

 

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). 

36 Marten et al. (2014) 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. 
4-14 

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 4-3 Social Cost of Methane (SC-CH4), 2012 – 2050a [in 2012$ per metric ton] 

(Source: Marten et al., 2014b)

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. 

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. 

The EPA recently conducted a peer review of the application of the Marten et al. (2014) 

non-CO2 social cost estimates in regulatory analysis and received responses that supported this 
4-15 

application. Three reviewers considered seven charge questions that covered issues such as the 

EPA’s interpretation of the Marten et al. estimates, the consistency of the estimates with the SCCO2 estimates, the 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 the 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. The 

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 with the SC-CO2 estimates that are recommended by OMB’s guidance on valuing CO2

emissions reductions, leads the 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 the EPA to value nonCO2 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. The 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. 
4-16 

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 $88 million 

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

estimate of about $200 to $210 million in 2020. The methane benefits increase for the proposed 

option in 2025 and likewise vary by discount rate, ranging from about $220 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 $460 to $550 million in 2025. 

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

Discount rate and 

statistic 

Option 1 Proposed Option 2 

(Low) 

Proposed Option 2 

(High) Option 3 

2020 2025 2020 2025 2020 2025 2020 2025 

Million metric tonnes 

of methane reduced 0.15 0.31 0.15 0.31 0.16 0.36 0.17 0.43 

Million metric tonnes 

of CO2 Eq. 3.8 7.7 3.8 7.7 4.0 9.0 4.2 11 

5% (average) $89 $220 $88 $220 $93 $250 $99 $300 

3% (average) $200 $470 $200 $460 $210 $550 $220 $640 

2.5% (average) $260 $600 $260 $600 $280 $700 $290 $830 

3% (95th percentile) $530 $1,200 $520 $1,200 $550 $1,400 $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. 

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 
4-17 

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 

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-
4-18 

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. 

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, the 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 the EPA has not quantified 

these effects in previous benefits analyses, the scientific literature suggests that exposure to 
4-19 

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 the 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, the EPA estimates PM-related premature mortality without applying an 

assumed concentration threshold. This decision is supported by the data, which are quite 

consistent in showing effects down to the lowest measured levels of PM2.5 in the underlying 

epidemiology studies. 

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). 

The 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 the EPA provides the benefit estimates derived from expert 

opinions in Roman et al. (2008) as a characterization of uncertainty. As shown in Table 4-5, the 

range of VOC benefits that reflects the range of epidemiology studies and the range of the urban 
4-20 

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 the 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). 
4-21 

Table 4-5 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 

Atlanta $660 $1,600 $1,700 $1,300 $1,300 $920 $2,100 $1,200 $780 $980 $1,300 

Chicago $1,600 $4,000 $4,200 $3,300 $3,200 $2,300 $5,300 $3,000 $1,900 $2,400 $3,200 

Dallas $320 $790 $830 $650 $630 $450 $1,000 $580 $380 $480 $630 

Denver $770 $1,900 $2,000 $1,500 $1,500 $1,100 $2,400 $1,400 $910 $1,100 $1,500 

NYC/ Philadelphia $2,300 $5,600 $5,900 $4,600 $4,500 $3,200 $7,300 $4,100 $2,700 $3,400 $4,500 

Phoenix $1,100 $2,700 $2,800 $2,200 $2,100 $1,500 $3,500 $2,000 $1,300 $1,600 $2,100 

Salt Lake $1,400 $3,300 $3,500 $2,700 $2,700 $1,900 $4,400 $2,500 $1,600 $2,000 $2,700 

San Joaquin $3,100 $7,500 $7,900 $6,100 $6,000 $4,300 $9,700 $5,500 $3,600 $4,500 $6,000 

Seattle $300 $730 $770 $570 $590 $420 $950 $540 $350 $440 $580 

National average $1,300 $3,200 $3,400 $2,600 $2,600 $1,800 $4,200 $2,300 $1,500 $1,900 $2,500 

* These estimates assumed a 50 percent reduction in VOC emissions, an analysis year of 2015, and a 3 percent discount rate. All estima

significant digits. These estimates have been adjusted from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currency year VSL estimate. However, these estimates have not been updated to reflect recent epidemiological studies for mortality studies, morbid

data. Using a discount rate of 7 percent, the benefit-per-ton estimates would be approximately 9 percent lower. Assuming a 75 percen

emissions would increase the benefit-per-ton estimates by approximately 4 percent to 52 percent. Assuming a 25 percent reduction in decrease the benefit-per-ton estimates by 5 percent to 52 percent. The EPA generally presents a range of benefits estimates derived fr

from Roman et al. (2008) as a characterization of uncertainty. 
4-22 

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 
4-23 

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 
4-24 

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, the 

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, the 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. 
4-25 

benefit-per-ton for ozone of $260 to $1,070 per ton of VOC reduced. Since EPA conducted the 

analysis of industrial boilers, the 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 
4-26 

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, the 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, the 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/
4-27 

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 the 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. 
4-28 

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 4-2 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. 
4-29 

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, the EPA has quantified the benefits 

of potential reductions in the incidences of cancer and noncancer risk (e.g., U.S. EPA, 1995). In 

those analyses, 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/m3

 of 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 
4-30 

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, the EPA has continued to develop better methods for analyzing the 

benefits of reductions in HAP. 

As part of the second prospective analysis of the benefits and costs of the Clean Air Act 

(U.S. EPA, 2011a), the EPA conducted a case study analysis of the health effects associated with 

reducing exposure to benzene in Houston from implementation of the Clean Air Act (IEc, 2009). 

While reviewing the draft report, the EPA’s Advisory Council on Clean Air Compliance 

Analysis concluded that “the challenges for assessing progress in health improvement as a result 

of reductions in emissions of hazardous air pollutants (HAP) are daunting...due to a lack of 

exposure-response functions, uncertainties in emissions inventories and background levels, the 

difficulty of extrapolating risk estimates to low doses and the challenges of tracking health 

progress for diseases, such as cancer, that have long latency periods” (U.S. EPA-SAB, 2008). 

In 2009, the 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. The EPA remains committed to 
4-31 

improving methods for estimating HAP benefits by continuing to explore additional concepts of 

benefits, including changes in the distribution of risk. 

Available emissions data show that several different HAP are emitted from oil and 

natural gas operations, either from equipment leaks, processing, compressing, transmission and 

distribution, or storage tanks. Emissions of eight HAP make up a large percentage of the total 

HAP emissions by mass from the oil and 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 The EPA states in its IRIS database that data indicate a causal 

relationship between benzene exposure and acute lymphocytic leukemia and suggest a 

relationship between benzene exposure and chronic non-lymphocytic leukemia and chronic 

lymphocytic leukemia. The International Agency for Research on Carcinogens (IARC) has 

determined that benzene is a human carcinogen and the U.S. Department of Health and Human 

 

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. 
4-32 

Services has characterized benzene as a known human carcinogen.51,52 A number of adverse 

noncancer health effects including blood disorders, such as preleukemia and aplastic anemia, 

have also been associated with long-term exposure to benzene.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.57,58,59,60 The EPA’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 

 

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. 

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>.
4-33 

bioassays of rats and mice exposed for life, and increased incidences of mammary cancer and 

leukemia were reported in a lifetime rat oral bioassay. 

The central nervous system (CNS) is the primary target for toluene toxicity in both 

humans and animals for acute and chronic exposures. CNS dysfunction (which is often 

reversible) and narcosis have been frequently observed in humans acutely exposed to low or 

moderate levels of toluene by inhalation: symptoms include fatigue, sleepiness, headaches, and 

nausea. Central nervous system depression has been reported to occur in chronic abusers exposed 

to high levels of toluene. Symptoms include ataxia, tremors, cerebral atrophy, nystagmus 

(involuntary eye movements), and impaired speech, hearing, and vision. Chronic inhalation 

exposure of humans to toluene also causes irritation of the upper respiratory tract, eye irritation, 

dizziness, headaches, and difficulty with sleep. 

Human studies have also reported developmental effects, such as CNS dysfunction, 

attention deficits, and minor craniofacial and limb anomalies, in the children of women who 

abused toluene during pregnancy. A substantial database examining the effects of toluene in 

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 

 

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.
4-34 

sulfide has not undergone a complete evaluation and determination under the 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 

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 

 

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.

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.
4-35 

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. 

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 The 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 

 

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.
4-36 

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

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 the 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. 

 

 

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>. 

72 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris 
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Table 4-6 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 

The secondary emision impacts for regulatory options are equal across the options. This 

result holds because the only requirements varied across the options is the coverage (low and 

high impact cases of the proposed Option 2) or frequency (Moving from Option 1 to Option 3 

increases the frequency of survey and repair under the fugitive emissions requirement) and 

secondary emissions from the fugitive emissions 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, the 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 
4-38 

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 the 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 

greenhouse gas emissions, reduce exposure to various harmful pollutants, improve visibility 

impairment, and reduce vegetation damage. 

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

 

Option 1 Proposed 

Option 2 (Low) 

Proposed 

Option 2 (High) Option 3 

 Pollutant 2020 2025 2020 2025 2020 2025 2020 2025

Change in 

Direct 

Emissions 

Methane 170,000 340,000 170,000 340,000 180,000 400,000 190,000 470,000 

VOC 120,000 170,000 120,000 170,000 120,000 180,000 130,000 200,000 

HAP 310 1,900 310 1,900 400 2,500 510 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) 

4.2 8.5 4.2 8.5 4.4 9.9 4.7 12 

CO2 Eq. 

(million 

metric tons) 

3.8 7.7 3.8 7.7 4.0 9.0 4.2 11 

Note: Totals may not sum due to independent rounding. 

 

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. 
4-39 

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<http://www.epa.gov/air/sect812/dec09/812CAAA_Benzene_Houston_Final_Report_Jul

y_2009.pdf>. Accessed March 30, 2015. 

Interagency Working Group (IWG) on Social Cost of Carbon (SC-CO2). 2010. Technical 

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<http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-ofCarbon-for-RIA.pdf> Accessed March 31, 2015. 

Interagency Working Group (IWG) on Social Cost of Carbon (SC-CO2). 2013. Technical 

Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 12866. Docket ID EPA-HQ-OAR-2013-0495. Participation by Council 

of Economic Advisers, Council on Environmental Quality, Department of Agriculture, 

Department of Commerce, Department of Energy, Department of Transportation, 

Domestic Policy Council, Environmental Protection Agency, National Economic 

Council, Office of Management and Budget, Office of Science and Technology Policy, 

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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 Office of Management and Budget (OMB) has previously approved the information 

collection activities contained in 40 CFR part 60, subpart OOOO under the PRA and has 

assigned OMB control number 2060-0673 and ICR number 2437.01; a summary can be found at 

77 F.R. 49537. The information collection requirements in today’s proposed rule titled, 

Standards of Performance for Crude Oil and Natural Gas Facilities for Construction, 

Modification, or Reconstruction (40 CFR part 60 subpart OOOOa) have been submitted for 

approval to the OMB under the PRA. The ICR document prepared by the EPA has been assigned 

EPA ICR Number 2523.01. You can find a copy of the ICR in the docket for this rule, and is 

briefly summarized below. 

The information to be collected for the proposed NSPS is based on notification, 

performance tests, recordkeeping and reporting requirements which will be mandatory for all 

operators subject to the final standards. Recordkeeping and reporting requirements are 

specifically authorized by section 114 of the CAA (42 U.S.C. 7414). The information will be 

used by the delegated authority (state agency, or Regional Administrator if there is no delegated 

state agency) to ensure that the standards and other requirements are being achieved. Based on 

review of the recorded information at the site and the reported information, the delegated 

permitting authority can identify facilities that may not be in compliance and decide which 
5-2 

facilities, records, or processes may need inspection. 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. 

Potential respondents under subpart OOOOa are owners or operators of new, modified or 

reconstructed oil and natural gas affected facilities as defined under the rule. None of the 

facilities in the United States are owned or operated by state, local, tribal or the Federal 

government. All facilities are privately owned for-profit businesses. The requirements in this 

action result in industry recording keeping and reporting burden associated with review of the 

requirements for all affected entities, gathering relevant information, performing initial 

performance tests and repeat performance tests if necessary, writing and submitting the 

notifications and reports, developing systems for the purpose of processing and maintaining 

information, and train personnel to be able to respond to the collection of information. 

The estimated average annual burden (averaged over the first 3 years after the effective 

date of the standards) for the recordkeeping and reporting requirements in subpart OOOOa for 

the 2,552 owners and operators that are subject to the rule is 92,658 labor hours, with an annual 

average cost of $3,163,699. The annual public reporting and recordkeeping burden for this 

collection of information is estimated to average 3.9 hours per response. Respondents must 

monitor all specified criteria at each affected facility and maintain these records for 5 years. 

Burden is defined at 5 CFR 1320.3(b). 

5.3 Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any 

rule subject to notice and comment rulemaking requirements under the Administrative Procedure 

Act or any other statute unless the agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small entities include small 

businesses, small organizations, and small governmental jurisdictions. 

For purposes of assessing the impacts of this rule on small entities, a small entity is 

defined as: (1) A small business in the oil or natural gas industry whose parent company has no 

more than 500 employees (or revenues of less than $7 million for firms that transport natural gas 
5-3 

via pipeline); (2) a small governmental jurisdiction that is a government of a city, county, town, 

school district, or special district with a population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is independently owned and operated and 

is not dominant in its field. 

Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory flexibility 

analysis (IRFA) that examines the impact of the proposed rule on small entities along with 

regulatory alternatives that could minimize that impact. The complete IRFA is available for 

review in the docket and is summarized here. 

The IRFA describes the reason why the proposed rule is being considered and describes 

the objectives and legal basis of the proposed rule, as well as discusses related rules affecting the 

oil and natural gas sector. The IRFA describes the EPA’s examination of small entity effects 

prior to proposing a regulatory option and provides information about steps taken to minimize 

significant impacts on small entities while achieving the objectives of the rule. 

The EPA also summarized the potential regulatory cost impacts of the proposed rule and 

alternatives in Section 3 of this RIA. The analysis in the IRFA drew upon the same analysis and 

assumptions as the analyses presented in RIA. The IRFA analysis is presented in its entirely in 

Section 7.3 of the RIA. 

Identifying impacts on specific entities is challenging because of the difficulty of 

predicting potentially affected new or modified sources at the firm level. To identify potentially 

affected entities under the proposed NSPS, the EPA combined information from industry 

databases to identify firms drilling and completing wells in 2012, as well as identified their oil 

and natural gas production levels for that year. 

The EPA based the analysis in the IRFA on impacts estimates for the proposed 

requirements for hydraulically fractured and re-fractured oil well completions and well site 

fugitive emissions While the IRFA does not incorporate potential impacts from other provisions 

of the proposed NSPS, the completions and fugitive emissions provisions represent a large 

majority of the estimated compliance costs of the proposed NSPS in 2020 and 2025. Note 

incorporating impacts from other provisions in this analysis is a limitation and underestimates 

impacts, but the EPA believes that detailed analysis of the two provisions impacts on small 

entities is illustrative of impacts on small entities from the proposed rule in its entirety. 
5-4 

We projected the 2012 base year estimates of incrementally affected facilities to 2020 

and 2025 levels based on the same growth rates used to project future activities as described in 

the TSD and consistent with other analyses in this RIA. This approach assumes that no other 

firms perform potentially affected activities and firms performing oil and natural gas activities in 

2012 will continue to do so in 2020 and 2025. While likely true for many firms, this will not be 

the case for all firms. 

For some firms, we estimated their 2012 sales levels by multiplying 2012 oil and natural 

gas production levels reported in an industry database by assumed oil and natural gas prices at 

the wellhead. For natural gas, we assumed the $4/Mcf for natural gas. For oil prices, we 

estimated revenues using two alternative prices, $70/bbl and $50/bbl. In the results, we call the 

case using $70/bbl the “primary scenario” and the case using the $50/bbl as the “low oil price 

scenario”. 

For projected 2020 and 2025 potentially affected activities, we allocated compliance 

costs across entities based upon the costs estimated in the TSD and used in the RIA. The RIA 

and IRFA also estimates the potential implications of the proposed exclusion for low producing 

sites from the fugitive emission requirements. Fewer sites in the program due to this exclusion 

will likely lead to lower costs and emissions. 

The analysis indicates about 1,200 to 2,100 small entities may be subject to the 

requirements for hydraulically fractured and re-fractured oil well completions and fugitive 

emissions requirements at well sites. The low end of this range reflects an estimate of how many 

entities might be excluded as a result of the low production fugitive emissions exemption. Also, 

the cost-to-sales ratios with ratios greater than 1 percent and 3 percent increase from 2020 to 

2025 as affected sources accumulate under the proposed NSPS. Cost-to-sales ratios exceeding 1 

percent and 3 percent are also reduced from the case without the entities that might be excluded 

from fugitive emissions requirements as a result of the low production exemption. 

The analysis above is subject to a number of caveats and limitations. These are discussed 

in detail in the IRFA, as well as in Section 3 of the RIA.

As required by section 609(b) of the RFA, the EPA also convened a Small Business 

Advocacy Review (SBAR) Panel to obtain advice and recommendations from small entity 

representatives that potentially would be subject to the rule's requirements. The SBAR Panel 
5-5 

evaluated the assembled materials and small-entity comments on issues related to elements of an 

IRFA. A copy of the full SBAR Panel Report is available in the rulemaking docket. 

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 

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 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 
5-6 

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. 

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 
5-7 

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. 

More detailed information on the impacts of climate change to human health and welfare 

is provided in Section V of this preamble. 

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 

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. 

The EPA modeled the high impact case of the proposed NSPS with respect the low 

production exemption from the well site fugitive emissions requirements. As such the NEMS-
5-8 

based estimates of energy system impacts are likely high end estimates. 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 

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 (NTTAA) and 1 C.F.R. part 51 

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 EPA conducted searches 

for the Oil and Natural Gas Sector: Emission Standards for New and Modified Sources through 

the Enhanced National Standards Systems Network (NSSN) Database managed by the American 

National Standards Institute (ANSI). Searches were conducted for EPA Methods 1, 1A, 2, 2A, 
5-9 

2C, 2D, 3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 21, 22, and 25A of 40 C.F.R. part 60 Appendix A. No 

applicable voluntary consensus standards were identified for EPA Methods 1A, 2A, 2D, 21, and 

22. All potential standards were reviewed to determine the practicality of the VCS for this rule. 

In this rule, the EPA is proposing to include in a final EPA rule regulatory text for 40 CFR part 

60, subpart OOOOa that includes incorporation by reference. In accordance with requirements of 

1 CFR 51.5, the EPA is proposing to incorporate by reference 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 

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. 
6-1 

6 COMPARISON OF BENEFITS AND COSTS 

Tables 6-1 though Table 6-3 present the summary of the benefits, costs, and net benefits 

for the NSPS across regulatory options. Table 6-4 provides a summary of the direct and 

secondary emissions changes for each regulatory option. 

Table 6-1 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 $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.

 
6-2 

Table 6-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 

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

 2020 2025 

Total Monetized Benefits1 $200 to $210 million $460 to $550 million 

Total Costs2 $150 to $170 million $320 to $420 million 

Net Benefits3 $35 to $42 million $120 to $150 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 170,000 to 180,000 

tons of VOC reduced 

 Health effects of HAP exposure from 

310 to 400 tons of HAP reduced 

Health effects of ozone exposure from 

170,000 to 180,000 tons of methane 

Health effects of HAP exposure from 

1,900 to 2,500 tons of HAP reduced 

Health effects of ozone exposure from 

340,000 to 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 $88 million to $550 million in 2020 and $220 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 3.8 to 4.0 million metric tons in 2020 and 7.7 to 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.

 
6-3 

Table 6-3 Summary of the Monetized Benefits, Costs, and Net Benefits for 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.

 
6-4 

Table 6-4 Summary of Emissions Changes across Options for the NSPS in 2020 and 

2025 (short tons per year, unless otherwise noted)

 

Option 1 Proposed 

Option 2 (Low) 

Proposed 

Option 2 (High) Option 3 

 Pollutant 2020 2025 2020 2025 2020 2025 2020 2025

Change in 

Direct 

Emissions 

Methane 170,000 340,000 170,000 340,000 180,000 400,000 190,000 470,000 

VOC 120,000 170,000 120,000 170,000 120,000 180,000 130,000 200,000 

HAP 310 1,900 310 1,900 400 2,500 510 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) 

4.2 8.5 4.2 8.5 4.4 9.9 4.7 12 

CO2 Eq. 

(million 

metric tons) 

3.8 7.7 3.8 7.7 4.0 9.0 4.2 11 

Note: Totals may not sum due to independent rounding. 
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. The EPA only modeled the energy system impacts of the high 

impact case of the proposed NSPS with respect the low production exemption from the well site 

fugitive emissions requirements. As such the NEMS-based estimates of energy system impacts 

are likely high end estimates. 

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 

hydraulically-fractured 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 
7-2 

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. 

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. 
7-3 

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 

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 

 

74 Assumptions for the 2014 Annual Energy Outlook can be found at 

<http://www.eia.gov/forecasts/aeo/assumptions/>. 
7-4 

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. 

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. 
7-5 

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 

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. 
7-6 

Table 7-1 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 
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.75 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. 

 

 

75 The EPA only modeled the high impact case of the proposed NSPS with respect the low production exemption 

from the well site fugitive emissions requirements. As such the NEMS-based estimates of energy system impacts 

are likely high end estimates. 
7-8 

Table 7-2 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%

Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption 

from the well site fugitive emissions requirements.

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 7-3 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% 

Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption 

from the well site fugitive emissions requirements.
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 7-4 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% 

Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption 

from the well site fugitive emissions requirements.
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 7-5 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% 

Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption 

from the well site fugitive emissions requirements.

7.3 Initial Regulatory Flexibility Analysis 

The Regulatory Flexibility Act (RFA; 5 U.S.C.§ 601 et seq.), as amended by the Small 

Business Regulatory Enforcement Fairness Act (Public Law No. 104-121), provides that 

whenever an agency is required to publish a general notice of proposed rulemaking, it must 

prepare and make available an initial regulatory flexibility analysis (IRFA), unless it certifies that
7-11 

the proposed rule, if promulgated, will not have a significant economic impact on a substantial 

number of small entities (5 U.S.C. § 605[b]). Small entities include small businesses, small 

organizations, and small governmental jurisdictions. An IRFA describes the economic impact of 

the proposed rule on small entities and any significant alternatives to the proposed rule that 

would accomplish the objectives of the rule while minimizing significant economic impacts on 

small entities. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along 

with regulatory alternatives that could minimize that impact. 

7.3.1 Reasons why Action is Being Considered 

This action 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 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. 

7.3.2 Statement of Objectives and Legal Basis for Proposed Rules 

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, and 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). 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 
7-12 

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 

implementation of several aspects of the current standards. 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 natural gas sector and related 

amendments. Except for the implementation improvements and the setting of standards for 

methane, these amendments do not change the requirements for operations already covered by 

the current standards. 

Section 111 of the CAA requires the EPA Administrator to list categories of stationary 

sources that, in his or her judgment, cause or contribute significantly to air pollution which may 

reasonably be anticipated to endanger public health or welfare. The EPA must then issue 

“standards of performance” for new sources in such source categories. The EPA has the 

authority to define the source categories, determine the pollutants for which standards should be 

developed, and identify within each source category the facilities for which standards of 

performance would be established. 

CAA Section 111(a)(1) defines “a standard of performance” as “a standard for emissions 

of air pollutants which reflects the degree of emission limitation achievable through the 

application of the best system of emission reduction which (taking into account the cost of 

achieving such reduction and any nonair quality health and environmental impact and energy 

requirement) the Administrator determines has been adequately demonstrated.” This definition 

makes clear that the standard of performance must be based on controls that constitute "the best 

system of emission reduction... adequately demonstrated". The standard that the EPA develops, 

based on the BSER, is commonly a numerical emissions limit, expressed as a performance level 

(e.g., a rate-based standard). Generally, the EPA does not prescribe a particular technological 

system that must be used to comply with a standard of performance. Rather, sources generally 

can select any measure or combination of measures that will achieve the emissions level of the 

standard. 

 Standards of performance under section 111 are issued for new, modified and 

reconstructed stationary sources. These standards are referred to as “new source performance 
7-13 

standards.” The EPA has the authority to define the source categories, determine the pollutants 

for which standards should be developed, identify the facilities within each source category to be 

covered and set the emission level of the standards. 

CAA section 111(b)(1)(B) requires the EPA to “at least every 8 years review and, if 

appropriate, revise” performance standards unless the “Administrator determines that such 

review is not appropriate in light of readily available information on the efficacy” of the 

standard. When conducting a review of an existing performance standard, the EPA has discretion 

to revise that standard to add emission limits for pollutants or emission sources not currently 

regulated for that source category. 

7.3.3 Description and Estimate of Affected Small Entities

The industry sectors covered by the final rule were identified during the development of 

the engineering cost analysis. The EPA conducted this regulatory flexibility analysis at the 

ultimate (i.e., highest) level of ownership, evaluating parent entities.76 The EPA identified the 

size of ultimate parent entities by using the Small Business Administration (SBA) size threshold 

guidelines.77 The criteria for size determination vary by the organization/operation category of 

the ultimate parent entity, as follows: 

Table 7-6 SBA Size Standards by NAICS Code 

NAICS 

Codes NAICS Industry Description 

Size Standards 

(in millions of dollars) 

Size Standards 

(in no. of employees) 

211111 Crude Petroleum and Natural Gas Extraction - 500 

211112 Natural Gas Liquid Extraction - 500 

213111 Drilling Oil and Gas Wells - 500 

213112 Support Activities for Oil and Gas Operations $38.5 - 

486110 Pipeline Transportation of Crude Oil - 1,500

486210 Pipeline Transportation of Natural Gas $27.5 - 

Sources: U.S. Census Bureau, Statistics of U.S. Businesses, 2012. http://www.census.gov/econ/susb/. SBA Size 

Standards, 13 CFR 121. 201 

We have projections of future potentially affected activities at an aggregate level, but 

identifying impacts on specific entities is challenging because of the difficulty of predicting 

 

76 See Section 2.6 of this RIA for more information on oil and natural gas industry firm characteristics and a 

breakdown of firms by size at the national level. 

77 U.S. Small Business Administration (SBA). 2014. Small Business Size Standards. Effective as of July 14, 2014. 

See: http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf. 
7-14 

potentially affected new or modified source at the firm level. Because of these limitations, we 

based the analysis in this IRFA on impacts estimates for the proposed requirements for 

hydraulically fractured and re-fractured oil well completions and well site fugitive emissions. We 

are able to do this because the base year activity counts for the impacts estimates (as described in 

the TSD) for this rule were based on detailed information for 2012 in a dataset of U.S. wells. The 

proprietary DrillingInfo dataset contains a variety of information including oil, condensate, and 

natural gas production levels, geographic locations, as well as basin and formation information, 

and information about owners/operators of wells, among other data fields.78 As described in the 

TSD sections on hydraulically fractured and re-fractured oil well completions and fugitive 

emissions, we used the DrillingInfo dataset to identify and estimate all wells that were completed 

in 2012, as well as completions of hydraulically fracture or re-fractured oil wells.79 We used the 

field called “common operator” to identify the owner/operator of all wells in this set of new or 

modified 2012 wells. 

While the IRFA does not incorporate potential impacts from other provisions of the 

proposed NSPS, the completions and fugitive emissions provisions represent about 97 percent 

and 94 percent of the estimated compliance costs of the proposed NSPS in 2020 and 2025, 

respectively (Table 7-7). Note incorporating impacts from other provisions in this analysis is a 

limitation, but the EPA believes that detailed analysis of the two provisions impacts on small 

entities is illustrative of impacts on small entities from the proposed rule in its entirety. 

 

 

78 DrillingInfo is a private company that provides information and analysis to the energy sector. More information is 

available at: http://info.drillinginfo.com. 

79 The TSD for this proposed rule provides information on this dataset of U.S. wells. Additional details on the 

development of this dataset can also be found in the following docketed memo: Memorandum to Mark de 

Figueiredo, EPA, from Casey MacQueen and Jessica Gray, ERG. “DrillingInfo Processing Methodology”. 

August 27, 2014. 
7-15 

Table 7-7 Distribution of Estimated Compliance Costs across Sources 

 Annualized Costs (With Product Recovery, 2012$) 

 2020 2020 (%) 2025 2025 (%) 

Hydraulically-fractured and Re-fractured 

Oil Well Completions and Recompletions $120,000,000 71% $120,000,000 29% 

Fugitive Emissions at Well-sites1 $43,000,000 25% $270,000,000 64% 

Other Sources $5,800,000 3% $30,000,000 7% 

Total Annualized Costs of Proposed NSPS $170,000,000 100% $420,000,000 100% 

1

 Estimates for fugitive emissions requirements based on “high impact” case. 

Note: sums may not total due to independent rounding. 

To identify potentially affected entities under the proposed NSPS, the EPA combined 

ownership information from the DrillingInfo dataset with information drawn from the Hoover’s 

Inc. online platform, which includes information about companies NAICS codes, employee 

counts, and sales information.80 Note that this analysis assumes that the firms performing 

potentially affected activities are also the firms performing activities in the future under the 

proposed NSPS. While likely true for many firms, this will not be the case for all firms. 

The EPA matched owner/operators from the DrillingInfo dataset to companies in a 

database developed from a download of oil and gas companies in Hoover’s online database. The 

EPA matched as many records as possible. In the instances where the DrillingInfo 

owner/operator was not the highest level or company ownership, we recorded the highest level of 

owner as was identifiable in Hoovers. Linking these two datasets yields information on the 

NAICS, employee levels, and revenues of the owner/operators shown in the DrillingInfo dataset 

to have new or modified wells in 2012. 

The EPA then used the NAICS codes associated with the matched owner/operators to 

determine which owner/operators should be considered to be small entities for this analysis, 

based on the SBA size standards above. That said, many DrillingInfo owner/operators had no 

match in Hoovers. Additionally, some Hoovers records lacked the information (employees or 

revenues, depending on the NAICS) needed to make a size determination. We initially classified 

these as an “unknown” size. See Table 7-8 for a summary of results of this matching exercise. 

 

 

80 The Hoover’s Inc. online platform includes company records that can contain NAICS codes, number of 

employees, revenues, and assets. For more information, see: http://www.hoovers.com. 
7-16 

Table 7-8 No. of Completions in 2012 by Preliminary Firm Size 

 Number of Completions, 2012 

Firm Size Performing 

Well Completions No. of Firms 

Hydraulically Fractured 

or Re-fractured Oil Wells All Completions 

Small 1,000 3,300 12,000 

Not Small 67 10,000 21,000 

Unknown 1,100 750 6,000 

Total 2,200 14,000 39,000 

Note: consistent with the cost and emissions analysis, these 2012 completion counts do not include completions in 

states where there are state rules with similar requirements as the proposed rules. Counts slightly lower than totals 

included in impacts analysis base year estimates as some completions have no owner/operator recorded in the 

dataset. Sums may not total due to independent rounding. 

Upon analysis of the firms of unknown size, the EPA observed that, on average, the firms 

of unknown size perform fewer well completions. For this reason, we made the observation that 

the firms of unknown size are more likely to be small than not small. To proceed with the 

analysis, we reclassified these firms as small, resulting in the distribution presented in the first 

two columns of Table 7-9. 

Table 7-9 No. of Completions in 2012 by Firm Size 

 No. of Completions, 2012 

Firm Size Performing 

Well Completions No. of Firms 

Hydraulically Fractured 

or Re-fractured Oil Wells All Completions 

Small 1,100 to 2,200 4,000 7,800 to 18,000 

Not Small 66 to 67 10,000 15,000 to 21,000 

Total 1,200 to 2,200 14,000 23,000 to 39,000 

Note: consistent with the cost and emissions analysis, these 2012 completion counts do not include completions in 

states where there are state rules with similar requirements as the proposed rules. Counts slightly lower than totals 

included in impacts analysis base year estimates as some completions have no owner/operator recorded in the 

dataset. Sums may not total due to independent rounding. 

The proposed NSPS provides an exclusion for low producing sites from the fugitive 

emissions requirements.81 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.82 While the EPA is proposing an exclusion from fugitive emission requirements for low 

production well sites, there is uncertainty in how many well sites this exclusion might affect in 

the future. As a result, the analyses in this IRFA, like the RIA, presents a “low” impact case and 

 

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

fugitive emissions program. 

82 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. 
7-17 

“high” impact case for fugitive emissions requirements at well sites. The low impact case 

excludes an estimate low production sites, based on the first month of production data from wells 

newly completed or modified in 2012.The high impact case includes these well sites. Table 7-9 

presents the number of wells completed in the base year of 2012, where the range of wells under 

the fugitive emissions requirements reflects the range of the low and high impact cases. Note that 

while the number of firms potentially affected goes down substantially, the low production 

exclusion from fugitive emissions requirements does not affect the number of affected oil well 

completions. 

7.3.4 Compliance Cost Impact Estimates 

7.3.4.1 Methodology for Estimating Impacts on Small Entities 

This section describes how we project the 2012 base year estimates of incrementally 

affected facilities to 2020 and 2025 levels, how we estimate costs at the firm level from these 

activity estimates, and how we estimated sales for small entities when available data on sales are 

incomplete. 

New and modified hydraulically fractured oil well completions and well sites in this 

IRFA are based on the same growth rates used to project future activities as described in the TSD 

and consistent with other analyses in this RIA. These growth rates are consistent with the drilling 

activity in the 2014 Annual Energy Outlook. These growth rates are applied to the 2012 base 

year estimates for each firm in the database. Table 7-10 and Table 7-11 present future year 

estimates of incrementally affected new and modified sources, in the low and high impact cases, 

respectively. 

Table 7-10 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, Low 

Impact Fugitive Emissions Case 

 

No. of Incrementally Affected Sources, 

2020 

No. of Incrementally Affected Sources, 

2025 

Firm Size 

Performing 

Well 

Completions 

Hydraulically 

Fractured or Refractured Oil 

Wells 

Gas Well 

Sites 

Oil Wells 

Sites 

Hydraulically 

Fractured or Refractured Oil 

Wells 

Gas Well 

Sites 

Oil Wells 

Sites 

Small 4,100 980 3,400 4,200 6,900 20,000 

Not Small 11,000 2,800 5,900 11,000 20,000 35,000 

Total 15,100 3,780 9,300 15,200 26,900 55,000 

Note: Sums may not total due to independent rounding. Assumes well sites have two wells apiece.
7-18 

Table 7-11 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, High 

Impact Fugitive Emissions Case 

 

No. of Incrementally Affected Sources, 

2020 

No. of Incrementally Affected Sources, 

2025 

Firm Size 

Performing 

Well 

Completions 

Hydraulically 

Fractured or 

Re-fractured 

Oil Wells 

Gas Well 

Sites 

Oil Wells 

Sites 

Hydraulically 

Fractured or 

Re-fractured 

Oil Wells 

Gas Well 

Sites 

Oil Wells 

Sites 

Small 4,100 1,900 7,900 4,200 13,000 48,000 

Not Small 11,000 3,600 8,700 11,000 25,000 52,000 

Total 15,100 5,500 16,600 15,200 38,000 100,000 

Note: Sums may not total due to independent rounding. Assumes well sites have two wells apiece. 

This approach assumes that no other firms perform potentially affected activities and 

firms performing these activities in 2012 will continue to do so in 2020 and 2025. Again, the 

analysis in this IRFA is meant to be illustrative of impacts on small entities. Exact predictions of 

future activities at the firm level is not possible. 

Once the future year activities were estimated we allocated compliance costs across small 

entities based upon the costs estimated in the TSD and consistently with other analyses in this 

RIA. These cost estimates include estimates of revenue from natural gas recovery at the assumed 

value of $4/Mcf in 2012 dollars, again consistent with other analyses in this RIA. For 

hydraulically fractured and re-fractured oil well completions, we assumed each small entity is 

required to perform RECs/completions and completions in the same proportions assumed in the 

TSD and RIA. We also assumed the same proportion would be exploratory or delineation wells 

as the TSD and RIA. Table 7-12 shows the distribution of compliance costs estimates across firm 

size, year, and whether the low production exemption is in place. 

Table 7-12 Distribution of Estimated Compliance Costs1 across Firm Size Classes 

 

Annualized Compliance Costs (2012$) 

Low Impact Case 

Annualized Compliance Costs (2012$) 

High Impact Case 

Firm Size No. of Firms 2020 2025 No. of Firms 2020 2025 

Small 1,100 43,000,000 88,000,000 2,200 54,000,000 160,000,000 

Not Small 66 100,000,000 190,000,000 67 110,000,000 240,000,000 

Total 1,200 150,000,000 280,000,000 2,200 170,000,000 390,000,000 

1

 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-fractured oil 

well completions and well-site fugitive emissions. As described in Section 7.1.3, these provisions account for the 

large majority of the rule’s potential impact in 2020 and 2025. 

Note: sums may not total due to independent rounding. 
7-19 

In order to estimate the cost-to-sales ratio, we again combined information from Hoovers 

and the DrillingInfo databases. The Hoovers database has sales information for some, but not all, 

small entities estimated in this IRFA analysis to have impacts. To supplement the sales 

information, we estimated 2012 sales by multiplying 2012 oil and natural gas production levels 

reported in the DrillingInfo database by assumed oil and natural gas prices at the wellhead. For 

natural gas, we assumed the same $4/Mcf for natural gas.83 For oil prices, we estimated revenues 

using two alternative prices, $70/bbl and $50/bbl. In the results, we call the case using $70/bbl 

the “primary scenario” and the case using the $50/bbl as the “low oil price scenario”.84 In the 

instances where the 2012 production-derived revenues exceeded the Hoovers revenues, we 

replaced the Hoovers estimate with the production-derived estimate as more likely to be an 

accurate estimate of sales for 2012. 

7.3.4.2 Results 

This section presents results of the cost-to-sales ratio analysis for both the primary 

scenario and the low oil price scenario. In addition, we present both scenarios for the low and 

high impact cases with respect to the low production exemption from the well site fugitive 

emissions requirements. 

 

 

83 The U.S. Energy Information Administration’s 2015 Annual Energy Outlook projects 2020 Henry Hub natural gas 

prices to be $4.88/MMBtu in its reference case and $4.30/MMBtu in its “low oil” price case in 2013 dollars. 

Available at: http://www.eia.gov/beta/aeo/#/?id=14-AEO2015. After adjusting to $/Mcf (using the conversion of 

1 MMBtu = 1.208 Mcf) in 2012 dollars (using the GDP-Implicit Price Deflator), these prices are $4.94/Mcf in 

the reference case and $4.35/Mcf in the low oil price case. Rounding down to $4/Mcf would likely underestimated sales. 

84 The 2015 Annual Energy Outlook projects wellhead oil prices to be $75.16/bbl in its reference case and 

$54.10/bbl in its “low oil” price case in 2013 dollars. Available at: http://www.eia.gov/beta/aeo/#/?id=14-

AEO2015. After adjusting to 2012 dollars (using the GDP-Implicit Price Deflator), these prices are $74.00/bbl in 

the reference case and $53.27/bbl in the low oil price case. Rounding down to $4/Mcf would likely underestimated sales. 
7-20 

Table 7-13 Compliance Costs-to-Sales1 Ratios (Fugitive Emissions Requirements Low 

Impact Case) across Firm Size Classes for Primary Scenario and Low Oil Price Scenario2 

 2020 (Primary Scenario) 2020 (Low Oil Price Scenario) 

 No. of Small 

Entities 

% of Small 

Entities 

No. of Small 

Entities 

% of Small 

Entities 

No. of Small Entities 1,200 - 1,200 - 

Greater than 1 percent 66 6% 77 7% 

Greater than 3 percent 22 2% 25 2% 

 

2025 (Primary Scenario) 2025 (Low Oil Price Scenario) 

 No. of Small 

Entities 

% of Small 

Entities 

No. of Small 

Entities 

% of Small 

Entities 

No. of Small Entities 1,200 - 1,200 - 

Greater than 1 percent 130 11% 160 13% 

Greater than 3 percent 44 4% 53 5% 

1

 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-fractured oil 

well completions and well-site fugitive emissions. These provisions account for the large majority of the rule’s 

potential impact in 2020 and 2025. 

2

 In the main case, the wellhead prices are assumed to be $4/Mcf for natural gas and $70/bbl for crude oil. In the low 

oil price case, the wellhead prices are assumed to be $4/Mcf for natural gas and $50/bbl for crude oil. 

Table 7-14 Compliance Costs-to-Sales1 Ratios (Fugitive Emissions Requirements Low 

Impact Case) across Firm Size Classes for Primary Scenario and Low Oil Price Scenario2

 2020 (Primary Scenario) 2020 (Low Oil Price Scenario) 

 No. of Small 

Entities 

% of Small 

Entities 

No. of Small 

Entities 

% of Small 

Entities 

No. of Small Entities 2,100 - 2,100 - 

Greater than 1 percent 270 13% 320 15% 

Greater than 3 percent 120 6% 140 7% 

 

2025 (Primary Scenario) 2025 (Low Oil Price Scenario) 

 No. of Small 

Entities 

% of Small 

Entities 

No. of Small 

Entities 

% of Small 

Entities 

No. of Small Entities 2,100 - 2,100 - 

Greater than 1 percent 710 33% 800 38% 

Greater than 3 percent 370 17% 410 20% 

1

 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-fractured oil 

well completions and well-site fugitive emissions. As described in Section 7.1.3, these provisions account for the 

large majority of the rule’s potential impact in 2020 and 2025. 

2

 In the main case, the wellhead prices are assumed to be$4/Mcf for natural gas and $70/bbl for crude oil. In the low 

oil price case, the wellhead prices are assumed to be$4/Mcf for natural gas and $50/bbl for crude oil. 

Comparing Table 7-13 with Table 7-14, about 900 fewer small entities are estimated to 

be affected by the examined provision in the low impact fugitive emissions requirements case. 
7-21 

Cost-to-sales ratios exceeding 1 percent and 3 percent are also reduced from the high impact to 

low impact case without the exemption in place by approximately two-thirds. The percent 

impacted by greater than 3 percent is about double the percent affected by greater than 1 percent 

for each year of analysis in the primary and in the low oil price scenarios. Meanwhile, impacts 

greater than 1 percent and 3 percent increase in the low oil price scenarios, as would be expected. 

Also as expected the cost-to-sales ratios with ratios greater than 1 percent and 3 percent increase 

from 2020 to 2025 as affected sources accumulate under the proposed NSPS. 

7.3.5 Caveats and Limitations 

The analysis above is subject to a number of caveats and limitations, many of which we 

discussed in the presentation of methods and results. It is useful, however, to present a complete 

list of the caveats and limitation here. 

• Because of data limitations, the analysis presented in the IRFA only examines impacts 

on requirements for hydraulically fractured and re-fractured oil well completions and 

well site fugitive emissions. While impacts from these requirements constitute a large 

proportion of the estimated impacts from the proposed NSPS, the omission of the cost 

requirements of other requirements leads to a relative under-estimation of the impacts 

on small entities. Also, the impacts from other requirements may affect firms that are 

not drilling wells, such as pipeline transmission firms. 

• Not all owner/operators listed in the DrillingInfo database could be identified in the 

Hoovers database. These owner/operators tend to have developed relatively few new 

or modified wells in 2012. As a result, we assumed these were small entities, whereas 

these entities may actually be subsidiaries of larger enterprises. While the impacts 

estimates are not affected in the aggregate by this assumption, the assumption likely 

leads to an over-estimate of the impact on small entities for the provisions examined. 

• The analysis assumes the same population of entities completing wells in 2012 are also 

completing wells in 2020 and 2025, according to growth rates developed for the entire 

sector. In the future, many of these firms will complete fewer or more wells, and other 

firms will complete wells. All of these firms combined may complete new or modified 

wells at higher or lower rates depending on economics and technological factors that 

are largely unpredictable. 

• The approach used to estimate sales for the cost-to-sales might over-estimate or underestimate sales depending upon the accuracy of the information in the underlying 

databases and the market prices ultimately faced in 2020 and 2025.

7.3.6 Projected Reporting, Recordkeeping and Other Compliance Requirements 

The information to be collected for the proposed NSPS is based on notification, 
7-22 

performance tests, recordkeeping and reporting requirements which will be mandatory for all 

operators subject to the final standards. Recordkeeping and reporting requirements are 

specifically authorized by section 114 of the CAA (42 U.S.C. 7414). The information will be 

used by the delegated authority (state agency, or Regional Administrator if there is no delegated 

state agency) to ensure that the standards and other requirements are being achieved. Based on 

review of the recorded information at the site and the reported information, the delegated 

permitting authority can identify facilities that may not be in compliance and decide which 

facilities, records, or processes may need inspection. 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. 

Potential respondents under subpart OOOOa are owners or operators of new, modified or 

reconstructed oil and natural gas affected facilities as defined under the rule. None of the 

facilities in the United States are owned or operated by state, local, tribal or the Federal 

government. All facilities are privately owned for-profit businesses. The requirements in this 

action result in industry recording keeping and reporting burden associated with review of the 

requirements for all affected entities, gathering relevant information, performing initial 

performance tests and repeat performance tests if necessary, writing and submitting the 

notifications and reports, developing systems for the purpose of processing and maintaining 

information, and train personnel to be able to respond to the collection of information. 

The estimated average annual burden (averaged over the first 3 years after the effective 

date of the standards) for the recordkeeping and reporting requirements in subpart OOOOa for 

the 2,552 owners and operators that are subject to the rule is 92,658 labor hours, with an annual 

average cost of $3,163,699. The annual public reporting and recordkeeping burden for this 

collection of information is estimated to average 3.9 hours per response. Respondents must 

monitor all specified criteria at each affected facility and maintain these records for 5 years. 

Burden is defined at 5 CFR 1320.3(b). 

7.3.7 Related Federal Rules 

The New Source Performance Standards (NSPS) issued in 2012 are currently reducing 

VOC emissions from several sources in the oil and natural gas industry In addition to the 2012 
7-23 

NSPS, there are two National Emission Standards for Hazardous Air Pollutants (NESHAP) rules 

that apply to certain equipment and processes in the oil and natural gas sector. These rules, listed 

below, address air toxics, primarily benzene, toluene, ethylbenzene and xylenes (collectively 

referred to as BTEX) and n-hexane. These two rules, which were updated concurrently with the 

2012 NSPS, were promulgated under section 112 of the Clean Air Act and are codified in 40 

CFR Part 63: 

• Subpart HH – Crude Oil and Natural Gas Production (including processing); and 

• Subpart HHH – Natural Gas Transmission and Storage.

Additionally, 40 CFR Part 98 Subpart W is a greenhouse gas reporting requirement that 

applies to petroleum and natural gas systems. Owners or operators of facilities that contain 

petroleum and natural gas systems and emit 25,000 metric tons or more of GHGs per year from 

process operations, stationary combustion, miscellaneous use of carbonates, and other source 

categories are required to report emissions from all source categories located at the facility for 

which emission calculation methods are defined in the rule. Owners or operators are required to 

collect emission data; calculate GHG emissions; and follow the specified procedures for quality 

assurance, missing data, recordkeeping, and reporting. 

7.3.8 Regulatory Flexibility Alternatives 

The Panel agrees that the EPA should explore regulatory alternatives and provide 

flexibility where appropriate. This flexibility can lessen impacts to small entities as well as 

entities not classified as small. 

7.3.8.1 Oil Well Exemptions 

SERs encouraged the EPA to exempt stripper wells, low pressure oil wells, and any well 

that requires artificial lift. SERs recommended that the EPA establish an overall applicability 

threshold based on production, emissions, well depth, well type (horizontal), well pressure, 

formation, or revenue to limit potential impact of future regulations on small entities. 

The SERs offered several threshold alternatives to be applied to the oil well completion 

requirements which would significantly reduce compliance costs and burden to small entities that 

the SERs asserted would not affect gas recovery benefits. Some of these comments are described 
7-24 

below. Advocacy believes the EPA had a greater opportunity to advance the discussion by 

evaluating these alternatives through analysis of the available data. Advocacy further believes 

that there is enough information to conduct analysis of alternatives now. Advocacy notes that 

there are several types of thresholds that could be explored by the EPA, such as average 

production of nearby wells (by oil field, reservoir, or basin), well length or depth, and gas and 

water pressure characteristics. Advocacy encourages the EPA to do so in the future, in advance 

of proposal, to facilitate more informed and productive comments from the public which will 

lead to a better rulemaking. 

The EPA has production and well characteristic data on thousands of oil wells through 

DrillingInfo, which aggregates all well data in the U.S. reported by operators to state agencies. In 

this database, the EPA could develop thresholds to target geographical areas or well 

characteristics with greater gas recovery potential than areas or characteristics where costs 

imposed would achieve little to no benefit. Advocacy believes the EPA should examine the data 

in DrillingInfo and the studies identified in the White paper for potential alternatives that 

minimize small entity costs, while achieving significant methane emission benefits. For example, 

Advocacy performed its own preliminary analysis of the DrillingInfo data, which led us to 

recommend a production threshold (see below). Advocacy believes the EPA also should consider 

the peer review and public comments on the white paper and reassess the size and diversity of 

the oil well completions in a more comprehensive fashion. Advocacy believes the EPA should 

have provided additional analysis since the publication of the white paper. 

The EPA believes that it has reasonably analyzed the available data for this draft 

proposed rule, and sufficiently documented this analysis through the rule, the technical support 

document (TSD), and the SBREFA process. However, the EPA notes information gaps and has 

requested additional data and information through the public comment process. 

Gas to Oil Ratio 

Advocacy is concerned that the EPA estimate of ten tons of methane reduction per event 

for oil well completions may be significantly overestimated, based on its analysis of the 2012 

Drilling Info database and SER comments. The 2012 analysis includes hydraulically fractured oil 
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well completions with GORs between 300 and 100,000, whereas the 2011 analysis was limited 

to GORs up to 12,500. 

The Panel recommends that the EPA continue analyzing current data, and assess the 

alternatives mentioned by SERs. In an effort to contribute to the panel process, Advocacy 

analyzed the EPA data provided. Advocacy found that geographical patterns and well 

characteristics exist in the data to suggest common sense thresholds. While a 300 gas to oil ratio 

(GOR) threshold provides some relief for small entities, it is problematic because GOR is not 

known at time of fracturing when a completion takes place. Advocacy further recommends that 

the EPA develop a scheme based on the well characteristics of nearby wells in the basin or 

reservoir to provide an estimate for the GOR parameter. However, the location of the well, and 

the drill direction are known parameters that could be used. In concert with these other 

considerations, Advocacy recommends the EPA consider a GOR cutoff closer to 900, as one 

SER suggested. 

The EPA believes that a gas-to-oil ratio (GOR) of 300 scf of gas per barrel of oil 

produced is an appropriate threshold for facilities to be subject to the well completion provisions 

of the NSPS. The reason for the proposed threshold GOR of 300 is that separators typically do 

not operate at a GOR less than 300, which is based on industry experience rather than a vetted 

technical specification for separator performance85. Though, in theory, any amount of free gas 

could be separated from the liquid, the reality is that this is not practical given the design and 

operating parameters of separation units operating in the field. The EPA is soliciting comment on 

whether a GOR of 300 is the appropriate applicability threshold. Additionally, the EPA 

understands that GOR is not known at the time of well completion, and is soliciting comment on 

whether the GOR of nearby wells would be a reliable indicator in determining the GOR of a new 

or modified well. 

Low Production Wells

When mapping average daily associated gas of 90 Mcf or above (isolating stripper wells) 

using county level data, Advocacy found that most (85%) of these greater gas recovery oil well 

 

85 On February 24, 2015, API submitted a comment to the EPA stating that oil wells with GOR values less than 300 

do not have sufficient gas to operate a separator. 
7-26 

completions occur in about a third of the counties analyzed. Advocacy contends that there are 

potentially large areas that could be exempted from this requirement without forgoing significant 

methane emission reduction, or at least phased in to allow time to design proper data collection. 

For example, PIOGA comments report an average gas volume of only 74 MCFD in 

Pennsylvania stripper oil wells in contrast to Pennsylvania stripper gas wells averaging 532 

MCFD. 

The EPA understands that low production wells have inherently low emissions from well 

completions and many are owned and operated by small businesses. However, the EPA 

recognizes that identification of these wells prior to completion events is difficult, especially 

considering that drilling of a low production well may be unintentional and may be infrequent, 

but production may nevertheless proceed due to economic reasons. The EPA is soliciting 

comment and information on emissions associated with low production wells, characteristics of 

these wells and supporting information that would help owners/operators and enforcement 

personnel identify these wells prior to completion. 

Because of these preliminary findings about low production and a lack of evidence that 

there will be sufficient gas recovery, the Panel recommends that the EPA further analyze and 

consider exempting low production wells (with an average daily production of less than 15 barrel 

equivalents) from a REC or combustion requirement during oil well completions. 

Vertical Wells

According to a SER comment, vertical wells lack sufficient wellhead pressure or quantity 

of gas to be separated during completion. Advocacy recommends that since the white papers laid 

the foundation to the materials prepared for the Panel, the EPA should revisit the information 

learned through this process, especially as it relates to the specific characteristics of vertical 

wells. Therefore, as a regulatory alternative, Advocacy recommends the EPA consider 

exempting vertical wells from oil well completion requirements. 

The EPA clarifies that both the 2014 white paper analysis of oil well completions and 

DrillingInfo data analysis include vertical wells that are hydraulically fractured. However, the 

EPA understands that there are certain physical well characteristics that may inhibit the operation 

of a separator, and notes that the rule does not require RECs where their use is not feasible. 
7-27 

However, the EPA has not seen sufficient data to support the characterization that a separator 

will not be able to function for all or the majority of vertical wells that are hydraulically 

fractured. However, the EPA recommends soliciting comment on the types of oil wells that will 

not be capable of performing a REC or combusting completion emissions due to technical 

considerations such as low pressure or low gas content, or other physical characteristics such as 

location, well depth, length of hydraulic fracturing, or drilling direction (e.g., horizontal, vertical, 

directional). 

Low Pressure Oil Wells 

Advocacy recommends that “low pressure wells” should be categorically exempt and 

could be based on a threshold sales line/gathering line of approximately 250 psi or a simple 

water gradient formula of 0.465 psi/foot. The emissions associated with these types of wells are 

so low that even if a separator can be operated for some short period of time, the value of gas 

does not exceed the cost associated with bringing equipment to the site. As the SERs indicated, 

these oil completion requirements can be very costly on small firms, particularly with respect to 

small production wells. The expected gas recovery benefits from oil well completions are 

expected to be a small fraction of the benefits obtained by the gas wells under the current version 

of the NSPS rule. 

The EPA is aware that oil wells cannot perform a REC if there is not sufficient well 

pressure or gas content during the well completion to operate the surface equipment required for 

a REC. In the 2012 NSPS the EPA did not require low pressure gas wells to perform REC, but 

operators were required to control those well completions using combustion. However, the EPA 

recommends soliciting comment on the types of oil wells that will not be capable of performing a 

REC or combusting completion emissions due to technical considerations such as low pressure 

or low gas content, or other physical characteristics such as location, well depth, length of 

hydraulic fracturing, or drilling direction (e.g., horizontal, vertical, directional). The EPA defines

low pressure wells as a well with reservoir pressure and true vertical well depth such that 0.445 

times the reservoir pressure (in psia) minus 0.038 times the vertical well depth (in feet) minus 

67.578 psia is less than the flow line pressure at the sales meter. The EPA recommends soliciting 

comment on whether this definition is appropriate for low pressure oil wells. 
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Substitution of Combustion over Green Completion / REC Requirements

Advocacy recommends that the EPA substitute flaring for the green completion 

requirement (REC), in addition to the consideration of thresholds. This alternative is much more 

cost-effective, and particularly important for small firms to have a lower cost alternative that 

achieves a 95% reduction. The PIOGA comments also stated that the use of RECs would 

adversely impact the productivity and longevity of the stripper oil wells. Alternatively, the EPA 

could require larger firms to perform the RECs, while allowing smaller firms (using a firm 

revenue cutoff or other small business size indicator) to combust the remaining gas. 

The EPA recommends that RECs be implemented on oil wells, except where their use is 

not feasible (e.g., technically infeasible for a separator to function, availability of gathering 

lines). Compared to combustion alone, the EPA believes that the combination of REC and 

combustion will maximize the recovery of natural resources and minimize venting to the 

atmosphere. However, the EPA notes that although the flaring in lieu of RECs may be less 

costly, flaring contributes secondary environmental impacts, nuisance impacts to nearby 

communities and complicates compliance for owners/operators. 

Phase – In for Oil Well Completion Requirements 

The Panel recommends that the EPA consider phasing in the well completion 

requirement over a period of years. The Panel agrees that the EPA solicit comment on whether 

the well completion provisions of the proposed rule can be implemented on the effective date of 

the rule in the event of potential shortage of REC equipment and, if not, how a phase in could be 

structured. The Panel agrees that a phased in approach could be structured to provide for control 

of the potentially highest emitting wells first, with other wells being included at a later date. The 

Panel recommends that the EPA solicit comment on whether GOR of the well and production 

level of the well should be bases for the phasing of requirements for RECs, and if so, what an 

appropriate threshold for phase-in should be. 

7.3.8.2 Fugitives - Leak Detection Methods 

SERs encouraged the EPA to allow a variety of leak detection technologies, including 

Method 21, AVO, and soap testing. The EPA asserts that use of OGI can reduce the amount of 
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time necessary to conduct fugitive emissions monitoring since multiple fugitive emissions 

components can be surveyed simultaneously, reducing the cost of identifying fugitive emissions 

compared to alternative leak detection technologies that require a manual screening of each 

fugitive emissions component. Advocacy recommends the EPA propose Method 21 or OGI as 

allowable alternatives. The EPA contends that while Method 21 is lacking because it does not 

allow the detection of malfunctioning equipment that may not be the focus of the survey, and it is 

not as cost-effective as OGI, the Panel recommends the EPA solicits comment on whether to 

allow EPA Method 21 as an alternative to OGI for monitoring, including the appropriate EPA 

Method 21 level repair threshold. The EPA notes that the proposed rule would allow the use 

either OGI or Method 21 for resurvey because the resurvey would focus solely on ensuring 

repairs resolved the leak at the individual component. 

7.3.8.3 Fugitives – Survey Frequency 

SERs recommended leak surveys be conducted no more than once per year. Advocacy 

has questions about the costs of repair and the emission reductions that be achieved through 

increased survey frequency which Advocacy believes the EPA was unable to address 

satisfactorily. Advocacy urges the EPA to improve the record basis for its emission reduction 

estimates and the cost of repairs for Method 21 and OGI, in order to permit more informed 

comment on the alternatives. Advocacy believes the EPA was unable to adequately explain the 

basis for the different repair costs vs. frequency for Method 21 and OGI86, or the basis for the 

40/60/80% emission reductions based on increasing survey frequency from annual to quarterly.87

 

The EPA determined that semiannual monitoring will result in identification and repair of 

significant fugitive emissions from components, and that using OGI, an operator can survey 

multiple fugitive emissions components simultaneously reducing the cost of identifying fugitive 

emissions. Additionally, if fugitive emissions are detected at less than one percent of the fugitive 

 

6At this time, the EPA shows annual repair costs that increase linearly with survey frequency for OGI, but are static 

for Method 21. For Method 21, the EPA applied the same repair costs whether the frequency was annual, 

semiannual or quarterly. For OGI, EPA used double the repair costs for semiannual, and four times the repair 

costs for quarterly. Advocacy believes this could lead to a bias in an evaluation of one method vs. the other. 

87 Advocacy was also disappointed that EPA was unable to share with the SERs more information that would have 

help the SERs formulate their recommendations (including some of the issues addressed above). The EPA 

believes the background documents created for the SERs were thorough and accurate, and transparently 

presented the data and data sources used in the analysis for the proposed rule. The documents are additionally 

available for public review in the docket for the proposed rule. 
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emission components at a well site during two consecutive semiannual monitoring surveys, the 

proposed rule allows for the monitoring survey frequency for that well site to be reduced to 

annually. Advocacy had no information upon which to base a recommendation related to the 

proportion of leaking components, but supports analysis of such an approach. Advocacy also 

recommends that the EPA provide more analysis and factual foundation for the record to allow 

commenters to provide more informed advice. 

The Panel agrees that the EPA should solicit comment on an alternate proposal option 

based on an initial annual survey frequency. The Panel recommends the EPA solicit comment on 

the appropriateness of semiannual monitoring frequency and the proposed provisions for 

increasing and decreasing the monitoring frequency. 

7.3.8.4 Fugitive Emissions at Well Sites 

The Panel recommends not requiring fugitive emission surveys at well production sites, 

unless there are potentially significant sources of emissions, such as storage tanks. The Panel 

further agrees that well sites with low production wells (i.e., a well with an average daily 

production of 15 barrel equivalents or less) should not require fugitive emission surveys. 

7.3.8.5 Fugitive Emissions at Production and Processing Sites, and Compressor Stations at 

Transmission and Storage Sites 

Under Subpart W, gas production and processing sites and compressor stations at 

transmission and storage sites are required to annually monitor for fugitive emissions and to 

quantify such emissions. The only missing regulatory component to be considered is to add a 

requirement to repair detected leaks as appropriate. This is already covered by the May 2015 

INGAA Directed Inspection and Maintenance voluntary Program for Transmission and Storage 

Compressor Stations. The EPA is already considering this program88 in its recent request for 

comment on the voluntary methane reduction program for the oil and gas sector. Advocacy 

recommends that the EPA retain the annual requirement, as Advocacy believes this requirement 

is entirely duplicative of a fugitives survey requirement, and consider the specific repair 

 

88 US EPA. Natural Gas STAR Methane Challenge Program: Proposed Framework, slide 17 states, “EPA has 

received, and is considering, a proposal to structure BMP coverage of natural gas transmission and storage 

compressor stations as a Directed Inspection and Maintenance Program.”
7-31 

requirements for repair identification and repair delay in the DI&M voluntary program as the 

components of a mandatory program. Furthermore, the EPA’s most recent evaluation of the 

survey cost-effectiveness shows that annual surveys are more cost-effective than semi-annual 

surveys. Therefore, the Panel recommends the EPA propose options based on semi-annual and 

annual monitoring. Advocacy recommends that the EPA should also consider allowing each 

facility to tailor the specific program to site-specific considerations, rather than apply the same 

requirements uniformly to each plant. The EPA recognizes that Subpart W serves as an 

emissions inventory, while this rule’s intent is to minimize pollution. The EPA believes that the 

additional survey with semiannual OGI monitoring provides additional leak detection, and costeffective emission reductions. The EPA recognizes that fugitive emissions may be 

underestimated based on emerging studies and will continue to evaluate these studies. The Panel 

recommends the EPA propose an alternate option based on an initial annual frequency for well 

sites. The Panel recommends that the EPA continue to consider the INGAA DI&M 

recommendations for leak repairs in the rulemaking. 

7.3.8.6 Well Site Compressors 

SERs encouraged the EPA to exempt well site compressors as they are typically rental 

units and have irregular service time, and regulation could be cost prohibitive. The Panel agrees 

that emissions from well site compressors were extremely low and that cost of control of these 

compressors would not be reasonable. The Panel recommends that the EPA maintain the 

exemption for well site compressors. 

7.3.8.7 Pneumatic Pumps 

SERs encouraged the EPA to exempt pneumatic pumps if controls were not already in 

place. The Panel agrees that combustion controls should only be required if a control is required 

for another source. The Panel recommends the EPA exempt pneumatic pumps without a control 

device already located on site. 

7.3.8.8 Reciprocating Compressors 

The Panel supports the EPA proposal to require replacement of rod packing every 26,000 

hours or 3 years in lieu of monitoring hours. The Panel also supports the further consideration of 

the alternative developed in the Natural Gas Star Program for condition-based maintenance. 
7-32 

Advocacy recommends the EPA should carefully study the INGAA recommendations for 

condition-based maintenance for rod packing as an alternative to maintaining or replacing rod 

packing on a prescribed schedule.89 

The EPA recommends that the draft proposed rule retain the rod packing replacement 

options and the option to route the rod packing emissions to a process through a closed vent 

system under negative pressure. 

7.3.8.9 Centrifugal Compressors 

Advocacy recommends that the EPA reconsider the requirement of requiring capture and 

combustion of gas emissions from wet seal compressors whose emissions don’t differ that much 

from dry seal compressors, according to INGAA. Advocacy is concerned that requiring 

combustion at compressor stations would prove to be unpopular with the surrounding 

neighborhood. This requirement would convert an otherwise unobtrusive structure in the 

neighborhood into a constant source of combustion and a source of air pollution. 

The EPA recommends retaining the requirement for a 95% emissions reduction from wet 

seal compressors, which can be achieved by capturing and routing the emissions utilizing a cover 

and closed vent system to a control device, or routing the captured emissions to a process. The 

EPA notes that dry seal compressors are not affected facilities in the draft proposed rule because 

of their inherently low emissions. The EPA also notes that many of these combustors are 

enclosed and will be innocuous to the surrounding neighborhood. In addition, the gas liberated 

from the barrier fluid during degassing is very clean natural gas, and the combustor is required 

under the NSPS to burn cleanly with no visible emissions. 

7.3.8.10 Pneumatic Controllers 

The Panel agrees with the EPA’s recommendation that low-bleed pneumatic controllers 

be required in place of high-bleed controllers (i.e., natural gas bleed rate not to exceed 6 scfh). 

The Panel recommends the rule continue to treat low-bleed pneumatic controllers as not affected 

facilities except at natural gas processing plants, where zero bleed pneumatic controllers are 

considered BSER. 

 

89 See INGAA comment on 40 CFR 60 Part OOOO. EPA-HQ-OAR-2010-0505-4104 
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7.3.8.11 Recordkeeping and Reporting for High Bleed Controllers 

The EPA recommends that owners and operators continue to be permitted to use high 

bleed controllers needed for specific functional purposes, but require recordkeeping to document 

the justification. The Panel agrees that recordkeeping and reporting requirements should be 

minimized wherever possible. However, the Panel notes that a recordkeeping and reporting 

requirement that asks companies to justify and document their need for continuous high bleed 

devices has caused many companies to reevaluate their need for and change out unnecessary 

high bleed pneumatic controllers. 

7.3.8.12 Liquids Unloading 

Based on the information and data available to the EPA during development of the 2012 

NSPS, the Panel agrees that control of liquids unloading emissions is not appropriate at this time. 

However, the EPA believes that the emissions from liquids unloading operations are significant, 

and so the Panel recommends that the EPA continue to study this issue and solicit information 

and data supporting demonstrated control technologies or management practices for reducing 

these emissions. 

7.4 Employment Impact Analysis 

In addition to addressing the costs and benefits of the proposed rule, the EPA has 

analyzed the impacts of this rulemaking on employment, which are presented in this section.90

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.”

91 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 

 

90 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). 

91 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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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. The EPA continues to explore the relevant theoretical and empirical 

literature and to seek public comments in order to ensure that the way the EPA characterizes the 

employment effects of its regulations is 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. 

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 
7-35 

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 

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) 
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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.92 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).93

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 

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 the 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 

 

92 Berman and Bui include over 40 4-digit SIC industries in their sample. 

93 Including the employment effect of exiting plants and plants dissuaded from opening will increase the estimated 

impact of regulation on employment. 
7-37 

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.94 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 

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, the 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, the EPA has formed a panel of experts as part of the EPA’s Science 

Advisory Board (SAB) to advise the 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.95 Once the EPA receives guidance from this panel it will carefully 

 

94 More detail on how emission reductions expected from compliance with this rule can be obtained can be found in 

Section 3 of this RIA. 

95 For further information see: 

http://yosemite.epa.gov/sab/sabproduct.nsf/0/07E67CF77B54734285257BB0004F87ED?OpenDocument 
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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 2-17 shows employment in six oil and natural gas-related NAICS codes from 1990 

to 2013.96 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 2-18 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 

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 

 

96 NAICS 211111, 21112, 213111, 213112, 486110, and 486210. 
7-39 

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 the EPA does not 

currently have this information. The labor requirements analysis uses a bottom-up engineeringbased 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. 

The results of this employment analysis of the proposed NSPS are presented in Tables 7-

16 through Table 7-19 for 2020 and 2025 for individual sources regulated under this proposal. 

Table 7-20 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 the 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. 
7-40 

Table 7-15 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 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). 

 
7-41 

Table 7-15 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 7-16 and Table 7-17 present estimates of labor requirements for the low and the 

high impacts cases for fugitive emissions. 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. Company-level 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. 

 
7-42 

Table 7-16 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive 

Emissions, Low Impact Case, 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 

605 118.0 0.0 71,352 0 34 0 

Site-level Activities 13,303 0.0 14.1 0 187,717 0 90 

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 13,583 N/A N/A 104,392 219,702 50 106 

 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.
7-43 

Table 7-17 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive 

Emissions, High Impact Case, 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.
7-44 

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 7-18 presents labor requirement estimates for reciprocating and centrifugal 

compressors. Like the estimates for completions, the per unit labor estimates were based on 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 7-18 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 7-19 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 
7-45 

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 7-19 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 7-20 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. 

 
7-46 

Table 7-20 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 15,000 0 720,000 0 350 

Fugitive Emissions 14,000 to 

22,000 

100,000 to 

150,000 

220,000 to 

340,000 50 to 73 110 to 170 

Pneumatic Controllers 210 0 0 0 0 

Pneumatic Pumps 3,000 N/A N/A N/A N/A 

Reciprocating Compressors 67 67 67 0 0 

Centrifugal Compressors 1 360 0 0 0 

Reporting and Recordkeeping 

Requirements All 0 40,000 0 19 

Total 31,000 to 

40,000 

100,000 to 

150,000 

980,000 to 

1,100,000 50 to 73 470 to 530 

 

 2025 

Hydraulically Fractured and Refractured Oil Well Completions 15,000 0 720,000 0 350 

Fugitive Emissions 86,000 to 

140,000 

100,000 to 

150,000 

1,400,000 to 

2,200,000 50 to 73 660 to 1,000 

Pneumatic Controllers 1,300 0 0 0 0 

Pneumatic Pumps 18,000 N/A N/A N/A N/A 

Reciprocating Compressors 400 67 400 0 0 

Centrifugal Compressors 6 360 0 0 0 

Reporting and Recordkeeping 

Requirements All 0 120,000 0 58 

Total 120,000 to 

180,000 

100,000 to 

150,000 

2,200,000 to 

3,000,000 50 to 73 1,100 to 1,400 

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). Rounded to two 

significant digits. Totals may not sum due to independent rounding. 

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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. 
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Gray, W.B., R.J. Shadbegian, C. Wang, and M. Meral. 2014. “Do EPA Regulations Affect Labor 

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United States 

Environmental 

Protection Agency 

Office of Air Quality Planning and 

Standards 

Health and Environmental Impacts Division 

Research Triangle Park, NC 

Publication No. 

EPA-452/R-15-002 

August 2015