***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review ***

E.O. 12866 NESHAP & NSPS for Oil and Gas 2060-AP76 RIA Final Rule 20120301

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

U.S. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, NC 27711

April 2012
ii

CONTACT INFORMATION

This document has been prepared by staff from the Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency. Questions related to this document should be 

addressed to Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air 

Quality Planning and Standards, C445-B, Research Triangle Park, North Carolina 27711 (email: 

macpherson.alex@epa.gov).

ACKNOWLEDGEMENTS

In addition to EPA staff from the Office of Air Quality Planning and Standards, 

personnel from the U.S. EPA Office of Atmospheric Programs, EC/R Incorporated, and ICF 

International contributed data and analysis to this document. Specific sections where EC/R 

Incorporated made contributions include the sections describing emissions options, pollution 

control options, secondary impacts analysis, engineering cost analysis, and employment impacts. 

Specific sections where ICF International made contributions also include the sections describing 

emissions options, pollution control options, engineering cost analysis, employment impacts, and 

small business impacts.
iii

TABLE OF CONTENTS

TABLE OF CONTENTS ....................................................................................................................III

LIST OF TABLES.............................................................................................................................VI

LIST OF FIGURES ........................................................................................................................ VIII

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

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

1.2 SUMMARY OF RESULTS................................................................................................................................ 1-2

1.2.1 NSPS Results..................................................................................................................................... 1-2

1.2.2 NESHAP Amendments Results......................................................................................................... 1-5

1.2.3 Results for Combined Small Entity Analysis for the NSPS and NESHAP Amendments................. 1-7

1.3 SUMMARY OF NSPS IMPACTS CHANGES FROM THE PROPOSAL RIA............................................................ 1-7

1.4 SUMMARY OF NESHAP AMENDMENTS IMPACTS CHANGES FROM THE PROPOSAL RIA.............................. 1-8

1.5 ORGANIZATION OF THIS REPORT.................................................................................................................. 1-8

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........................................................................................................................................ 2-2

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

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

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

2.5 INDUSTRY COSTS ....................................................................................................................................... 2-31

2.5.1 Finding Costs................................................................................................................................... 2-31

2.5.2 Lifting Costs .................................................................................................................................... 2-33

2.5.3 Operating and Equipment Costs ...................................................................................................... 2-34

2.6 FIRM CHARACTERISTICS ............................................................................................................................ 2-36

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

2.6.2 Size Distribution of Firms in Affected............................................................................................. 2-37

2.6.3 Trends in National Employment and Wages ................................................................................... 2-39

2.6.4 Horizontal and Vertical Integration ................................................................................................. 2-44

2.6.5 Firm-level Information .................................................................................................................... 2-45

2.6.6 Financial Performance and Condition.............................................................................................. 2-49

2.7 REFERENCES .............................................................................................................................................. 2-53

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

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

3.2 EMISSIONS POINTS, CONTROLS, AND ENGINEERING COSTS ANALYSIS ........................................................ 3-1
iv

3.2.1 Emission Points and Pollution Controls assessed in the RIA ............................................................ 3-2

3.2.1.1 NSPS Emission Points and Pollution Controls ........................................................................ 3-2

3.2.1.2 NESHAP Emission Points and Pollution Controls................................................................... 3-6

3.2.2 Engineering Cost Analysis................................................................................................................. 3-7

3.2.2.1 NSPS Sources........................................................................................................................... 3-8

3.2.2.2 NESHAP Sources................................................................................................................... 3-25

3.3 REFERENCES .............................................................................................................................................. 3-26

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

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

4.2 DIRECT EMISSION REDUCTIONS FROM THE OIL AND NATURAL GAS RULES ................................................ 4-2

4.3 SECONDARY IMPACTS ANALYSIS FOR OIL AND GAS RULES......................................................................... 4-4

4.4 HAZARDOUS AIR POLLUTANT (HAP) BENEFITS .......................................................................................... 4-8

4.4.1 Benzene ........................................................................................................................................... 4-13

4.4.2 Toluene ............................................................................................................................................ 4-15

4.4.3 Carbonyl sulfide............................................................................................................................... 4-15

4.4.4 Ethylbenzene.................................................................................................................................... 4-16

4.4.5 Mixed xylenes.................................................................................................................................. 4-17

4.4.6 n-Hexane.......................................................................................................................................... 4-17

4.4.7 Other Air Toxics.............................................................................................................................. 4-18

4.5 VOC .......................................................................................................................................................... 4-18

4.5.1 VOC as a PM2.5 precursor................................................................................................................ 4-18

4.5.2 PM2.5 health effects and valuation.................................................................................................... 4-19

4.5.3 Organic PM welfare effects............................................................................................................. 4-23

4.5.4 Visibility Effects.............................................................................................................................. 4-24

4.6 VOC AS AN OZONE PRECURSOR ................................................................................................................ 4-24

4.6.1 Ozone health effects and valuation .................................................................................................. 4-25

4.6.2 Ozone vegetation effects.................................................................................................................. 4-26

4.6.3 Ozone climate effects....................................................................................................................... 4-26

4.7 METHANE (CH4) ........................................................................................................................................ 4-27

4.7.1 Methane climate effects and valuation............................................................................................. 4-27

4.7.2 Methane as an ozone precursor........................................................................................................ 4-34

4.7.3 Combined methane and ozone effects ............................................................................................. 4-34

4.8 REFERENCES .............................................................................................................................................. 4-35

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 ..................................................................................................................... 5-3

5.3 REGULATORY FLEXIBILITY ACT .................................................................................................................. 5-3

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... 5-6

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.................................................................. 5-8

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

POPULATIONS AND LOW-INCOME POPULATIONS................................................................................................... 5-8

5.11 CONGRESSIONAL REVIEW ACT.............................................................................................................. 5-10

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

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

7.2 ENERGY SYSTEM IMPACTS ANALYSIS OF FINAL NSPS................................................................................ 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..................................................................................... 7-5

7.2.2.1 Compliance Costs for Oil and Gas Exploration and Production .............................................. 7-6

7.2.2.2 Adding Averted Methane Emissions into Natural Gas Production .......................................... 7-9

7.2.2.3 Fixing Canadian Drilling Costs to Baseline Path ................................................................... 7-10

7.2.3 Energy System Impacts ................................................................................................................... 7-11

7.2.3.1 Impacts on Drilling Activities................................................................................................ 7-11

7.2.3.2 Impacts on Production, Prices, and Consumption.................................................................. 7-12

7.2.3.3 Impacts on Imports and National Fuel Mix............................................................................ 7-16

7.3 EMPLOYMENT IMPACT ANALYSIS .............................................................................................................. 7-19

7.3.1 Employment Impacts from Pollution Control Requirements........................................................... 7-20

7.3.2 Employment Impacts Primarily on the Regulated Industry............................................................. 7-23

7.4 SMALL BUSINESS IMPACTS ANALYSIS ....................................................................................................... 7-27

7.4.1 Small Business National Overview ................................................................................................. 7-28

7.4.2 Small Entity Economic Impact Measures........................................................................................ 7-33

7.4.3 Small Entity Economic Impact Analysis, Final NSPS..................................................................... 7-35

7.4.3.1 Overview of Sample Data and Methods................................................................................. 7-35

7.4.3.2 Small Entity Impact Analysis, Final NSPS, Results .............................................................. 7-41

7.4.3.3 Small Entity Impact Analysis, Final NSPS, Additional Qualitative Discussion .................... 7-47

7.4.4 Small Entity Economic Impact Analysis, Final NESHAP Amendments ........................................ 7-50

7.4.5 Conclusions for NSPS and NESHAP Amendments........................................................................ 7-52

7.5 REFERENCES .............................................................................................................................................. 7-53
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LIST OF TABLES

Table 1-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS 

in 2015 (millions of 2008$)1............................................................................................................... 1-4

Table 1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas 

NESHAP in 2015 (millions of 2008$)1.............................................................................................. 1-6

Table 2-1 Technically Recoverable Crude Oil and Natural Gas Resource Estimates, 2007............................. 2-10

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

Recovery, 1977-2008 ....................................................................................................................... 2-11

Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by State, 2008..................................................... 2-13

Table 2-4 Crude Oil Domestic Production, Wells, Well Productivity, and U.S. Average First Purchase Price2-14

Table 2-5 Natural Gas Production and Well Productivity, 1990-2009............................................................. 2-15

Table 2-6 Crude Oil and Natural Gas Exploratory and Development Wells and Average Depth, 1990-2009. 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, 1990-2008................................................................... 2-20

Table 2-9 Crude Oil Consumption by Sector, 1990-2009 ................................................................................ 2-21

Table 2-10 Natural Gas Consumption by Sector, 1990-2009............................................................................. 2-23

Table 2-11 Total Crude Oil and Petroleum Products Imports (Million Bbl), 1990-2009................................... 2-25

Table 2-12 Natural Gas Imports and Exports, 1990-2009 .................................................................................. 2-26

Table 2-13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2035 ....................................... 2-27

Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2010-2035..................................... 2-29

Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price ...................................... 2-31

Table 2-16 SBA Size Standards and Size Distribution of Oil and Natural Gas Firms ....................................... 2-38

Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-09 ..................................................... 2-39

Table 2-18 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2009 (2008 dollars)..................... 2-43

Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2010.......................................... 2-47

Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009.............................................. 2-48

Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2009............................. 2-49

Table 2-22 Selected Financial Items from Income Statements (Billion 2008 Dollars) ...................................... 2-50

Table 2-23 Return on Investment for Lines of Business (all FRS), for 1998, 2003, and 2008 (percent) ........... 2-51

Table 2-24 Income and Production Taxes, 1990-2008 (Million 2008 Dollars).................................................. 2-52

Table 3-1 Emissions Sources, Points, and Controls Included in the Final NSPS ............................................... 3-9

Table 3-2 Summary of Capital and Annualized Costs per Unit for NSPS Emissions Points ........................... 3-15

Table 3-3 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction CostEffectiveness by Emissions Sources and Points, NSPS, 2015 ......................................................... 3-16

Table 3-4 Engineering Compliance Costs, NSPS (2008$) ............................................................................... 3-18

Table 3-5 Estimates of Control Unit-level and National Level Natural Gas and Condensate Recovery, NSPS, 

2015.................................................................................................................................................. 3-21

Table 3-6 Simple Rate of Return Estimate for Final NSPS Controls ............................................................... 3-23

Table 3-7 Summary of Estimated Capital and Annual Costs, Emissions Reductions, and HAP Reduction CostEffectiveness for Final NESHAP Amendments............................................................................... 3-26

Table 4-1 Direct Emission Reductions Associated with the Oil and Natural Gas NSPS and NESHAP 

Amendments in 2015 (short tons per year) ........................................................................................ 4-3

Table 4-2 Secondary Air Pollutant Impacts Associated with Control Techniques by Emissions Category 

(“Producer-Side”) (tons per year)....................................................................................................... 4-6

Table 4-3 Modeled Changes in Energy-related CO2-equivalent Emissions by Fuel Type for the Final Oil and 

Gas NSPS in 2015 (million metric tons) ("Consumer-Side")1........................................................... 4-7

Table 4-4 Total Change in CO2-equivalent Emissions including Secondary Impacts for the Final Oil and Gas 

NSPS in 2015 (million metric tons) ................................................................................................... 4-7

Table 4-5 Summary of Emissions Changes for the Final Oil and Gas NSPS and NESHAP in 2015 (short tons 

per year).............................................................................................................................................. 4-8

Table 4-6 Monetized Benefits-per-Ton Estimates for VOC (2008$) ............................................................... 4-22

Table 4-7 Climate Methane Benefits Using ‘GWP’ Approach......................................................................... 4-32

Table 5-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS 

and NESHAP Amendments in 2015 (millions of 2008$)1................................................................. 5-2
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Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS 

in 2015 (millions of 2008$)1............................................................................................................... 6-4

Table 6-2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas 

NESHAP Amendments in 2015 (millions of 2008$)1........................................................................ 6-5

Table 6-3 Summary of Emissions Changes for the Final Oil and Gas NSPS and NESHAP in 2015 (short tons 

per year).............................................................................................................................................. 6-6

Table 7-1 Summary of Additional Annualized O&M Costs (on a Per New Well Basis) for Environmental 

Controls Entered into NEMS.............................................................................................................. 7-8

Table 7-2 Summary of Additional Per Completion/Recompletion Costs (2008$) for Environmental Controls 

Entered into NEMS ............................................................................................................................ 7-9

Table 7-3 Successful Oil and Gas Wells Drilled, NSPS................................................................................... 7-11

Table 7-4 Successful Wells Drilled by Well Type (Onshore, Lower 48 States), NSPS ................................... 7-12

Table 7-5 Annual Domestic Natural Gas and Crude Oil Production, NSPS .................................................... 7-13

Table 7-6 Natural Gas Production by Well Type (Onshore, Lower 48 States), NSPS ..................................... 7-14

Table 7-7 Lower 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS............................................ 7-15

Table 7-8 Delivered Natural Gas Prices by Sector (2008$ per million BTU), 2015, NSPS............................. 7-15

Table 7-9 Natural Gas Consumption by Sector, NSPS..................................................................................... 7-16

Table 7-10 Net Imports of Natural Gas and Crude Oil, NSPS ........................................................................... 7-17

Table 7-11 Total Energy Consumption by Energy Type (Quadrillion BTU), NSPS.......................................... 7-18

Table 7-12 Modeled Change in Energy-related "Consumer-Side" CO2-equivalent GHG Emissions ................ 7-19

Table 7-13 Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and 

Maintaining Control Equipment Requirements, NSPS, 2015 .......................................................... 7-25

Table 7-14 Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and 

Maintaining Control Equipment Requirements, Final NESHAP Amendments, 2015 ..................... 7-26

Table 7-15 Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007 .... 7-30

Table 7-16 Distribution of Small and Large Firms by Number of Firms, Total Employment, and Estimated 

Receipts by Firm Size and NAICS, 2007......................................................................................... 7-31

Table 7-17 Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009............................... 7-33

Table 7-18 Estimated Revenues for Firms in Sample, by Firm Type and Size .................................................. 7-37

Table 7-19 Descriptive Statistics of Capital and Exploration Expenditures, Small and Large Firms in Sample, 

2008 and 2009 (million 2008 dollars) .............................................................................................. 7-38

Table 7-20 Descriptive Statistics of Estimated Wells Drilled, Small and Large Firms in Sample, 2008 and 2009 

(million 2008 dollars)....................................................................................................................... 7-39

Table 7-21 Distribution of Estimated Final NSPS Compliance Costs Without Revenues from Additional Natural 

Gas Product Recovery across Firm Size in Sample of Firms........................................................... 7-42

Table 7-22 Distribution of Estimated Final NSPS Compliance Costs With Revenues from Additional Natural Gas 

Product Recovery across Firm Size in Sample of Firms.................................................................. 7-43

Table 7-23 Summary of Sales Test Ratios, Without Revenues from Additional Natural Gas Product Recovery for 

Firms Affected by Final NSPS......................................................................................................... 7-44

Table 7-24 Summary of Sales Test Ratios, With Revenues from Additional Natural Gas Product Recovery for 

Firms Affected by Final NSPS......................................................................................................... 7-45

Table 7-25 Impact Levels of Final NSPS on Small Firms as a Percent of Small Firms in Sample, With and 

Without Revenues from Additional Natural Gas Product Recovery................................................ 7-46

Table 7-26 Summary of Sales Test Ratios for Firms Affected by Final NESHAP Amendments...................... 7-51

Table 7-27 Affected Small Firms as a Percent of Small Firms Nationwide, Final NESHAP Amendments ...... 7-52

Table 7-28 Affected Small Firms as a Percent of Small Firms Nationwide, Final NSPS and NESHAP 

Amendments..................................................................................................................................... 7-52
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LIST OF FIGURES

Figure 2-1 A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990-2008. B) Domestic 

Natural Gas Proved Reserves and Cumulative Production, 1990-2008 ........................................... 2-12

Figure 2-2 A) Total Producing Crude Oil Wells and Average Well Productivity, 1990-2009. B) Total Producing 

Natural Gas Wells and Average Well Productivity, 1990-2009....................................................... 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), 1990-2009............................. 2-22

Figure 2-5 Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-2009 ......................... 2-24

Figure 2-6 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2035 ....................................... 2-28

Figure 2-7 Forecast of Domestic Crude Oil Production and Net Imports, 2010-2035....................................... 2-30

Figure 2-8 Costs of Crude Oil and Natural Gas Wells Drilled, 1981-2008 ....................................................... 2-32

Figure 2-9 Finding Costs for FRS Companies, 1981-2008................................................................................ 2-33

Figure 2-10 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2008 (3-year Running Average)2-

34

Figure 2-11 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976 

dollars), 1976-2009 .......................................................................................................................... 2-35

Figure 2-12 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas Price, 1976-2009

2-36

Figure 2-13 Employment in Drilling of Oil and Natural Gas Wells (NAICS 213111), and Total Oil and Natural 

Gas Wells Drilled, 1990-2009.......................................................................................................... 2-40

Figure 2-14 Employment in Crude Petroleum and Natural Gas Extraction (NAICS 211111) and Total Crude Oil 

and Natural Gas Production (boe), 1990-2009................................................................................. 2-41

Figure 2-15 Employment in Natural Gas Liquid Extraction (NAICS 211112), Employment in Pipeline 

Transportation of Natural Gas (NAICS 486210), and Total Natural Gas Production, 1990-2009... 2-42

Figure 2-16 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2009 ($2008)............................... 2-44

Figure 3-1 Sensitivity Analysis of Final NSPS Annualized Costs after Revenues from Additional Product 

Recovery are Included...................................................................................................................... 3-19

Figure 4-1 Conceptual Diagram of Secondary Impacts from Oil and Gas NSPS and NESHAP Amendments... 4-5

Figure 4-2 Estimated Chronic Census Tract Carcinogenic Risk from HAP exposure from outdoor sources (2005 

NATA) ............................................................................................................................................. 4-10

Figure 4-3 Estimated Chronic Census Tract Noncancer (Respiratory) Risk from HAP exposure from outdoor 

sources (2005 NATA) ...................................................................................................................... 4-11

Figure 6-1 Illustrative Break-Even Diagram for Alternate Natural Gas Prices for the NSPS.............................. 6-2

Figure 7-1 Organization of NEMS Modules (source: U.S. Energy Information Administration) ....................... 7-4
1-1

1 EXECUTIVE SUMMARY

1.1 Background

The U.S. Environmental Protection Agency (EPA) reviewed the New Source 

Performance Standards (NSPS) for volatile organic compound and sulfur dioxide emissions from 

Natural Gas Processing Plants. As a result of these NSPS, this rule amends the Crude Oil and 

Natural Gas Production source category currently listed under section 111 of the Clean Air Act 

to include Natural Gas Transmission and Distribution, amends the existing NSPS for volatile 

organic compounds (VOC) from Natural Gas Processing Plants, and finalizes NSPS for 

stationary sources in the source categories that are not covered by the existing NSPS. In 

addition, this rule addresses the residual risk and technology review conducted for two source 

categories in the Oil and Natural Gas sector regulated by separate National Emission Standards 

for Hazardous Air Pollutants (NESHAP). It also finalizes standards for emission sources not 

currently addressed, as well as amendments to improve aspects of these NESHAP related to 

applicability and implementation. Finally, it addresses provisions in these NESHAP related to 

emissions during periods of startup, shutdown, and malfunction.

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

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

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

the NESHAP Amendments are being finalized in the same rulemaking package (i.e., same 

Preamble), we have chosen to present the economic impact analysis for the final NESHAP 

Amendments within the same document as the NSPS RIA.

This RIA includes an economic impact analysis and an analysis of human health and 

climate impacts anticipated from the final NSPS and NESHAP Amendments. We also estimate 

potential impacts of the final NSPS 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 a 7 percent discount rate. This analysis assumes an 

analysis year of 2015.

Several emission controls for the NSPS capture VOC emissions that otherwise would be 

vented to the atmosphere. Since methane is co-emitted with VOC, a large proportion of the 
1-2

averted methane emissions can be directed into natural gas production streams and sold. One 

emissions control option, reduced emissions well completions, also recovers saleable 

hydrocarbon condensates which would otherwise be lost to the environment. The revenues 

derived from additional natural gas and condensate recovery are expected to offset the 

engineering costs of implementing the NSPS. In the economic impact and energy economy 

analyses for the NSPS, we present results that include the additional product recovery and the 

revenues we expect producers to gain from the additional product recovery.

1.2 Summary of Results 

1.2.1 NSPS Results

For the final NSPS, the key results of the RIA follow and are summarized in Table 1-1:

 Benefits Analysis: The final NSPS is anticipated to prevent significant new emissions, 

including 290,000 tons of VOC, as well as 19,000 tons of hazardous air pollutants (HAP) and 

1.7 million tons of methane. While we expect that these 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. This is not to imply that there are no 

benefits of the rules; 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 methane 

emissions reductions associated with the final NSPS are likely to result in significant climate 

co-benefits. The specific control technologies for the final NSPS are anticipated to have 

minor secondary disbenefits, including an increase of 1.2 million tons of carbon dioxide 

(CO2), 630 tons of nitrogen oxides NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of 

total hydrocarbons (THC) as well as emission reductions associated with the energy system 

impacts. The net CO2-equivalent (CO2-e) emission reductions are 31 million metric tons.

 Engineering Cost Analysis: EPA estimates the total capital cost of the final NSPS will be 

$340 million. The estimate of total annualized engineering costs of the final NSPS will be 

$330 million. When estimated revenues from additional natural gas and condensate recovery

are included, the annualized engineering costs of the final NSPS are estimated at -$18

million, assuming a wellhead natural gas price of $4/thousand cubic feet (Mcf) and 

condensate price of $70/barrel. Possible explanations for why there appear to be negative 

cost control technologies are discussed in the engineering costs analysis section in the RIA. 

The estimated engineering compliance costs that include the product recovery are sensitive to 

the assumption about the price of the recovered product. There is also geographic variability

in wellhead prices, which can also influence estimated engineering costs. For example, 

$1/Mcf change in the wellhead price causes a change in estimated engineering compliance 

costs of about $82 million, given EPA estimates that 82 billion cubic feet of natural gas will 

be recovered by implementing the NSPS. All estimates are in 2008 dollars.
1-3

 Energy System Impacts: Using the NEMS, when additional natural gas recovery is 

included, the analysis of energy system impacts for the final NSPS shows that domestic 

natural gas production is likely to increase slightly (about 60 billion cubic feet or 0.3 percent) 

and average natural gas prices to decrease slightly (about $0.05/Mcf or 1.2 percent at the 

wellhead for onshore production in the lower 48 states). Domestic crude oil production is not 

expected to change, while average crude oil prices are estimated to decrease slightly (about 

$0.01/barrel or about 0.01 percent at the wellhead for onshore production in the lower 48 

states). All prices are in 2008 dollars.

 Small Entity Analyses: For the final NSPS, EPA performed a screening analysis for impacts 

on a sample of expected affected small entities by comparing compliance costs to entity

revenues. When revenue from additional natural gas product recovered is not included, we 

estimate that 120 of the 127 small firms analyzed (94.5 percent) are likely to have impacts 

less than 1 percent in terms of the ratio of annualized compliance costs to revenues. 

Meanwhile, seven firms (5.5 percent) are likely to have impacts greater than 1 percent. Three 

of these seven firms are likely to have impacts greater than 3 percent. However, when 

revenue from additional natural gas product recovery is included, we estimate that none of 

the analyzed firms will have an impact greater than 1 percent.

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

operation, and maintenance of control equipment, as well as labor associated with new 

reporting and recordkeeping requirements. We estimate up-front 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 up-front labor requirement to comply with the final NSPS is estimated at 

50 full-time-equivalent employees. The annual labor requirement to comply with final NSPS 

is estimated at about 1,100 full-time-equivalent employees. 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.
1-4

Table 1-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil 

and Natural Gas NSPS in 2015 (millions of 2008$)1

Final4

Total Monetized Benefits2 N/A

Total Costs3 -$18 million

Net Benefits N/A

Non-monetized Benefits 19,000 tons of HAP5

290,000 tons of VOC

1.7 million tons of methane5

Health effects of HAP exposure5

Health effects of PM2.5 and ozone exposure

Visibility impairment

Vegetation effects

Climate effects5

1 All estimates are for the implementation year (2015) and include estimated revenue from additional natural gas 

recovery as a result of the NSPS.

2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health 

effects associated with HAP, ozone, and particulate matter (PM) as well as climate effects associated with methane, 

we have determined that quantification of those benefits and co-benefits cannot be accomplished for this rule in a 

defensible way. This is not to imply that there are no benefits or co-benefits of the rules; 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. The specific control technologies for the final NSPS are anticipated to have minor 

secondary disbenefits, including an increase of 1.2 million tons of carbon dioxide (CO2), 630 tons of nitrogen oxides 

NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as well as emission reductions 

associated with the energy system impacts. The net CO2-equivalent (CO2-e) emission reductions are 31 million 

metric tons.

3 The engineering compliance costs are annualized using a 7 percent discount rate. 

4 The negative cost for the NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon 

condensate recovery that are estimated as a result of the final NSPS. Possible explanations for why there appear to 

be negative cost control technologies are discussed in the engineering costs analysis section in the RIA. 

5 Reduced exposure to HAP and climate effects are co-benefits.
1-5

1.2.2 NESHAP Amendments Results

For the final NESHAP Amendments, the key results of the RIA follow and are summarized in 

Table 1-2:

 Benefits Analysis: The final NESHAP Amendments are anticipated to reduce a significant 

amount of existing emissions, including 1,300 tons of HAP, 9,000 tons of VOC, and 4,800

tons of methane. While we expect that these avoided emissions will result in improvements 

in ambient air quality and reductions in health effects associated with exposure to HAP,

ozone, and PM, we have determined that quantification of those benefits cannot be 

accomplished for this rule. This is not to imply that there are no benefits of the rules; 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, 

and climate effects as well as additional natural gas recovery. The specific control 

technologies for the NESHAP is anticipated to have minor secondary disbenefits, including 

an increase of 5,500 tons of CO2, 2.9 tons of NOx, 16 tons of CO, and 6.0 tons of total 

hydrocarbons (THC) as well as emission reductions associated with the energy system 

impacts. The net CO2-equivalent emission reductions are 90,000 metric tons. 

 Engineering Cost Analysis: EPA estimates the total capital costs of the final NESHAP 

Amendments to be $47 million. Total annualized engineering costs of the final NESHAP 

Amendments are estimated to be $18 million. All estimates are in 2008 dollars.

 Energy System Impacts: We did not estimate the energy economy impacts of the final 

NESHAP Amendments as the expected costs of the rule are not likely to have estimable 

impacts on the national energy economy.

 Small Entity Analyses: For the final NESHAP Amendments, EPA estimates that 54 of the 

108 firms (50 percent) that own potentially affected facilities are small entities. The EPA 

performed a screening analysis for impacts on all expected affected small entities by

comparing compliance costs to entity revenues. Among the small firms, 45 of the 54 (83 

percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized 

compliance costs to revenues. Meanwhile, nine firms (17 percent) are likely to have impacts 

greater than 1 percent. Three of these nine firms are likely to have impacts greater than 3 

percent. While these nine firms might receive significant impacts from the final NESHAP 

Amendments, they represent a very small slice of the oil and gas industry in its entirety, less 

than 0.2 percent of the estimated 6,427 small firms in NAICS 211.

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

operation, and maintenance of control equipment, as well as labor associated with new 

reporting and recordkeeping requirements. We estimate up-front 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 up-front labor requirement to comply with the final NESHAP 

Amendments is estimated at 120 full-time-equivalent employees. The annual labor 

requirement to comply with final NESHAP Amendments is estimated at about 94 full-timeequivalent employees. We note that this type of FTE estimate cannot be used to identify the 
1-6

specific number of people involved or whether new jobs are created for new employees, 

versus displacing jobs from other sectors of the economy.

 Break-Even Analysis: A break-even analysis suggests that HAP emissions would need to be 

valued at $14,000 per ton for the benefits to exceed the costs if the health benefits, ecosystem 

and climate co-benefits from the reductions in VOC and methane emissions are assumed to 

be zero. If we assume the health benefits from HAP emission reductions are zero, the VOC 

emissions would need to be valued at $1,900 per ton or the methane emissions would need to 

be valued at $3,700 per ton for the benefits to exceed the costs. Previous assessments have 

shown that the PM2.5 benefits associated with reducing VOC emissions were valued at $280 

to $7,000 per ton of VOC emissions reduced in specific urban areas. , ozone benefits valued 

at $240 to $1,000 per ton of VOC emissions reduced, and climate co-benefits valued at $110 

to $1,400 per short ton of methane reduced. All estimates are in 2008 dollars.

Table 1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil 

and Natural Gas NESHAP in 2015 (millions of 2008$)1

Final

Total Monetized Benefits2 N/A

Total Costs3 $18 million

Net Benefits N/A

Non-monetized Benefits 1,300 tons of HAP

9,000 tons of VOC4

4,800 tons of methane4

Health effects of HAP exposure

Health effects of PM2.5 and ozone exposure4

Visibility impairment4

Vegetation effects4

Climate effects4

1 All estimates are for the implementation year (2015).

2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health 

effects associated with HAP, ozone, and PM as well as climate effects associated with methane, we have 

determined that quantification of those benefits and co-benefits cannot be accomplished for this rule in a defensible 

way. This is not to imply that there are no benefits or co-benefits of the rules; 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. The specific control technologies for the NESHAP is anticipated to have minor 

secondary disbenefits, including an increase of 5,500 tons of CO2, 2.9 tons of NOx, 16 tons of CO, and 6.0 tons of 

total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO2-

equivalent emission reductions are 90,000 metric tons. 

3 The engineering compliance costs are annualized using a 7 percent discount rate. 

4 Reduced exposure to VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects, and climate 
1-7

effects are co-benefits.

1.2.3 Results for Combined Small Entity Analysis for the NSPS and NESHAP Amendments

After considering the economic impact of the combined NSPS and NESHAP 

Amendments on small entities, EPA certifies this action will not have a significant impact on a 

substantial number of small entities (SISNOSE). While both the NSPS and NESHAP 

amendment would individually result in a no SISNOSE finding, EPA performed an additional 

screening analysis in order to certify the rule in its entirety. This analysis compared compliance 

costs to entity revenues for the total of all the entities affected by the NESHAP Amendments

and the sample of entities analyzed for the NSPS. When revenues from additional natural gas 

product sales are not included, 153 of the 169 small firms (91 percent) are likely to have 

impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. 

Meanwhile, 16 firms (9 percent) are likely to have impacts greater than 1 percent. Six of these 

16 firms are likely to have impacts greater than 3 percent. When revenues from additional 

natural gas product sales are included, 160 small firms (95 percent) are likely to have impacts of 

less than 1 percent. Nine firms (5 percent) are likely to have impacts greater than 1 percent, 

while only three of these nine are likely to have impacts greater than 3 percent.

1.3 Summary of NSPS Impacts Changes from the Proposal RIA

This section summarizes significant changes from the proposal version of the RIA. These 

changes were a result of revised assumptions and technical factors, as well as changes in the rule 

itself from proposal. 

 Changed estimate of number of recompleted wells: The NSPS proposal estimated that

12,050 reduced emissions completions (RECs) for existing natural gas well 

recompletions would be required in addition to those already required by state 

regulations. EPA has reevaluated the assumption based on data submitted to the Agency. 

Based on this information, EPA has estimated the recompletion frequency to be 1% of 

fractured gas wells per year, rather than 10 percent. 

 Well completions with insufficient pressure to implement RECs required to combust 

completions emissions: Using the formula estimated to identify wells that would not 

have sufficient pressure to perform an REC, approximately 10 percent of well 

completions and recompletions would be required to combust emissions rather than 

implement an REC. 

 Revised natural gas emissions factor for well completions and recompletions of 

hydraulically fractured wells: The EPA received several comments regarding the 

emission factor selected to calculate whole gas emissions (and the associated VOC 

emissions) from hydraulically fractured well completions. Comments focused on the data 
1-8

behind the emission factor, what the emission factor is intended to represent, and the 

procedures used to develop the emission factor from the selected data sets. We reviewed 

all information received and have decided to retain the data set and the analysis 

conducted to develop the emission factor, but rounded from 9,175 Mcf per completion to

9,000 Mcf per completion. More detailed discussion is presented in a technical 

memorandum on this subject in the docket.

 Removal of compressors and pneumatic devices in the natural gas transmission 

segment from NSPS: In the final rule, proposed requirements relating to reciprocating 

and centrifugal compressors and pneumatic devices in transmission segment are 

removed. Requirements pertaining to storage vessels in the transmission segment 

remain.

 Reporting and recordkeeping costs: EPA identified several ways to streamline 

reporting and recordkeeping requirements. As a result, the estimated annual cost of 

reporting and recordkeeping from $19 million per year to $7.1 million per year.

1.4 Summary of NESHAP Amendments Impacts Changes from the Proposal RIA

The cost and emissions reduction estimates for the NESHAP Amendments did not change 

significantly from proposal. Total annualized costs increased about $1.5 million per year. 

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 business 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 

and NESHAP Amendments 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 (213112—Support Activities for Oil and 

Gas Operations, 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 final NSPS and NESHAP Amendments.

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

of gas, energy, and petroleum products. As of 2009, the Energy Information Administration 

(EIA) estimates that about 526,000 producing oil wells and 493,000 producing natural gas wells 

operated in the United States. Domestic dry natural gas production was 20.5 trillion cubic feet 

(tcf) in 2009, the highest production level since 1970. The leading five natural gas producing 

states are Texas, Alaska, Wyoming, Oklahoma, and New Mexico. Domestic crude oil 

production in 2009 was 1,938 million barrels (bbl). The leading five crude oil producing states 

are Texas, Alaska, California, Oklahoma, and New Mexico. 

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

gas industry that are relevant to the final NSPS and NESHAP Amendments. The purpose is to 

give the reader a general understanding of the geophysical, engineering, and economic aspects of 

the industry that are addressed in subsequent economic analysis in this RIA. The Industry

Profile relies heavily on background material from the U.S. EPA’s “Economic Analysis of Air 
2-2

Pollution Regulations: Oil and Natural Gas Production” (1996) and the U.S. EPA’s “Sector 

Notebook Project: Profile of the Oil and Gas Extraction Industry” (2000).

2.2 Products of the Crude Oil and Natural Gas Industry

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

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

from that of any other reservoir. 

2.2.1 Crude Oil

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

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

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

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

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

may contain a high concentration of sulfur compounds. Intermediate crudes are those that are 

not classified in either of the above categories. 

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

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

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

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

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

30's to the low 40's.

Crude oils recovered in the production phase of the petroleum industry 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.

2.2.2 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 
2-3

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 total onshore natural gas production and nearly all of offshore natural gas 

production is classified as sweet.

2.2.3 Condensates

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

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

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

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

gas transmission and storage processes and operations.

2.2.4 Other Recovered Hydrocarbons

Various hydrocarbons may be recovered through the processing of the extracted 

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

gasoline, propane, butane, and liquefied petroleum gas (LPG). 
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, 2009). 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, 2009). 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 natural gas resource 

types relevant for this rule include:

 Shale 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, 2009).

 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, 2009).

 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 natural gas proved reserves, inferred reserves,

undiscovered technically recoverable resources and total technically recoverable resources as of 

2007. According to EIA1, 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.

 Inferred reserves: the estimate of total volume recovery from known crude oil or 

natural gas reservoirs or aggregation of such reservoirs is expected to increase during 

the time between discovery and permanent abandonment. 

 Technically recoverable: resources that are producible using current technology

without reference to the economic viability of production. 

The sum of proved reserves, inferred reserves, and undiscovered technically recoverable 

resources equal the total technically recoverable resources. As seen in Table 2-1, as of 2007, 

proved domestic crude oil reserves accounted for about 12 percent of the totally technically 

recoverable crude oil resources.

 

1 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, 

2007

Region

Proved

Reserves

Inferred 

Reserves

Undiscovered 

Technically 

Recoverable 

Resources

Total 

Technically 

Recoverable 

Resources

Crude Oil and Lease Condensate (billion bbl)

 48 States Onshore 14.2 48.3 25.3 87.8

 48 States Offshore 4.4 10.3 47.2 61.9

 Alaska 4.2 2.1 42.0 48.3

 Total U.S. 22.8 60.7 114.5 198.0

Dry Natural Gas (tcf)

 Conventionally Reservoired Fields 194.0 671.3 760.4 1625.7

 48 States Onshore Non-Associated Gas 149.0 595.9 144.1 889.0

 48 States Offshore Non-Associated Gas 12.4 50.7 233.0 296.0

 Associated-Dissolved Gas 20.7 117.2 137.9

 Alaska 11.9 24.8 266.1 302.8

 Shale Gas and Coalbed Methane 43.7 385 64.2 493.0

 Total U.S. 237.7 1056.3 824.6 2118.7

Source: U.S. Energy Information Administration, Annual Energy Review 2010. Inferred reserves for associateddissolved natural gas are included in "Undiscovered Technically Recoverable Resources." Totals may not sum due 

to independent rounding.

Proved natural gas reserves accounted for about 11 percent of the totally technically recoverable

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

areas.

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

from 1990 to 2008. 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 

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. 
2-11

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

Reserves, and Proved Ultimate Recovery, 1977-2008

Crude Oil and Lease Condensate

(million bbl)

Dry Natural Gas

(bcf)

Year

Cumulative

Production

Proved

Reserves

Proved

Ultimate

Recovery

Cumulative

Production

Proved

Reserves

Proved

Ultimate

Recovery

1990 158,175 27,556 185,731 744,546 169,346 913,892

1991 160,882 25,926 186,808 762,244 167,062 929,306

1992 163,507 24,971 188,478 780,084 165,015 945,099

1993 166,006 24,149 190,155 798,179 162,415 960,594

1994 168,438 23,604 192,042 817,000 163,837 980,837

1995 170,832 23,548 194,380 835,599 165,146 1,000,745

1996 173,198 23,324 196,522 854,453 166,474 1,020,927

1997 175,553 23,887 199,440 873,355 167,223 1,040,578

1998 177,835 22,370 200,205 892,379 164,041 1,056,420

1999 179,981 23,168 203,149 911,211 167,406 1,078,617

2000 182,112 23,517 205,629 930,393 177,427 1,107,820

2001 184,230 23,844 208,074 950,009 183,460 1,133,469

2002 186,327 24,023 210,350 968,937 186,946 1,155,883

2003 188,400 23,106 211,506 988,036 189,044 1,177,080

2004 190,383 22,592 212,975 1,006,564 192,513 1,199,077

2005 192,273 23,019 215,292 1,024,638 204,385 1,229,023

2006 194,135 22,131 216,266 1,043,114 211,085 1,254,199

2007 196,079 22,812 218,891 1,062,203 237,726 1,299,929

2008 197,987 20,554 218,541 1,082,489 244,656 1,327,145

Source: U.S. Energy Information Administration, Annual Energy Review 2010.

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

crude oil and natural gas, from above 10 percent in the early 1990s to 8 to 9 percent from 2006 to 

2008 for crude oil and from above 11 percent during the 1990s to about 8 percent from 2008 to 

2008 for natural gas.
2-12

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

2008. B) Domestic Natural Gas Proved Reserves and Cumulative Production, 1990-2008

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

producing area as of 2008. Four areas currently account for 77 percent of the U.S. total proved 

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

California. The top five states (Texas, Wyoming, Colorado, Oklahoma, and New Mexico) 

account for about 69 percent of the U.S. total proved reserves of natural gas.

A). Crude Oil

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

Cru

de Oil (million

b

bl)

B). Natural Gas

0

50,000

100,000

150,000

200,000

250,000

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

Natural Gas (bcf)

Cumulative Production Proved Reserves
2-13

Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by State, 2008

State/Region

Crude Oil

(million bbls)

Dry Natural Gas 

(bcf)

Crude Oil

(percent of total)

Dry Natural Gas

(percent of total)

Alaska 3,507 7,699 18.3 3.1

Alabama 38 3,290 0.2 1.3

Arkansas 30 5,626 0.2 2.3

California 2,705 2,406 14.1 1.0

Colorado 288 23,302 1.5 9.5

Florida 3 1 0.0 0.0

Illinois 54 0 0.3 0.0

Indiana 15 0 0.1 0.0

Kansas 243 3,557 1.3 1.5

Kentucky 17 2,714 0.1 1.1

Louisiana 388 11,573 2.0 4.7

Michigan 48 3,174 0.3 1.3

Mississippi 249 1,030 1.3 0.4

Montana 321 1,000 1.7 0.4

Nebraska 8 0 0.0 0.0

New Mexico 654 16,285 3.4 6.7

New York 0 389 0.0 0.2

North Dakota 573 541 3.0 0.2

Ohio 38 985 0.2 0.4

Oklahoma 581 20,845 3.0 8.5

Pennsylvania 14 3,577 0.1 1.5

Texas 4,555 77,546 23.8 31.7

Utah 286 6,643 1.5 2.7

Virginia 0 2,378 0.0 1.0

West Virginia 23 5,136 0.1 2.1

Wyoming 556 31,143 2.9 12.7

Miscellaneous States 24 270 0.1 0.1

U.S. Federal Offshore 3,903 13,546 20.4 5.5

Total Proved Reserves 19,121 244,656 100.0 100.0

Source: U.S. Energy Information Administration, Annual Energy Review 2010. Totals may not sum due to 

independent rounding.

2.4.2 Domestic Production

Domestic oil production is currently in a state of decline that began in 1970. Table 2-4

shows U.S. production in 2009 at 1938 million bbl per year, the highest level since 2004.

However, annual domestic production of crude oil has dropped by almost 750 million bbl since 

1990. 
2-14

Table 2-4 Crude Oil Domestic Production, Wells, Well Productivity, and U.S. Average 

First Purchase Price

Year

Total Production 

(million bbl)

Producing Wells 

(1000s)

Avg. Well 

Productivity 

(bbl/well)

U.S. Average First 

Purchase Price/Barrel 

(2005 dollars)

1990 2,685 602 4,460 27.74

1991 2,707 614 4,409 22.12

1992 2,625 594 4,419 20.89

1993 2,499 584 4,279 18.22

1994 2,431 582 4,178 16.51

1995 2,394 574 4,171 17.93

1996 2,366 574 4,122 22.22

1997 2,355 573 4,110 20.38

1998 2,282 562 4,060 12.71

1999 2,147 546 3,932 17.93

2000 2,131 534 3,990 30.14

2001 2,118 530 3,995 24.09

2002 2,097 529 3,964 24.44

2003 2,073 513 4,042 29.29

2004 1,983 510 3,889 38.00

2005 1,890 498 3,795 50.28

2006 1,862 497 3,747 57.81

2007 1,848 500 3,697 62.63

2008 1,812 526 3,445 86.69

2009 1,938 526 3,685 51.37*

Source: U.S. Energy Information Administration, Annual Energy Review 2010.

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

2009 Oil price is preliminary

Average well productivity has also 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. The exception to this general trend occurred in 2008 

and 2009 when the real price increased up to 86 dollars per barrel and production in 2009 

increased to almost 2 million bbl of oil.

Annual production of natural gas from natural gas wells has increased nearly 3000 bcf

from the 1990 to 2009 (Table 2-5). Natural gas extracted from crude oil wells (associated 

natural gas) has remained more or less constant for the last twenty years. Coalbed methane has 

become a significant component of overall gas withdrawals in recent years. 
2-15

Table 2-5 Natural Gas Production and Well Productivity, 1990-2009

Natural Gas Gross Withdrawals 

(bcf)

Natural Gas Well

Productivity

Year

Natural Gas

Wells

Crude Oil

Wells

Coalbed 

Methane

Wells Total

Dry Gas 

Production*

Producing 

Wells 

(no.)

Avg. 

Productivity 

per Well 

(MMcf)

1990 16,054 5,469 NA 21,523 17,810 269,100 59.657

1991 16,018 5,732 NA 21,750 17,698 276,337 57.964

1992 16,165 5,967 NA 22,132 17,840 275,414 58.693

1993 16,691 6,035 NA 22,726 18,095 282,152 59.157

1994 17,351 6,230 NA 23,581 18,821 291,773 59.468

1995 17,282 6,462 NA 23,744 18,599 298,541 57.888

1996 17,737 6,376 NA 24,114 18,854 301,811 58.770

1997 17,844 6,369 NA 24,213 18,902 310,971 57.382

1998 17,729 6,380 NA 24,108 19,024 316,929 55.938

1999 17,590 6,233 NA 23,823 18,832 302,421 58.165

2000 17,726 6,448 NA 24,174 19,182 341,678 51.879

2001 18,129 6,371 NA 24,501 19,616 373,304 48.565

2002 17,795 6,146 NA 23,941 18,928 387,772 45.890

2003 17,882 6,237 NA 24,119 19,099 393,327 45.463

2004 17,885 6,084 NA 23,970 18,591 406,147 44.036

2005 17,472 5,985 NA 23,457 18,051 425,887 41.025

2006 17,996 5,539 NA 23,535 18,504 440,516 40.851

2007 17,065 5,818 1,780 24,664 19,266 452,945 37.676

2008 18,011 5,845 1,898 25,754 20,286 478,562 37.636

2009 18,881 5,186 2,110 26,177 20,955 495,697 38.089

Source: U.S. Energy Information Administration, Annual Energy Review 2010.

*Dry gas production is gas production after accounting for gas used repressurizing wells, the removal of

nonhydrocarbon gases, vented and flared gas, and gas used as fuel during the production process.

The number of wells producing natural gas wells has nearly doubled between 1990 and 2009

(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. 
2-16

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

2009. B) Total Producing Natural Gas Wells and Average Well Productivity, 1990-2009.

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

From 2002 to 2009, crude oil well drilling showed significant increases, although the 1992-2001 

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 1990-2009 period. 

Like crude oil drilling, 2009 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 90 percent in 2009 (Table 2-6). The increasing success 

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

A). Crude Oil Wells

0

100

200

300

400

500

600

700

19901991199219931994199519961997199819992000200120022003200420052006200720082009

Prod

ucing Wells

0

1,000

2,000

3,000

4,000

5,000

Cru

de Oil (b

bl)/Well

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

B). Natural Gas Wells

0

100

200

300

400

500

600

19901991199219931994199519961997199819992000200120022003200420052006200720082009

Prod

ucing Wells

0

10

20

30

40

50

60

70

Natural Gas

(M

Mcf)/Well

Producing Wells (1000s) Avg. Well Productivity (MMcf)
2-17

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, 1990-2009

Wells Drilled

Year Crude Oil Natural Gas Dry Holes Total

Successful 

Wells 

(percent)

Average 

Depth (ft)

1990 12,800 11,227 8,237 32,264 75 4,841

1991 12,542 9,768 7,476 29,786 75 4,872

1992 9,379 8,149 5,857 23,385 75 5,138

1993 8,828 9,829 6,093 24,750 75 5,407

1994 7,334 9,358 5,092 21,784 77 5,736

1995 8,230 8,081 4,813 21,124 77 5,560

1996 8,819 9,015 4,890 22,724 79 5,573

1997 11,189 11,494 5,874 28,557 79 5,664

1998 7,659 11,613 4,763 24,035 80 5,722

1999 4,759 11,979 3,554 20,292 83 5,070

2000 8,089 16,986 4,134 29,209 86 4,942

2001 8,880 22,033 4,564 35,477 87 5,077

2002 6,762 17,297 3,728 27,787 87 5,223

2003 8,104 20,685 3,970 32,759 88 5,418

2004 8,764 24,112 4,053 36,929 89 5,534

2005E 10,696 28,500 4,656 43,852 89 5,486

2006E 13,289 32,878 5,183 51,350 90 5,537

2007E 13,564 33,132 5,121 51,817 90 5,959

2008E 17,370 34,118 5,726 57,214 90 6,202

2009E 13,175 19,153 3,537 35,865 90 6,108

Source: U.S. Energy Information Administration, Annual Energy Review 2010. Values for 2005-2009 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 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 1990-2008 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, 1990-2008

Oil Pipelines Natural Gas Pipelines

Year

Crude 

Lines

Product 

Lines Total

Distribution 

Mains

Transmission 

Pipelines

Gathering 

Lines Total

1990 118,805 89,947 208,752 945,964 291,990 32,420 1,270,374

1991 115,860 87,968 203,828 890,876 293,862 32,713 1,217,451

1992 110,651 85,894 196,545 891,984 291,468 32,629 1,216,081

1993 107,246 86,734 193,980 951,750 293,263 32,056 1,277,069

1994 103,277 87,073 190,350 1,002,669 301,545 31,316 1,335,530

1995 97,029 84,883 181,912 1,003,798 296,947 30,931 1,331,676

1996 92,610 84,925 177,535 992,860 292,186 29,617 1,314,663

1997 91,523 88,350 179,873 1,002,942 294,370 34,463 1,331,775

1998 87,663 90,985 178,648 1,040,765 302,714 29,165 1,372,644

1999 86,369 91,094 177,463 1,035,946 296,114 32,276 1,364,336

2000 85,480 91,516 176,996 1,050,802 298,957 27,561 1,377,320

2001 52,386 85,214 154,877 1,101,485 290,456 21,614 1,413,555

2002 52,854 80,551 149,619 1,136,479 303,541 22,559 1,462,579

2003 50,149 75,565 139,901 1,107,559 301,827 22,758 1,432,144

2004 50,749 76,258 142,200 1,156,863 303,216 24,734 1,484,813

2005 46,234 71,310 131,348 1,160,311 300,663 23,399 1,484,373

2006 47,617 81,103 140,861 1,182,884 300,458 20,420 1,503,762

2007 46,658 85,666 147,235 1,202,135 301,171 19,702 1,523,008

2008 50,214 84,914 146,822 1,204,162 303,331 20,318 1,527,811

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

Pipeline Safety, Natural Gas Transmission, Gas Distribution, and Hazardous Liquid Pipeline Annual Mileage, 

available at http://ops.dot.gov/stats.htm as of Apr. 28, 2010. Totals may not sum due to independent rounding.

Table 2-8 splits natural gas pipelines into three types: distribution mains, 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. Table 2-8 shows gathering lines decreasing from 1990 from above 30,000 miles 

from 1990 to 1995 to around 20,000 miles in 2007 and 2008. Transmission pipelines added 
2-21

about 10,000 miles during this period, from about 292,000 in 1990 to about 303,000 miles in 

2008. The most significant growth among all types of pipeline was in distribution, which 

increased about 260,000 miles during the 1990 to 2008 period, driving an increase in total 

natural gas pipeline mileage (Figure 2-1). The growth in distribution is likely driven by

expanding production as well as expanding gas markets in growing U.S. towns and cities.

2.4.3 Domestic Consumption

Historical crude oil sector-level consumption trends for 1990 through 2009 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 2009.

Table 2-9 Crude Oil Consumption by Sector, 1990-2009

Percent of Total

Year

Total

(million bbl) Residential Commercial Industrial

Transportation

Sector

Electric 

Power

1990 6,201 4.4 2.9 25.3 64.1 3.3

1991 6,101 4.4 2.8 25.2 64.4 3.1

1992 6,234 4.4 2.6 26.5 63.9 2.5

1993 6,291 4.5 2.4 25.7 64.5 2.9

1994 6,467 4.3 2.3 26.3 64.4 2.6

1995 6,469 4.2 2.2 25.9 65.8 1.9

1996 6,701 4.4 2.2 26.3 65.1 2.0

1997 6,796 4.2 2.0 26.6 65.0 2.2

1998 6,905 3.8 1.9 25.6 65.7 3.0

1999 7,125 4.2 1.9 25.8 65.4 2.7

2000 7,211 4.4 2.1 24.9 66.0 2.6

2001 7,172 4.3 2.1 24.9 65.8 2.9

2002 7,213 4.1 1.9 25.0 66.8 2.2

2003 7,312 4.2 2.1 24.5 66.5 2.7

2004 7,588 4.0 2.0 25.2 66.2 2.6

2005 7,593 3.9 1.9 24.5 67.1 2.6

2006 7,551 3.3 1.7 25.1 68.5 1.4

2007 7,548 3.4 1.6 24.4 69.1 1.4

2008 7,136 3.7 1.8 23.2 70.3 1.1

2009* 6,820 3.8 1.8 22.5 71.1 0.9

Source: U.S. Energy Information Administration, Annual Energy Review 2010. 2009 consumption is preliminary.
2-22

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

2009

Natural gas consumption has increased over the last twenty years. From 1990 to 2009,

total U.S. consumption increased by an average of about 1 percent per year (Table 2-10 and 

Figure 2-5). Over the same period, industrial consumption of natural gas declined, whereas 

electric power generation increased its consumption quite dramatically, an important trend in the 

industry as many utilities increasingly use natural gas for peak generation or switch from coalbased to natural gas-based electricity generation. The residential, commercial, and transportation 

sectors maintained their consumption levels at more or less constant levels during this time 

period.

0%

10%

20%

30%

40%

50%

60%

70%

80%

1990199119921993199419951996199719981999200020012002200320042005200620072008

2009*

Consumption (% of total)

Residential Commercial

Industrial Transportation Sector

Electric Power
2-23

Table 2-10 Natural Gas Consumption by Sector, 1990-2009

Percent of Total

Year

Total 

(bcf) Residential Commercial Industrial

Transportation

Sector

Electric 

Power

1990 19,174 22.9 13.7 43.1 3.4 16.9

1991 19,562 23.3 13.9 42.7 3.1 17.0

1992 20,228 23.2 13.9 43.0 2.9 17.0

1993 20,790 23.8 13.8 42.7 3.0 16.7

1994 21,247 22.8 13.6 42.0 3.2 18.4

1995 22,207 21.8 13.6 42.3 3.2 19.1

1996 22,609 23.2 14.0 42.8 3.2 16.8

1997 22,737 21.9 14.1 42.7 3.3 17.9

1998 22,246 20.3 13.5 42.7 2.9 20.6

1999 22,405 21.1 13.6 40.9 2.9 21.5

2000 23,333 21.4 13.6 39.8 2.8 22.3

2001 22,239 21.5 13.6 38.1 2.9 24.0

2002 23,007 21.2 13.7 37.5 3.0 24.7

2003 22,277 22.8 14.3 37.1 2.7 23.1

2004 22,389 21.7 14.0 37.3 2.6 24.4

2005 22,011 21.9 13.6 35.0 2.8 26.7

2006 21,685 20.1 13.1 35.3 2.8 28.7

2007 23,097 20.4 13.0 34.1 2.8 29.6

2008 23,227 21.0 13.5 33.9 2.9 28.7

2009* 22,834 20.8 13.6 32.4 2.9 30.2

Source: U.S. Energy Information Administration, Annual Energy Review 2010. 2009 consumption is preliminary.

Totals may not sum due to independent rounding.
2-24

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

2009

2.4.4 International Trade

Imports of crude oil and refined petroleum products have increased over the last twenty

years, showing increased substitution of imports for domestic production, as well as imports 

satisfying growing consumer demand in the U.S (Table 2-11). Crude oil imports have increased 

by about 2 percent per year on average, whereas petroleum products have increased by 1 percent

on average per year. 

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

1990199119921993199419951996199719981999200020012002200320042005200620072008

2009*

Consumption (% of total)

Residential Commercial

Industrial Transportation Sector

Electric Power
2-25

Table 2-11 Total Crude Oil and Petroleum Products Imports (Million Bbl), 1990-2009

Year Crude Oil Petroleum Products Total Petroleum

1990 2,151 775 2,926

1991 2,111 673 2,784

1992 2,226 661 2,887

1993 2,477 669 3,146

1994 2,578 706 3,284

1995 2,639 586 3,225

1996 2,748 721 3,469

1997 3,002 707 3,709

1998 3,178 731 3,908

1999 3,187 774 3,961

2000 3,320 874 4,194

2001 3,405 928 4,333

2002 3,336 872 4,209

2003 3,528 949 4,477

2004 3,692 1,119 4,811

2005 3,696 1,310 5,006

2006 3,693 1,310 5,003

2007 3,661 1,255 4,916

2008 3,581 1,146 4,727

2009 3,307 973 4,280

Source: U.S. Energy Information Administration, Annual Energy Review 2010. * 2009 Imports are preliminary.

Natural gas imports also increased steadily from 1990 to 2007 in volume and percentage 

terms (Table 2-12). The years 2007 and 2008 saw imported natural gas constituting a lower 

percentage of domestic natural gas consumption. In 2009, the U.S exported 700 bcf natural gas 

to Canada, 338 bcf to Mexico via pipeline, and 33 bcf to Japan in LNG-form. In 2009, the U.S. 

primarily imported natural gas from Canada (3268 bcf, 87 percent) via pipeline, although a 

growing percentage of natural gas imports are in LNG-form shipped from countries such as 

Trinidad and Tobago and Egypt. 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, 1990-2009

Year

Total Imports 

(bcf)

Total Exports 

(bcf)

Net Imports

(bcf)

Percent of

U.S. Consumption

1990 1,532 86 1,447 7.5

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 12.5

1998 3,152 159 2,993 13.5

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 14.7

2004 4,259 854 3,404 15.2

2005 4,341 729 3,612 16.4

2006 4,186 724 3,462 16.0

2007 4,608 822 3,785 16.4

2008 3,984 1,006 2,979 12.8

2009* 3,748 1,071 2,677 11.7

Source: U.S. Energy Information Administration, Annual Energy Review 2010. 2009 Imports are preliminary.

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 2011 Annual Energy

Outlook produced by EIA, the most current forecast information available from EIA. As will be 

discussed in detail in Section 3, to analyze the impacts of the final NSPS on the national energy

economy, we use the National Energy Modeling System (NEMS) that was used to produce the 

2011 Annual Energy Outlook. 

Table 2-13 and Figure 2-6 present forecasts of successful wells drilled in the U.S. from 

2010 to 2035. Crude oil well forecasts for the lower 48 states show a rise from 2010 to a peak in 

2019, which is followed by a gradual decline until the terminal year in the forecast, totaling a 28

percent decline for the forecast period. The forecast of successful offshore crude oil wells shows 

a variable but generally increasing trend.
2-27

Table 2-13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2035

Lower 48 U.S. States Offshore Totals

Year

Crude 

Oil

Conventional 

Natural Gas

Tight 

Sands

Devonian 

Shale

Coalbed 

Methane

Crude 

Oil

Natural 

gas

Crude 

Oil

Natural 

Gas

2010 12,082 7,302 2,393 4,196 2,426 74 56 12,155 16,373

2011 10,271 7,267 2,441 5,007 1,593 81 73 10,352 16,380

2012 10,456 7,228 2,440 5,852 1,438 80 71 10,536 17,028

2013 10,724 7,407 2,650 6,758 1,564 79 68 10,802 18,447

2014 10,844 7,378 2,659 6,831 1,509 85 87 10,929 18,463

2015 10,941 7,607 2,772 7,022 1,609 84 87 11,025 19,096

2016 11,015 7,789 2,817 7,104 1,633 94 89 11,108 19,431

2017 11,160 7,767 2,829 7,089 1,631 104 100 11,264 19,416

2018 11,210 7,862 2,870 7,128 1,658 112 101 11,323 19,619

2019 11,268 8,022 2,943 7,210 1,722 104 103 11,373 20,000

2020 10,845 8,136 3,140 7,415 2,228 89 81 10,934 21,000

2021 10,849 8,545 3,286 7,621 2,324 91 84 10,940 21,860

2022 10,717 8,871 3,384 7,950 2,361 90 77 10,807 22,642

2023 10,680 9,282 3,558 8,117 2,499 92 96 10,772 23,551

2024 10,371 9,838 3,774 8,379 2,626 87 77 10,458 24,694

2025 10,364 10,200 3,952 8,703 2,623 93 84 10,457 25,562

2026 10,313 10,509 4,057 9,020 2,705 104 103 10,417 26,394

2027 10,103 10,821 4,440 9,430 2,862 99 80 10,202 27,633

2028 9,944 10,995 4,424 9,957 3,185 128 111 10,072 28,672

2029 9,766 10,992 4,429 10,138 3,185 121 127 9,887 28,870

2030 9,570 11,161 4,512 10,539 3,240 127 103 9,697 29,556

2031 9,590 11,427 4,672 10,743 3,314 124 109 9,714 30,265

2032 9,456 11,750 4,930 11,015 3,449 143 95 9,599 31,239

2033 9,445 12,075 5,196 11,339 3,656 116 107 9,562 32,372

2034 9,278 12,457 5,347 11,642 3,669 128 92 9,406 33,206

2035 8,743 13,003 5,705 12,062 3,905 109 108 8,852 34,782

Source: U.S. Energy Information Administration, Annual Energy Outlook 2011. 

Meanwhile, Table 2-13 and Figure 2-6 show increases for all types of natural gas drilling 

in the lower 48 states. Drilling in shale reservoirs is expected to rise most dramatically, about 

190 percent during the forecast period, while drilling in coalbed methane and tight sands 

reservoirs increase significantly, 61 percent and 138 percent, respectively. Despite the growth in 

drilling in unconventional reservoirs, EIA forecasts successful conventional natural gas wells to 

increase about 78 percent during this period. Offshore natural gas wells are also expected to 

increase during the next 25 years, but not to the degree of onshore drilling.
2-28

Figure 2-6 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2035

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

prices. Domestic crude oil production increases slightly during the forecast period, with much of 

the growth coming from onshore production in the lower 48 states. Alaskan oil production is 

forecast to decline from 2010 to a low of 99 million barrels in 2030, but rising above that level 

for the final five years of the forecast. Net imports of crude oil are forecast to decline slightly 

during the forecast period. Figure 2-7 depicts these trends graphically. All told, EIA forecasts 

total crude oil to decrease about 3 percent from 2010 to 2035.

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2010 2015 2020 2025 2030 2035

S

uccessful Wells

Crude Oil Conventional Natural Gas

Tight Sands Devonian Shale

Coalbed Methane
2-29

Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2010-2035

Domestic Production (million bbls)

Year

Total 

Domestic

Lower 48 

Onshore

Lower 48 

Offshore Alaska

Lower 48 

End of 

Year 

Reserves

Net 

Imports

Total 

Crude 

Supply 

(million 

bbls)

Lower 48 

Average 

Wellhead Price 

(2009 dollars 

per bbl)

2010 2,011 1,136 653 223 17,634 3,346 5,361 78.6

2011 1,993 1,212 566 215 17,955 3,331 5,352 84.0

2012 1,962 1,233 529 200 18,026 3,276 5,239 86.2

2013 2,037 1,251 592 194 18,694 3,259 5,296 88.6

2014 2,102 1,267 648 188 19,327 3,199 5,301 92.0

2015 2,122 1,283 660 179 19,690 3,177 5,299 95.0

2016 2,175 1,299 705 171 20,243 3,127 5,302 98.1

2017 2,218 1,320 735 163 20,720 3,075 5,293 101.0

2018 2,228 1,323 750 154 21,129 3,050 5,277 103.7

2019 2,235 1,343 746 147 21,449 3,029 5,264 105.9

2020 2,219 1,358 709 153 21,573 3,031 5,250 107.4

2021 2,216 1,373 680 163 21,730 3,049 5,265 108.8

2022 2,223 1,395 659 169 21,895 3,006 5,229 110.3

2023 2,201 1,418 622 161 21,921 2,994 5,196 112.0

2024 2,170 1,427 588 155 21,871 2,996 5,166 113.6

2025 2,146 1,431 566 149 21,883 3,010 5,155 115.2

2026 2,123 1,425 561 136 21,936 3,024 5,147 116.6

2027 2,114 1,415 573 125 22,032 3,018 5,131 117.8

2028 2,128 1,403 610 116 22,256 2,999 5,127 118.8

2029 2,120 1,399 614 107 22,301 2,988 5,108 119.3

2030 2,122 1,398 625 99 22,308 2,994 5,116 119.5

2031 2,145 1,391 641 114 22,392 2,977 5,122 119.6

2032 2,191 1,380 675 136 22,610 2,939 5,130 118.8

2033 2,208 1,365 691 152 22,637 2,935 5,143 119.1

2034 2,212 1,351 714 147 22,776 2,955 5,167 119.2

2035 2,170 1,330 698 142 22,651 3,007 5,177 119.5

Source: U.S. Energy Information Administration, Annual Energy Outlook 2011. Totals may not sum due to 

independent rounding.

Table 2-14 also shows forecasts of proved reserves in the lower 48 states. The reserves forecast 

shows steady growth from 2010 to 2035, an increase of 28 percent overall. This increment is 

larger than the forecast increase in production from the lower 48 states during this period, 8

percent, showing reserves are forecast to grow more rapidly than production. Table 2-14 also 
2-30

shows average wellhead prices increasing a total of 52 percent from 2010 to 2035, from $78.6

per barrel to $119.5 per barrel in 2008 dollar terms.

Figure 2-7 Forecast of Domestic Crude Oil Production and Net Imports, 2010-2035

Table 2-15 shows domestic natural gas production is forecast to increase about 24 percent 

from 2010 to 2035. Contrasted against the much higher growth in natural gas wells drilled as 

shown in Table 2-13, per well productivity is expected to continue its declining trend. 

Meanwhile, imports of natural gas via pipeline are expected to decline during the forecast period 

almost completely, from 2.33 tcf in 2010 to 0.04 in 2035 tcf. Imported LNG also decreases from 

0.41 tcf in 2010 to 0.14 tcf in 2035. Total supply, then, increases about 10 percent, from 24.08

tcf in 2010 to 26.57 tcf in 2035. 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2010 2015 2020 2025 2030 2035

Crude Oil (Million bbl)

Total Domestic Net Imports

Lower 48 Onshore Lower 48 Offshore

Alaska
2-31

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

Production Net Imports

Year

Dry Gas 

Production

Supplemental 

Natural Gas

Net 

Imports 

(Pipeline)

Net 

Imports 

(LNG)

Total 

Supply

Lower 48 

End of 

Year Dry 

Reserves

Average Lower 48 

Wellhead Price 

(2009 dollars per 

Mcf)

2010 21.28 0.07 2.33 0.41 24.08 263.9 4.08

2011 21.05 0.06 2.31 0.44 23.87 266.3 4.09

2012 21.27 0.06 2.17 0.47 23.98 269.1 4.09

2013 21.74 0.06 2.22 0.50 24.52 272.5 4.15

2014 22.03 0.06 2.26 0.45 24.80 276.6 4.16

2015 22.43 0.06 2.32 0.36 25.18 279.4 4.24

2016 22.47 0.06 2.26 0.36 25.16 282.4 4.30

2017 22.66 0.06 2.14 0.41 25.28 286.0 4.33

2018 22.92 0.06 2.00 0.43 25.40 289.2 4.37

2019 23.20 0.06 1.75 0.47 25.48 292.1 4.43

2020 23.43 0.06 1.40 0.50 25.40 293.6 4.59

2021 23.53 0.06 1.08 0.52 25.19 295.1 4.76

2022 23.70 0.06 0.89 0.49 25.14 296.7 4.90

2023 23.85 0.06 0.79 0.45 25.15 297.9 5.08

2024 23.86 0.06 0.77 0.39 25.08 298.4 5.27

2025 23.99 0.06 0.74 0.34 25.12 299.5 5.43

2026 24.06 0.06 0.71 0.27 25.10 300.8 5.54

2027 24.30 0.06 0.69 0.22 25.27 302.1 5.67

2028 24.59 0.06 0.67 0.14 25.47 304.4 5.74

2029 24.85 0.06 0.63 0.14 25.69 306.6 5.78

2030 25.11 0.06 0.63 0.14 25.94 308.5 5.82

2031 25.35 0.06 0.57 0.14 26.13 310.1 5.90

2032 25.57 0.06 0.50 0.14 26.27 311.4 6.01

2033 25.77 0.06 0.38 0.14 26.36 312.6 6.12

2034 26.01 0.06 0.23 0.14 26.44 313.4 6.24

2035 26.33 0.06 0.04 0.14 26.57 314.0 6.42

Source: U.S. Energy Information Administration, Annual Energy Outlook 2011. Totals may not sum due to 

independent rounding.

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 

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

2-8). 
2-32

Figure 2-8 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 2-9 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 2008. The costs are reported in 2008 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)
2-33

Figure 2-9 Finding Costs for FRS Companies, 1981-2008

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 2-8 and finding costs in Figure 2-9 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 2008 dollars on a barrel of oil equivalent basis. Total 

lifting costs are the sum of direct lifting costs and production taxes. Figure 2-10 depicts direct 

lifting cost trends from 1981 to 2008 for domestic and foreign production.

0

10

20

30

40

50

60

70

80

1981-19831986-19881991-19931996-19982001-20032006-2008

$2008/boe

U.S. Onshore U.S. Offshore Foreign
2-34

Figure 2-10 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2008 (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 2008, domestic lifting costs increased sharply, 

about $6 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 2008.

2.5.3 Operating and Equipment Costs

The EIA report, “Oil and Gas Lease Equipment and Operating Costs 1994 through 

2009”

2

, 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 

 

2 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/current/

coststudy.html> Accessed February 2, 2011.

0

2

4

6

8

10

12

1981198419871990199319961999200220052008

$2008/boe

Domestic Foreign
2-35

six regions (California, Mid-Continent, South Louisiana, South Texas, West Texas, and Rocky

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 2-11 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 2-11 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and 

Crude Oil Price (in 1976 dollars), 1976-2009

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.

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)
2-36

Figure 2-12 Natural Operating Costs and Equipment Costs Indices (1976=100) and 

Natural Gas Price, 1976-2009

Figure 2-12 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.

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 

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 ($/M

Mcf, 1976 Dollars)

Natural Gas Operating Costs

Natural Gas Equipment Costs

Natural Gas Price ($/Mcf, 1976 Dollars)
2-37

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 

As of 2007, there were 6,563 firms within the 211111 and 211112 NAICS codes, of 

which 6427 (98 percent) were considered small businesses (Table 2-16). Within NAICS 211111 

and 211112, large firms compose about 2 percent of the firms, but account for 59 percent of 

employment and generate about 80 percent of estimated receipts listed under the NAICS. 
2-38

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

NAICS NAICS Description

SBA Size 

Standard 

Small 

Firms Large Firms Total Firms

Number of Firms by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 500 6,329 95 6,424

211112 Natural Gas Liquid Extraction 500 98 41 139

213111 Drilling Oil and Gas Wells 500 2,010 49 2,059

486210 Pipeline Transportation of Natural Gas $7.0 million 61* 65* 126

Total Employment by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 500 55,622 77,664 133,286

211112 Natural Gas Liquid Extraction 500 1,875 6,648 8,523

213111 Drilling Oil and Gas Wells 500 36,652 69,774 106,426

486210 Pipeline Transportation of Natural Gas $7.0 million N/A* N/A* 24,683

Estimated Receipts by Firm Size ($1000)

211111 Crude Petroleum and Natural Gas Extraction 500 44,965,936 149,141,316 194,107,252

211112 Natural Gas Liquid Extraction 500 2,164,328 37,813,413 39,977,741

213111 Drilling Oil and Gas Wells 500 7,297,434 16,550,804 23,848,238

486210 Pipeline Transportation of Natural Gas $7.0 million N/A* N/A* 20,796,681

Note: *The counts of small and large firms in NAICS 486210 is based upon firms with less than $7.5 million in 

receipts, rather than the $7 million required by the SBA Size Standard. We used this value because U.S. Census 

reports firm counts for firms with receipts less than $7.5 million. **Employment and receipts could not be split 

between small and large businesses because of non-disclosure requirements faced by the U.S. Census Bureau.

Source: U.S. Census Bureau. 2010. “Number of Firms, Number of Establishments, Employment, Annual Payroll, 

and Estimated Receipts by Enterprise Receipt Size for the United States, All Industries: 2007.” 

<http://www.census.gov/econ/susb/>

The small and large firms within NAICS 21311 are similarly distributed, with large firms 

accounting for about 2 percent of firms, but 66 percent and 69 percent of employment and 

estimated receipts, respectively. 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.
2-39

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 2009. The overall trend shows a decline in total 

industry employment throughout the 1990s, hitting a low of 313,703 in 1999, but rebounding to a 

2008 peak of 511,805. 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.

Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-09

Year

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 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 30,469

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

Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2011 , 

<http://www.bls.gov/cew/>
2-40

Figure 2-13 Employment in Drilling of Oil and Natural Gas Wells (NAICS 213111), and 

Total Oil and Natural Gas Wells Drilled, 1990-2009

Figure 2-13 compares employment in Drilling of Oil and Natural Gas Wells (NAICS 

213111) with the total number of oil and natural gas wells drilled from 1990 to 2009. The figure 

depicts a strong positive correlation between employment in the sector with drilling activity. 

This correlation also holds throughout the period covered by the data.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Employment: Drilling of Oil and Natural Gas Wells (NAICS

213111)
2-41

Figure 2-14 Employment in Crude Petroleum and Natural Gas Extraction (NAICS 

211111) and Total Crude Oil and Natural Gas Production (boe), 1990-2009

Figure 2-14 compares employment in Crude Petroleum and Natural Gas Extraction 

(NAICS 211111) with total domestic oil and natural gas production from 1990 to 2009 in barrels 

of oil equivalent terms. While until 2003, employment in this sector and total production 

declined gradually, employment levels declined more rapidly. However, from 2004 to 2009 

employment in Extraction recovered, rising to levels similar to the early 1990s.

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

19901991199219931994199519961997199819992000200120022003200420052006200720082009

E

mployment

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Total Oil and Gas Production (boe)

Employment: Crude Petroleum and Natural Gas Extraction (NAICS 211111)

Total Oil and Gas Production (boe)
2-42

Figure 2-15 Employment in Natural Gas Liquid Extraction (NAICS 211112), 

Employment in Pipeline Transportation of Natural Gas (NAICS 486210), and Total 

Natural Gas Production, 1990-2009

Figure 2-15 depicts employment in Natural Gas Liquid Extraction (NAICS 211112), 

Employment in Pipeline Transportation of Natural Gas (NAICS 486210), and Total Natural Gas 

Production, 1990-2009. While total natural gas production has risen slightly over this time 

period, employment in natural gas pipeline transportation has steadily declined to almost half of 

its 1991 peak. Employment in natural gas liquid extraction declined from 1992 to a low in 2005, 

then rebounded slightly from 2006 to 2009. Overall, however, these trends depict these sectors 

becoming decreasingly labor intensive, unlike the trends depicted in Figure 2-13 and Figure 

2-14.

From 1990 to 2009, average wages for the oil and natural gas industry have increased. 

Table 2-18 and Figure 2-16 show real wages (in 2008 dollars) from 1990 to 2009 for the NAICS 

codes associated with the oil and natural gas industry.

0

10,000

20,000

30,000

40,000

50,000

60,000

19901991199219931994199519961997199819992000200120022003200420052006200720082009

Employment: Natural Gas Liquid Extraction (NAICS 211112)

Employment: Pipeline Trans. of Natural Gas (NAICS 486210)

Natural Gas Production (bcf)
2-43

Table 2-18 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2009 (2008 

dollars)

Year

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 

Operations 

(213112)

Pipeline 

Transportation 

of Crude Oil 

(486110)

Pipeline 

Transportation 

of Natural Gas 

(486210) Total

1990 71,143 66,751 42,215 45,862 68,044 61,568 59,460

1991 72,430 66,722 43,462 47,261 68,900 65,040 60,901

1992 76,406 68,846 43,510 48,912 74,233 67,120 64,226

1993 77,479 68,915 45,302 50,228 72,929 67,522 64,618

1994 79,176 70,875 44,577 50,158 76,136 68,516 64,941

1995 81,433 67,628 46,243 50,854 78,930 71,965 66,446

1996 84,211 68,896 48,872 52,824 76,841 76,378 68,391

1997 89,876 79,450 52,180 55,600 78,435 82,775 71,813

1998 93,227 89,948 53,051 57,578 79,089 84,176 73,722

1999 98,395 89,451 54,533 59,814 82,564 94,471 79,078

2000 109,744 112,091 60,862 60,594 81,097 130,630 86,818

2001 111,101 111,192 61,833 61,362 83,374 122,386 85,333

2002 109,957 103,653 62,196 59,927 87,500 91,550 82,233

2003 110,593 112,650 61,022 61,282 87,388 91,502 82,557

2004 121,117 118,311 63,021 62,471 93,585 93,684 86,526

2005 127,243 127,716 70,772 67,225 92,074 90,279 90,292

2006 138,150 133,433 74,023 70,266 91,708 98,691 94,925

2007 135,510 132,731 82,010 71,979 96,020 105,441 96,216

2008 144,542 125,126 81,961 74,021 101,772 99,215 99,106

2009 133,575 123,922 80,902 70,277 100,063 100,449 96,298

Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2011 , 

<http://www.bls.gov/cew/>

Employees in the NAICS 211 codes enjoy the highest average wages in the industry, while 

employees in the NAICS 213111 code have relatively lower wages. Average wages in natural 

gas pipeline transportation show the highest variation, with a rapid climb from 1990 to 2000, 

more than doubling in real terms. However, since 2000 wages have declined in the pipeline 

transportation sector, while wages have risen in the other NAICS.
2-44

Figure 2-16 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2009 ($2008)

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 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 firm-level 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 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

19901991199219931994199519961997199819992000200120022003200420052006200720082009

Average Wage (2008 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
2-45

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 

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 top 150 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 2010, only 137 companies are listed3. Table 2-19 lists selected statistics for 

 

3 Oil and Gas Journal. “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010.
2-46

the top 20 companies in 2010. The results presented in the table reflect relatively lower 

production and financial figures as a result of the economic recession of this period. 

Total earnings for the top 137 companies fell from 2008 to 2009 from $71 billion to $27 

billion, reflecting the weak economy. Revenues for these companies also fell 35 percent during 

this period. 69 percent of the firms posted net losses in 2009, compared to 46 percent one year 

earlier (Oil and Gas Journal, September 6, 2010).

The total worldwide liquids production for the 137 firms declined 0.5 percent to 2.8 

billion bbl, while total worldwide gas production increased about 3 percent to a total of 16.5 tcf 

(Oil and Gas Journal, September 6, 2010). Meanwhile, the 137 firms on the OGJ list increased 

both oil and natural gas production and reserves from 2008 to 2009. Domestic production of 

liquids increased about 7 percent to 1.1 billion bbl, and natural gas production increased to 10.1 

tcf. For context, the OGJ150 domestic crude production represents about 57 percent of total 

domestic production (1.9 billion bbl, according to EIA). The OGJ150 natural gas production 

represents about 54 percent of total domestic production (18.8 tcf, according to 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.
2-47

Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2010

Worldwide 

Production U.S. Production

Rank by 

Total 

Assets Company Employees

Total Assets 

($ millions)

Total 

Rev. ($ 

millions)

Net Inc.

($ 

millions)

Liquids 

(Million 

bbl)

Natural 

Gas 

(Bcf)

Liquids 

(Million 

bbl)

Natural 

Gas 

(Bcf)

Net 

Wells 

Drilled

1 ExxonMobil Corp. 102,700 233,323 310,586 19,280 725 2,383 112 566 466

2 Chevron Corp. 64,000 164,621 171,636 10,563 674 1,821 177 511 594

3 ConocoPhillips 30,000 152,588 152,840 4,858 341 1,906 153 850 692

4 Anadarko Petroleum Corp. 4,300 50,123 9,000 -103 88 817 63 817 630

5 Marathon Oil Corp. 28,855 47,052 54,139 1,463 90 351 23 146 115

6 Occidental Petroleum Corp. 10,100 44,229 15,531 2,915 179 338 99 232 260

7 XTO Energy Inc. 3,129 36,255 9,064 2,019 32 855 32 855 1,059

8 Chesapeake Energy Corp. 8,200 29,914 7,702 -5,805 12 835 12 835 1,003

9 Devon Energy Corp. 5,400 29,686 8,015 -2,479 72 966 43 743 521

10 Hess Corp. 13,300 29,465 29,569 740 107 270 26 39 48

11 Apache Corp. 3,452 28,186 8,615 -284 106 642 35 243 124

12 El Paso Corp. 4,991 22,505 4,631 -539 6 219 6 215 134

13 EOG Resources Inc. 2,100 18,119 14,787 547 29 617 26 422 652

14 Murphy Oil Corp. 8,369 12,756 18,918 838 48 68 6 20 3

15 Noble Energy Inc. 1,630 11,807 2,313 -131 29 285 17 145 540

16 Williams Cos. Inc. 4,801 9,682 2,219 400 0 3,435 0 3,435 488

17 Questar Corp. 2,468 8,898 3,054 393 4 169 4 169 194

18 Pioneer Nat. Resources Co. 1,888 8,867 1,712 -52 19 157 17 148 67

19 Plains Expl. & Prod. Co. 808 7,735 1,187 136 18 78 18 78 53

20 Petrohawk Energy Corp. 469 6,662 41,084 -1,025 2 174 2 174 162

Source: Oil and Gas Journal. “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010.

Notes: The source for employment figures is the American Business Directory.
2-48

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 136 companies in 2010 (Oil and Gas Journal, November 1, 2010). 

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 2009. 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 63 percent of the total pipeline mileage and 

transport about 54 percent of the volume of the industry (Table 2-21). Operating revenues of the 
2-49

top 20 companies equaled $11.5 billion, representing 60 percent of the total operating revenues 

for major and non-major companies. The top 20 companies also account for 64 percent of the 

net income of the industry.

Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2009

Rank Company

Transmission 

(miles)

Vol. trans 

for others 

(MMcf)

Op. Rev.

(thousand $)

Net 

Income

1 Natural Gas Pipeline Co of America 9,312 1,966,774 1,131,548 348,177

2 Dominion Transmission Inc. 3,452 609,193 831,773 212,365

3 Columbia Gas Transmission LLC 9,794 1,249,188 796,437 200,447

4 Panhandle Eastern Pipe Line Co. LP 5,894 675,616 377,563 196,825

5 Transcontinental Gas Pipe Line Co. LLC 9,362 2,453,295 1,158,665 192,830

6 Texas Eastern Transmission LP 9,314 1,667,593 870,812 179,781

7 Northern Natural Gas Co. 15,028 922,745 690,863 171,427

8 Florida Gas Transmission Co. LLC 4,852 821,297 520,641 164,792

9 Tennessee Gas Pipeline Co. 14,113 1,704,976 820,273 147,378

10 Southern Natural Gas Co. 7,563 867,901 510,500 137,460

11 El Paso Natural Gas Co. 10,235 1,493,213 592,503 126,000

12 Gas Transmission Northwest Corp. 1,356 809,206 216,526 122,850

13 Rockies Express Pipeline LLC 1,682 721,840 555,288 117,243

14 CenterPoint Energy Gas Transmission Co. 6,162 1,292,931 513,315 116,979

15 Colorado Interstate Gas Co. 4,200 839,184 384,517 108,483

16 Kern River Gas Transmission Co. 1,680 789,858 371,951 103,430

17 Trunkline LNG Co. LLC — — 134,150 101,920

18 Northwest Pipeline GP 3,895 817,832 434,379 99,340

19 Texas Gas Transmission LLC 5,881 1,006,906 361,406 91,575

20 Algonquin Gas Transmission LLC 1,128 388,366 237,291 82,472

TOTAL FOR TOP 20 124,903 21,097,914 11,510,401 3,021,774

TOTAL FOR ALL COMPANIES 198,381 38,793,532 18,934,674 4,724,456

Source: Oil and Gas Journal. “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow.” 

November 1, 2010.

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. This information is used in annual report to Congress, as well as is released to the 

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. 
2-50

For 2008, there are 27 companies in the FRS4 that accounted for 41 percent of total U.S. crude 

oil and NGL production, 43 percent of natural gas production, 77 percent of U.S. refining

capacity, and 0.2 percent of U.S. electricity net generation (U.S. EIA, 2010). 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 as 

well. 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 saw a decline from previous periods, as oil and 

natural gas prices declined significantly during the latter half of 2008.

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

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.

 

4 Alenco, Anadarko Petroleum Corporation, Apache Corporation, BP America, Inc., 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., WRB Refining LLC, and XTO 

Energy, Inc.
2-51

Table 2-23 shows in percentage terms the estimated return on investments for a variety of 

business lines, in 1998, 2003, and 2008, for FRS companies. For U.S. petroleum-related 

business activities, oil and natural gas production has remained the most profitable line of 

business relative to refining/marketing and pipelines, sustaining a return on investment greater 

than 10 percent for the three years evaluated. Returns to foreign oil and natural gas production 

rose above domestic production in 2008. Electric power generation and sales emerged in 2008 

as a highly profitable line of business for the FRS companies.

Table 2-23 Return on Investment for Lines of Business (all FRS), for 1998, 2003, and 

2008 (percent)

Line of Business 1998 2003 2008

Petroleum 10.8 13.4 12.0

 U.S. Petroleum 10 13.7 8.2

 Oil and Natural Gas Production 12.5 16.5 10.7

 Refining/Marketing 6.6 9.3 2.6

 Pipelines 6.7 11.5 2.4

 Foreign Petroleum 11.9 13.0 17.8

 Oil and Natural Gas Production 12.5 14.2 16.3

 Refining/Marketing 10.6 8.0 26.3

Downstream Natural Gas* - 8.8 5.1

Electric Power* - 5.2 181.4

Other Energy 7.1 2.8 -2.1

Non-energy 10.9 2.4 -5.3

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 2008

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) 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 2008, about 13 percent of the total paid to U.S. 

authorities.
2-52

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

Year

U.S. Federal, State, 

and Local Taxes Paid 

or Accrued Total Current Total Deferred

Total Income 

Tax Expense

Other NonIncome 

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

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System). 

The difference between total current taxes and U.S. federal, state, and local taxes in 

includes taxes and royalties paid to foreign countries. As can be seen in Table 2-24, foreign 

taxes paid far exceeds domestic taxes paid. Other non-income production taxes paid, which have 

risen almost three-fold between 1990 and 2008, include windfall profit and severance taxes, as 

well as other production-related taxes.
2-53

2.7 References

Andrews, et al. 2009. Unconventional Gas Shales: Development, Technology, and Policy Issues.

Congressional Research Service. R40894.

Argonne National Laboratory. 2009. Produced Water Volumes and Management Practices in the 

United States. ANL/EVS/R-09/1.

Hyne, N.J. 2001. Nontechnical Guide to Petroleum Geology, Exploration, Drilling and 

Production. Tulsa, OK: Penwell Books. 

Independent Petroleum Association of America. 2009. Profile of Independent Producers.

<http://www.ipaa.org/news/docs/IPAAProfile2009.pdf> Accessed March 30, 2011.

Manning, F.S. and R.E. Thompson. 1991. Oil Field Processing of Petroleum – Volume 3: 

Produced and Injection Waters. Tulsa, OK: Penn Well Books.

Oil and Gas Journal. “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil 

Profits Grow.” November 1, 2010.

Oil and Gas Journal. “OGJ150 Financial Results Down in '09; Production, Reserves Up.” 

September 6, 2010.

Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push 

Global Gas Processing Capacity Ahead in 2009.” June 7, 2010.

U.S. Energy Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial 

Link between Natural Gas Production and Its Transportation to Market. 

<http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngproc

ess.pdf> Accessed February 2, 2011.

U.S. Department of Energy. 2009. Modern Shale Gas Development in the United States: A 

Primer. <http://www.netl.doe.gov/technologies/oilgas/publications/EPreports/Shale_Gas_Primer_2009.pdf> Accessed March 30, 2011.

U.S. Energy Information Administration (U.S. EIA). 2010. Annual Energy Review (AER). 

<http://www.eia.doe.gov/emeu/aer/contents.html> 

U.S. Energy Information Administration (U.S. EIA). 2010. Oil and Gas Lease Equipment and 

Operating Costs 1994 through 2009 

<http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_

production/current/coststudy.html> Accessed March 30, 2011.
2-54

U.S. Energy Information Administration (U.S. EIA). 2010. Summary: U.S. Crude Oil, Natural 

Gas, and Natural Gas Liquids Proved Reserves 2009. 

<http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_re

serves/cr.html> Accessed March 30, 2011.

U.S. Energy Information Administration (U.S. EIA). 2010. Performance Profiles of Major 

Energy Producers 2008. <http://www.eia.gov/finance/performanceprofiles> Accessed 

March 30, 2011.

U.S. Energy Information Administration (U.S. EIA). 2011. Annual Energy Outlook 2011.

<http://www.eia.gov/forecasts/aeo> June 2, 2011.

U.S. Environmental Protection Agency (U.S. EPA), Office of Air Quality Planning and 

Standards. 1996. Economic Analysis of Air Pollution Regulations: Oil and Natural Gas 

Production.

<http://www.epa.gov/ttnecas1/regdata/IPs/Oil%20and%20NG%20Production%20and%2

0NG%20Transmission_IP.pdf> Accessed March 30, 2011.

U.S. Environmental Protection Agency (U.S. EPA). 2004. Impacts to Underground Sources of 

Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. EPA/816-R-04-

003.

U.S. Environmental Protection Agency. 2000. EPA Office of Compliance Sector Notebook 

Project: Profile of the Oil and Gas Extraction Industry. EPA/310-R-99-006.

<http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/oil.

html> Accessed March 30, 2011.
3-1

3 EMISSIONS AND ENGINEERING COSTS

3.1 Introduction

This section includes three sets of discussions for both the final NSPS and NESHAP 

Amendments:

 Emission Sources and Points

 Emissions Control Options

 Engineering Cost Analysis

3.2 Emissions Points, Controls, and Engineering Costs Analysis

This section discusses the emissions points and pollution control options for the final 

NSPS and NESHAP Amendments. This discussion of emissions points and control options is 

meant to assist the reader of the RIA in better understanding the economic impact analysis. 

However, we provide reference to the detailed technical memoranda prepared by the Office of 

Air Quality Planning and Standards (OAQPS) for the reader interested in a greater level of detail. 

This section also presents the engineering cost analysis, which provides a cost basis for the 

energy system, employment, and small business analyses.

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 final rules. To estimate VOC emissions from the oil and 

gas sector, we modified the emissions estimate for the crude oil and natural gas sector in the 

2008 National Emissions Inventory (NEI). During this review, EPA identified VOC emissions 

from natural gas sources which are likely relatively under-represented in the NEI, natural gas 

well completions primarily. Crude oil and natural gas sector VOC emissions estimated in the 

2008 NEI total approximately 1.76 million tons. Of these emissions, the NEI identifies about 21 

thousand tons emitted from natural gas well completion processes. We substituted the estimates 

of VOC emissions from natural gas well completions estimated as part of the engineering 

analysis (249,000 tons, which is discussed in more detail in the next section), bringing the total 

estimated VOC emissions from the crude oil and natural gas sector to about 1.99 million tons 

VOC.
3-2

The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009 (published April 

2011) estimates 2009 methane emissions from Petroleum and Natural Gas Systems (not 

including petroleum refineries and petroleum transportation) to be 251.55 (MMtCO2-e). It is 

important to note that the 2009 emissions estimates from well completions and recompletions 

exclude a significant number of wells completed in tight sand plays and the Marcellus Shale, due 

to availability of data when the 2009 Inventory was developed. The estimate in this analysis 

includes an adjustment for tight sand plays and the Marcellus Shale, and such an adjustment is 

also being considered as a planned improvement in next year's Inventory. This adjustment would 

increase the 2009 Inventory estimate by about 80 MMtCO2-e to approximately 330 MMtCO2-e.

3.2.1 Emission Points and Pollution Controls assessed in the RIA

3.2.1.1 NSPS Emission Points and Pollution Controls

A series of emissions controls were evaluated as part of the NSPS review. This section 

provides a basic description of possible 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 Technical Support Document (TSD) which is 

published in the Docket. The chapters are also referenced below. 

Centrifugal and reciprocating compressors (UPDATED REFERENCE TO BE ADDED): 

There are many locations throughout the oil and gas sector where compression of natural gas is 

required to move the gas along the pipeline. This is accomplished by compressors powered by 

combustion turbines, reciprocating internal combustion engines, or electric motors. Turbinepowered compressors use a small portion of the natural gas that they compress to fuel the 

turbine. The turbine operates a centrifugal compressor, which compresses and pumps the natural 

gas through the pipeline. Sometimes an electric motor is used to turn a centrifugal compressor. 

This type of compression does not require the use of any of the natural gas from the pipeline, but 

it does require a source of electricity. Reciprocating spark ignition engines are also used to 

power many compressors, referred to as reciprocating compressors, since they compress gas 

using pistons that are driven by the engine. Like combustion turbines, these engines are fueled 

by natural gas from the pipeline. 
3-3

Both centrifugal and reciprocating compressors are sources of VOC emissions, and EPA 

evaluated compressors for coverage under the NSPS. Centrifugal compressors require seals 

around the rotating shaft to prevent gases from escaping where the shaft exits the compressor 

casing. The seals in some compressors use oil, which is circulated under high pressure between 

three rings around the compressor shaft, forming a barrier against the compressed gas leakage. 

Very little gas escapes through the oil barrier, but considerable gas is absorbed by the oil. Seal 

oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and 

recirculated, and the gas is commonly vented to the atmosphere. These are commonly called 

“wet” seals. An alternative to a wet seal system is the mechanical dry seal system. This seal 

system does not use any circulating seal oil. Dry seals operate mechanically under the opposing 

force created by hydrodynamic grooves and static pressure. Fugitive VOC is emitted from dry 

seals around the compressor shaft. The use of dry gas seals substantially reduces emissions. In 

addition, they significantly reduce operating costs and enhance compressor efficiency.

Reciprocating compressors in the natural gas industry leak natural gas during normal 

operation. The highest volume of gas loss is associated with piston rod packing systems. 

Packing systems are used to maintain a tight seal around the piston rod, preventing the gas 

compressed to high pressure in the compressor cylinder from leaking, while allowing the rod to 

move freely. Monitoring and replacing compressor rod packing systems on a regular basis can 

greatly reduce VOC emissions. 

Equipment leaks (UPDATED REFERENCE TO BE ADDED): Equipment leaks are fugitive 

emissions emanating from valves, pump seals, flanges, compressor seals, pressure relief valves, 

open-ended lines, and other process and operation components. There are several potential 

reasons for equipment leak emissions. Components such as pumps, valves, pressure relief 

valves, flanges, agitators, and compressors are potential sources that can leak due to seal failure. 

Other sources, such as open-ended lines, and sampling connections may leak for reasons other 

than faulty seals. In addition, corrosion of welded connections, flanges, and valves may also be a 

cause of equipment leak emissions. Because of the large number of valves, pumps, and other 

components within an oil and gas production, processing, and transmission facility, equipment 

leaks of volatile emissions from these components can be significant. Natural gas processing 
3-4

plants, especially those using refrigerated absorption, and transmission stations tend to have a 

large number of components. These types of equipment also exist at production sites and gas 

transmission/compressor stations. While the number of components at individual 

transmission/compressor stations is relatively smaller than at processing plants, collectively there 

are many components that can result in significant emissions. Therefore, EPA evaluated NSPS 

for equipment leaks for facilities in the production segment of the industry, which includes 

everything from the wellhead to the point that the gas enters the processing plant or refinery. 

Pneumatic controllers (UPDATED REFERENCE TO BE ADDED): Pneumatic controllers are 

automated instruments used for maintaining a process condition such as liquid level, pressure, 

delta-pressure, and temperature. Pneumatic controllers are widely used in the oil and natural gas 

sector. In many situations, the pneumatic controllers used in the oil and gas sector make use of 

the available high-pressure natural gas to regulate temperature, pressure, liquid level, and flow 

rate across all areas of the industry. In these “gas-driven” pneumatic controllers, natural gas may

be released with every valve movement 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. 

Gas-driven pneumatic controllers are typically characterized as “high-bleed” or “low-bleed”, 

where a high-bleed device releases at least 6 cubic feet of gas per hour. EPA evaluated the 

impact of requiring low-bleed controllers. 

Storage vessels (UPDATED REFERENCE TO BE ADDED): Crude oil, condensate, and 

produced water are typically stored in fixed-roof storage vessels. Some vessels used for storing 

produced water may be open-top tanks. These vessels, which are operated at or near 

atmospheric pressure conditions, are typically located at tank batteries. A tank battery refers to 

the collection of process equipment used to separate, treat, and store crude oil, condensate, 

natural gas, and produced water. The extracted products from productions wells enter the tank 

battery through the production header, which may collect product from many wells. Emissions 

from storage vessels are a result of working, breathing, and flash losses. Working losses occur 

due to the emptying and filling of storage tanks. Breathing losses are the release of gas 
3-5

associated with daily temperature fluctuations and other equilibrium effects. Flash losses occur 

when a liquid with entrained gases is transferred from a vessel with higher pressure to a vessel 

with lower pressure, thus allowing entrained gases or a portion of the liquid to vaporize or flash. 

In the oil and natural gas production segment, flashing losses occur when live crude oils or 

condensates flow into a storage tank from a processing vessel operated at a higher pressure. 

Typically, the larger the pressure drop, the more flashing emission will occur in the storage 

stage. The two ways of controlling tanks with significant emissions would be to install a vapor 

recovery unit (VRU) and recover all the vapors from the tanks or to route the emissions from the 

tanks to a control device. 

Well completions (UPDATED REFERENCE TO BE ADDED): In the oil and natural gas 

sector, well completions contain multi-phase processes with various sources of emissions. One 

specific emission source during completion activities is the 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 refracturing an existing well. Well completions include multiple steps after the well bore hole has 

reached the target depth. These steps include inserting and cementing-in well casing, perforating 

the casing at one or more producing horizons, and often hydraulically fracturing one or more 

zones in the reservoir to stimulate production.

Hydraulic fracturing is one completion step for improving gas production where the 

reservoir rock is fractured with very high pressure fluid, typically water emulsion with proppant 

(generally sand) that “props open” the fractures after fluid pressure is reduced. Emissions are a 

result of the backflow of the fracture fluids and reservoir gas at high velocity necessary to lift 

excess proppant to the surface. This multi-phase mixture is often directed to a surface 

impoundment where natural gas and VOC vapors escape to the atmosphere during the collection 

of water, sand, and hydrocarbon liquids. As the fracture fluids are depleted, the backflow 

eventually contains more volume of natural gas from the formation. Thus, we estimate 

completions involving hydraulic fracturing vent substantially more natural gas, approximately

230 times more, than completions not involving hydraulic fracturing. Specifically, we estimate 

that uncontrolled well completion emissions for a hydraulically fractured well are about 23 tons 
3-6

of VOC, where emissions for a conventional gas well completion are around 0.1 ton VOC. Our 

data indicate that hydraulically fractured wells have higher emissions but we believe some wells 

that are not hydraulically fractured may have higher emissions than our data show, or in some 

cases, hydraulically fractured wells could have lower emissions that our data show. 

Reduced emission completions, which are sometimes referred to as “green completions” 

or “flareless completions,” use equipment at the well site to capture and treat gas so it can be 

directed into the sales line and avoid emissions from venting. Equipment required to conduct a 

reduced emissions completion may include tankage, special gas-liquid-sand separator traps, and 

gas dehydration. Equipment costs associated with reduced emission completions will vary from 

well to well. Based on information provided to the EPA Natural Gas STAR program, 90 percent 

of gas potentially vented during a completion can be recovered during a reduced emission 

completion.

3.2.1.2 NESHAP Emission Points and Pollution Controls

A series of emissions controls will be required under the final NESHAP Amendments. 

This section provides a basic description of potential sources of emissions and the controls 

intended for each to facilitate the reader’s understanding of the economic impacts and 

subsequent benefits analysis section. The reader who is interested in more technical detail on the 

engineering and cost basis of the analysis is referred to the relevant technical memos which are 

published in the Docket. The memos are also referenced below.

Glycol dehydrators5: Once natural gas has been separated from any liquid materials or products 

(e.g., crude oil, condensate, or produced water), residual entrained water is removed from the 

natural gas by dehydration. Dehydration is necessary because water vapor may form hydrates, 

which are ice-like structures, and can cause corrosion in or plug equipment lines. The most 

widely used natural gas dehydration processes are glycol dehydration and solid desiccant 

dehydration. Solid desiccant dehydration, which is typically only used for lower throughputs,

 

5 Memorandum. Brown, Heather, EC/R Incorporated, to Bruce Moore and Greg Nizich, EPA/OAQPS/SPPD/FIG. 

Oil and Natural Gas Production MACT and Natural Gas Transmission and Storage MACT - Glycol Dehydrators: 

Impacts of MACT Review Options. July 17,2011 UPDATED REFERENCE TO BE ADDED.
3-7

uses adsorption to remove water and is not a source of HAP emissions. Glycol dehydration is an 

absorption process in which a liquid absorbent, glycol, directly contacts the natural gas stream 

and absorbs any entrained water vapor in a contact tower or absorption column. The rich glycol, 

which has absorbed water vapor from the natural gas stream, leaves the bottom of the absorption 

column and is directed either to (1) a gas condensate glycol separator (GCG separator or flash 

tank) and then a reboiler or (2) directly to a reboiler where the water is boiled off of the rich 

glycol. The regenerated glycol (lean glycol) is circulated, by pump, into the absorption tower. 

The vapor generated in the reboiler is directed to the reboiler vent. The reboiler vent is a source 

of HAP emissions. In the glycol contact tower, glycol not only absorbs water but also absorbs 

selected hydrocarbons, including BTEX and n-hexane. The hydrocarbons are boiled off along 

with the water in the reboiler and vented to the atmosphere or to a control device. 

The most commonly used control device is a condenser. Condensers not only reduce 

emissions, but also recover condensable hydrocarbon vapors that can be recovered and sold. In 

addition, the dry non-condensable off-gas from the condenser may be used as fuel or recycled 

into the production process or directed to a flare, incinerator, or other combustion device.

If present, the GCG separator (flash tank) is also a potential source of HAP emissions. 

Some glycol dehydration units use flash tanks prior to the reboiler to separate entrained gases, 

primarily methane and ethane from the glycol. The flash tank off-gases are typically recovered 

as fuel or recycled to the natural gas production header. However, the flash tank may also be 

vented directly to the atmosphere. Flash tanks typically enhance the reboiler condenser’s 

emission reduction efficiency by reducing the concentration of non-condensable gases present in 

the stream prior to being introduced into the condenser.

Storage vessels: Please see the discussion of storage vessels in the NSPS section above.

3.2.2 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 in order to comply with the final NSPS 

and NESHAP Amendments. A detailed discussion of the methodology used to estimate cost 

impacts is presented in series of memos published in the Docket as part of the TSD.
3-8

3.2.2.1 NSPS Sources

Table 3-1 shows the emissions sources, points, and controls analyzed for the final rule. 

The final NSPS contains reduced emission completion (REC) and completion combustion 

requirements for a subset of newly drilled natural gas wells that are hydraulically fractured. The 

NSPS also requires a subset of wells that are recompleted using hydraulic fracturing to 

implement RECs. The NSPS requires emissions reductions from reciprocating compressors at 

gathering and boosting stations and processing plants. The NSPS also requires emissions 

reductions from centrifugal compressors at processing plants. Finally, the NSPS requires 

emissions reductions from pneumatic controllers at oil and gas production facilities and 

reductions from high throughput storage vessels.
3-9

Table 3-1 Emissions Sources, Points, and Controls Included in the Final NSPS 

Emissions Sources and Points Emissions Control Final NSPS

Well Completions of Post-NSPS Wells 

Hydraulically Fractured Gas Wells that Meet Criteria for 

Reduced Emissions Completion (REC) REC X

Hydraulically Fractured Gas Wells that Do Not Meet 

Criteria for REC Combustion X

Conventional Gas Wells Combustion

Oil Wells Combustion

Well Recompletions

Hydraulically Fractured Gas Wells (post-NSPS wells) REC X

Hydraulically Fractured Gas Wells (pre-NSPS wells) REC X

Conventional Gas Wells Combustion

Oil Wells Combustion

Equipment Leaks

Well Pads NSPS Subpart VV

Gathering and Boosting Stations NSPS Subpart VV

Processing Plants NSPS Subpart VVa X

Transmission Compressor Stations NSPS Subpart VV

Reciprocating Compressors

Well Pads Annual Monitoring/ 

Maintenance (AMM)

Gathering/Boosting Stations AMM X

Processing Plants AMM X

Transmission Compressor Stations AMM

Underground Storage Facilities AMM

Centrifugal Compressors

Processing Plants Dry Seals/Route to Process or 

Control X

Transmission Compressor Stations Dry Seals/Route to Process or 

Control

Pneumatic Controllers -

Oil and Gas Production Low Bleed/Route to Process X

Natural Gas Transmission and Storage Low Bleed/Route to Process

Storage Vessels

High Throughput 95% control X

Low Throughput 95% control

Table 3-2 summarizes the unit level capital and annualized costs for the evaluated NSPS 

emissions sources and points. The detailed description of costs estimates is provided in the 
3-10

series of technical memos included in the TSD in the document, as referenced in Section 3.2.1 of 

this RIA. The table also includes the projected number of affected units. Four issues are 

important to note on Table 3-2: the approach to annualizing costs, the projection of affected units 

in the baseline; that capital and annualized costs are equated for RECs; and additional natural gas 

and hydrocarbon condensates that would otherwise be emitted to the environment are recovered

from several control options evaluated in the NSPS review.

First, engineering capital costs were annualized using a 7 percent interest rate. However, 

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 momentarily)

 Reciprocating compressors: 3 years

 Centrifugal compressors and pneumatic controllers: 10 years

 Storage vessels: 15 years

 Equipment leaks: 5 to 10 years, depending on specific control

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. For example, a 15 year project would require 

replacing reciprocating compressor-related controls five times, but only require a single 

installation of controls on storage vessels. 

Second, the projected number of affected units is the number of units that our analysis 

shows would be affected in 2015, the analysis year. The projected number of affected units 

accounts for estimates of the adoption of controls in absence of Federal regulation. While the 

procedures used to estimate adoption in absence of Federal regulation are presented in detail 

within the TSD, because REC requirements provide a significant component of the estimated 
3-11

emissions reductions and engineering compliance costs, it is worthwhile to go into some detail 

on the projected number of RECs within the RIA. We use EIA projections consistent with the 

Annual Energy Outlook 2011 to estimate the number of natural gas well completions with 

hydraulic fracturing in 2015, assuming that successful wells drilled in coal bed methane, shale, 

and tight sands used hydraulic fracturing. Based on this assumption, we estimate that 11,403 

wells were successfully completed and used hydraulic fracturing. To approximate the number of 

wells that would not be required to perform RECs because of the absence of sufficient 

infrastructure, we draw upon the distinction in EIA analysis between exploratory and 

developmental wells. We assume exploratory wells do not have sufficient access to 

infrastructure to perform a REC and are exempt from the REC requirement. These 446 wells are 

removed from the REC estimate and are assumed to combust emissions using pit flares.

The number of hydraulically fractured recompletions of existing wells was approximated 

using assumptions found in Subpart W’s TSD6and applied to well count data found in the 

proprietary HPDI®database. The underlying assumption is that wells found in coal bed 

methane, shale, and tight sand formations require re-fracture, on average, every 10 years. In 

other words, one percent of the total wells classified as being performed with hydraulic 

fracturing would perform a recompletion in any given year. Natural gas well recompletions 

performed without hydraulic fracturing were based only on 2008 well data from HPDI®. 

The number of completions and recompletions already controlling emissions in absence 

of a Federal regulation was estimated based on existing State regulations that require applicable 

control measures for completions and workovers in specific geographic locations. Based on this 

criterion, 15 percent of natural gas completions with hydraulic fracturing and 15 percent of 

existing natural gas workovers with hydraulic fracturing are estimated to be controlled by either 

flare or REC in absence of Federal regulations. Completions and recompletions without 

hydraulic fracturing were assumed as having no controls in absence of a Federal regulation. 

Following these procedures leads to an estimate of 9,313 completions of new wells and 1,205

recompletions of existing wells that will require a REC under the final NSPS in 2015. However, 

 

6 U.S. Environmental Protection Agency (U.S. EPA). 2010. Greenhouse Gas Emissions Reporting From the 

Petroleum and Natural Gas Industry: Background Technical Support Document. Climate Change Division. 

Washington, DC.
3-12

because the pressure level for some wells may be insufficient to successfully perform an REC, 

these wells will be required to combust emissions, rather than implement an REC. EPA analysis 

shows about 10 percent of the wells that otherwise would be required by the NSPS to perform an 

REC will combust emissions. In summary, we expect 8,382 completions of new wells and 1,085 

recompletions of existing wells will ultimately require a REC, after consideration of state 

regulations and pressure levels. 

As just mentioned, the baseline for the impacts analysis of our NSPS for natural gas well 

completions takes into account reduced emission completions conducted pursuant to state 

regulations covering these operations. However, based on public comments and reports to EPA's 

Natural Gas Star program, EPA acknowledges that some producers conduct well completions 

using REC techniques voluntarily. However, EPA normally does not account for voluntary

actions in baseline emissions estimates when we analyze potential impacts of our regulatory

actions, since there is no assurance that such voluntary emission reduction measures will 

continue in the future. As such, emissions reductions obtained from RECs implemented 

voluntarily are not reflected in our baseline emissions estimates.

It also should be noted that natural gas prices are stochastic and, historically, there have 

been periods where prices have increased or decreased rapidly. These price changes would be 

expected to affect adoption of emission reduction technologies in absence of regulation, 

particularly control measures such as RECs that capture emission significantly over short periods 

of time.

The completion requirements (combustion and RECs) are essentially one-shot events; the 

emissions controls are applied over the course of a well completion, which will typically range 

over a few days to a couple of weeks. After this relatively short period of time, there is no 

continuing control requirement, unless the well is again completed at a later date, sometimes 

years later. Consequently, we counted these requirements as as recurring costs, implicitly

treating the number of completions taking place in 2015 as representative of a typical year.

Fourth, for annualized cost, we present two figures, the annualized costs with revenues 

from additional natural gas and condensate recovery and annualized costs without additional 
3-13

revenues this product recovery. Several emission controls for the NSPS capture VOC emissions 

that otherwise would be vented to the atmosphere. Since methane is co-emitted with VOC, a 

large proportion of the averted methane emissions can be directed into natural gas production 

streams and sold. 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. RECs also capture saleable condensates that would otherwise be lost to the 

environment. The engineering analysis assumes a REC will capture 34 barrels of condensate per 

REC and that the value of this condensate is $70/barrel. 

The $4/Mcf is below the 2015 EIA-forecasted wellhead price, $4.22/Mcf in 2008 dollars. 

The $4/Mcf payment rate does not reflect any taxes or tax credits that might apply to producers 

implementing the control technologies. 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. A $1/Mcf change in the wellhead price causes a change 

in estimated engineering compliance costs of about $82 million in 2008 dollars. 

As will be seen in subsequent analysis, the estimate of revenues from additional product 

recovery is critical to the economic impact analysis. However, before discussing this assumption 

in more depth, it is important to further develop the engineering estimates to contextualize the 

discussion and to provide insight into why, if it is profitable to capture natural gas emissions that 

are otherwise vented, producers may not already be doing so.

Table 3-3 presents the estimated nationwide compliance costs, emissions reductions, and 

VOC reduction cost-effectiveness broken down by emissions sources and points for those 

sources and points evaluated in the NSPS analysis. The annual reporting and recordkeeping 

costs for the final NSPS are estimated at $7.1 million per year and are included in Table 3-3. 

As can be seen from Table 3-3 controls associated with well completions and 

recompletions of hydraulically fractured wells provide the largest potential for emissions 

reductions from evaluated emissions sources and points, as well as present the most significant 

compliance costs if revenue from additional natural gas recovery is not included. Emissions 

reductions from conventional natural gas wells and crude oil wells are clearly not as significant 

as the potential from hydraulically fractured wells, as was discussed in Section 3.2.1.1.
3-14

Several evaluated emissions sources and points are estimated to have net financial 

savings when including the revenue from additional natural gas recovery. Table 3-4 presents the 

estimated engineering costs, emissions reductions, and VOC reduction cost-effectiveness for the 

final NSPS evaluated in the RIA. The resulting total national annualized cost impact of the final

NSPS rule is estimated at $340 million per year without considering revenues from additional 

natural gas recovery. Annual costs for the final NSPS are estimated at -$18 million when 

revenue from additional natural gas recovery is included. All figures are in 2008 dollars.
3-15

Table 3-2 Summary of Capital and Annualized Costs per Unit for NSPS Emissions 

Points

Sources/Emissions Point

Projected No. of 

Affected Units

Per Unit Annualized Cost (2008$)

Capital Costs 

(2008$)

Without 

Revenues from

Additional 

Product 

Recovery

With 

Revenues from

Additional 

Product 

Recovery

Well Completions

Hydraulically Fractured Gas Wells 

that Meet Criteria for REC 8,382 $33,237 $33,237 -$1,543

Hydraulically Fractured Gas Wells 

that Do Not Meet Criteria for REC 

(Completion Combustion) 1,498 $3,523 $3,523 $3,523

Conventional Gas Wells 7,694 $3,523 $3,523 $3,523

Oil Wells 12,193 $3,523 $3,523 $3,523

Well Recompletions

Hydraulically Fractured Gas Wells 

(existing wells) 1,085 $33,237 $33,237 -$1,543

Conventional Gas Wells 42,342 $3,523 $3,523 $3,523

Oil Wells 39,375 $3,523 $3,523 $3,523

Equipment Leaks

Well Pads 4,774 $68,970 $23,413 $21,871

Gathering and Boosting Stations 275 $239,494 $57,063 $51,174

Processing Plants 29 $8,041 $12,273 $8,474

Transmission Compressor Stations 107 $96,542 $25,350 $25,350

Reciprocating Compressors

Well Pads 6,000 $6,480 $3,701 $3,664

Gathering/Boosting Stations 210 $5,346 $2,456 $870

Processing Plants 209 $4,050 $2,090 -$2,227

Transmission Compressor Stations 20 $5,346 $2,456 $2,456

Underground Storage Facilities 4 $7,290 $3,349 $3,349

Centrifugal Compressors

Processing Plants 13 $22,000 $3,132 -$50,106

Transmission Compressor Stations 14 $75,000 $10,678 -$77,622

Pneumatic Controllers -

Oil and Gas Production 13,632 $165 $23 -$1,519

Natural Gas Trans. and Storage 67 $165 $23 $23

Storage Vessels

High Throughput 304 $65,243 $19,864 $19,281

Low Throughput 17,086 $65,243 $19,864 $19,281
3-16

Table 3-3 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-Effectiveness by 

Emissions Sources and Points, NSPS, 2015

Source/Emissions Point Emissions Control

Nationwide Annualized Costs 

(2008$)

Nationwide Emissions 

Reductions (tons/year)

VOC Emissions Reduction 

Cost-Effectiveness 

(2008$/ton) 

Without 

Addl. 

Revenues 

With Addl. 

Revenues VOC Methane HAP

Without 

Addl. 

Revenues 

With Addl. 

Revenues

Well Completions (New Wells)

Hydraulically Fractured Gas Wells REC $278,598,165 -$12,931,447 180,217 1,235,207 13,093 $1,546 -$72

Hydraulically Fractured Gas Wells Combustion $5,276,674 $5,276,674 32,204 220,726 2,340 $164 $164

Conventional Gas Wells Combustion $27,104,761 $27,104,761 857 5,875 62 $31,619 $31,619

Oil Wells Combustion $42,954,036 $42,954,036 83 88 0 $520,580 $520,580

Well Recompletions (Existing Wells)

Hydraulically Fractured Gas Wells (existing 

wells) REC $36,045,804 -$1,673,106 23,317 159,815 1,694 $1,546 -$72

Conventional Gas Wells Combustion $149,164,257 $149,164,257 316 2,165 23 $472,227 $472,227

Oil Wells Combustion $138,711,979 $138,711,979 44 47 0 $3,134,431 $3,134,431

Equipment Leaks

Well Pads NSPS Subpart VV $111,773,662 $104,412,154 10,646 38,287 401 $10,499 $9,808

Gathering and Boosting Stations NSPS Subpart VV $15,692,325 $14,072,850 2,340 8,415 88 $6,705 $6,013

Processing Plants NSPS Subpart VVa $355,917 $245,746 132 475 5 $2,693 $1,860

Transmission Compressor Stations NSPS Subpart VV $2,712,450 $2,712,450 261 9,427 8 $10,389 $10,389

Reciprocating Compressors

Well Pads

Annual Monitoring/ 

Maintenance (AMM) $22,204,209 $21,984,763 263 947 10 $84,379 $83,545

Gathering/Boosting Stations AMM $515,764 $182,597 400 1,437 15 $1,291 $457

Processing Plants AMM $436,806 -$465,354 1,082 3,892 41 $404 -$430

Transmission Compressor Stations AMM $49,120 $49,120 12 434 0 $4,093 $4,093

Underground Storage Facilities AMM $13,396 $13,396 2 87 0 $5,542 $5,542
3-17

Table 3-3 (continued) Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction CostEffectiveness by Emissions Sources and Points, NSPS, 2015

Source/Emissions Point Emissions Control

Nationwide Annualized Costs 

(2008$)

Nationwide Emissions 

Reductions (tons/year)

VOC Emissions Reduction 

Cost-Effectiveness 

(2008$/ton) 

Without 

Addl. 

Revenues 

With Addl. 

Revenues VOC Methane HAP

Without 

Addl. 

Revenues 

With Addl. 

Revenues

Centrifugal Compressors

Processing Plants

Dry Seals/Route to 

Process or Control $40,720 -$651,377 254 2,810 9 $161 -$2,569

Transmission Compressor Stations

Dry Seals/Route to 

Process or Control $149,496 -$1,086,704 43 1,546 1 $3,495 -$25,405

Pneumatic Controllers -

Oil and Gas Production

Low Bleed/Route to 

Process $320,071 -$20,699,918 25,210 90,685 952 $13 -$821

Natural Gas Trans. and Storage

Low Bleed/Route to 

Process $1,541 $1,541 6 212 0 $262 $262

Storage Vessels

High Throughput 95% control $6,031,787 $5,855,032 29,654 6,490 876 $203 $197

Low Throughput 95% control $339,388,204 $329,442,792 12,900 2,824 381 $26,308 $25,537
3-18

Table 3-4 Engineering Compliance Costs, NSPS (2008$)

Final NSPS

Capital Costs $344,724,611

Annualized Costs

 Without Revenues from Additional Natural 

 Gas Product Recovery $334,927,549

With Revenues from Additional Natural Gas

 Product Recovery -$17,607,568

VOC Reductions (tons per year) 292,532

Methane Reduction (tons per year) 1,721,763

HAP Reductions (tons per year) 19,028

VOC Reduction Cost-Effectiveness ($/ton without 

additional product revenues)

$1,144

VOC Reduction Cost-Effectiveness ($/ton with 

additional product revenues)

-$60

Note: the VOC reduction cost-effectiveness estimate assumes there is no benefit to reducing methane and HAP, 

which is not the case. We however present the per ton costs of reducing the single pollutant for illustrative 

purposes. As product prices can increase or decrease rapidly, the estimated engineering compliance costs can 

vary when revenue from additional product recovery is included. There is also geographic variability in 

wellhead prices, which can also influence estimated engineering costs. A $1/Mcf change in the wellhead price 

causes a change in estimated engineering compliance costs of about $82 million in 2008 dollars. The annualized 

cost estimates also includes reporting and recordkeeping costs of $7.1 million.

As the price assumption is very influential on estimated impacts, we performed a simple 

sensitivity analysis of the influence of the assumed wellhead price paid to natural gas producers 

on the overall engineering costs estimate of the final NSPS. Figure 3-1 plots the annualized 

costs after revenues from natural gas product recovery have been incorporated (in millions of 

2008 dollars) as a function of the assumed price of natural gas paid to producers at the wellhead 

for the recovered natural gas (represented by the sloped, dotted line). The vertical solid lines in 

the figure represent the natural gas price assumed in the RIA ($4.00/Mcf) for 2015 and the 2015 

forecast by EIA in the 2011 Annual Energy Outlook ($4.22/Mcf) in 2008 dollars.
3-19

Figure 3-1 Sensitivity Analysis of Final NSPS Annualized Costs after Revenues from 

Additional Product Recovery are Included

As shown in Table 3-4, at the assumed $4/Mcf, the annualized costs are estimated at -$18

million. At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy Outlook, the 

annualized costs are estimated at about -$36 million, which would approximately double the 

estimate of net cost savings of the final NSPS. As indicated by this difference, EPA has chosen a 

relatively conservative assumption (leading to an estimate of few savings and higher net costs) 

for the engineering costs analysis. The natural gas price at which the final NSPS breaks-even is 

around $3.79/Mcf. As mentioned earlier, a $1/Mcf change in the wellhead natural gas price 

leads to about a $82 million change in the annualized engineering costs of the final NSPS. 

Consequently, annualized engineering costs estimates would increase to about $65 million under 

a $3/Mcf price or decrease to about -$100 million under a $5/Mcf price. 

It is additionally helpful to put the quantity of natural gas and condensate potentially

recovered in the context of domestic production levels. To do so, it is necessary to make two 

adjustments. First, not all emissions reductions can be directed into production streams to be 

$(300)

$(200)

$(100)

$-

$100 

$200 

$- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 

Annualized Costs after 

Product Recovery

($ Millions) Natural Gas

Price ($/Mcf)

in 2015

RIA Assumed 

Price in 2015 

($4.00/Mcf)

EIA Forecast 

Price in 2015

($4.22/Mcf)

Annualized

Costs as 

Functionof

NaturalGas

Price

Assumption
3-20

ultimately consumed by final consumers. Several controls require combustion of the natural gas 

rather than capture and direction into product streams. After adjusting estimates of national 

emissions reductions in Table 3-3 for these combustion-type controls, the final NSPS is

estimated to capture about 82 bcf of natural gas and 320,000 barrels of condensate. Estimates of 

unit-level and nation-level product recovery are presented in Section 3 of the RIA. Note that 

completion-related requirements for new and existing wells generate all the condensate recovery

for the NSPS. For natural gas recovery, RECs contribute about 77 bcf (or 93 percent). 
3-21

Table 3-5 Estimates of Control Unit-level and National Level Natural Gas and Condensate Recovery, NSPS, 2015 

Projected No. 

of Affected 

Units

Unit-level Product Recovery Total Product Recovery

Source/ Emissions Points Emissions Control

Natural Gas 

Savings 

(Mcf/unit)

Condensate 

(bbl/unit)

Natural Gas 

Savings (Mcf)

Condensate 

(bbl)

Well Completions

Hydraulically Fractured Gas Wells REC 8,382 8,100 34 67,895,051 284,992 

Hydraulically Fractured Gas Wells Combustion 1,498 0 0 0 0 

Hydraulically Fractured Gas Wells 

(existing wells) REC 1,085 8,100 34 8,784,450 36,873 

Equipment Leaks

Processing Plants NSPS Subpart VVa 29 950 0 27,548 0 

Reciprocating Compressors

Gathering/Boosting Stations Annual Monitoring/ 

Maintenance (AMM) 210 397 0 83,370 0 

Processing Plants AMM 209 1,079 0 225,540 0 

Centrifugal Compressors

Processing Plants Dry Seals/Route to Process 

or Ctrl 13 11,527 0 149,853 0 

Pneumatic Controllers -

Oil and Gas Production Low Bleed/Route to 

Process 13,632 386 0 5,254,997 0 

Processing Plants Instrument Air 15 871 0 13,064 0 

Storage Vessels

High Throughput 95% control 304 146 0 44,189 0 

Total (Mcf) 82,478,062 321,865 
3-22

A second adjustment to the natural gas quantities is necessary to account for 

nonhydrocarbon gases removed and gas that reinjected to repressurize wells, vented or flared, or 

consumed in production processes. Generally, wellhead production is metered at or near the 

wellhead and payments to producers are based on these metered values. In most cases, the 

natural gas is minimally processed at the meter and still contains impurities or co-products that 

must be processed out of the natural gas at processing plants. This means that the engineering 

cost estimates of revenues from additional natural gas recovery arising from controls 

implemented at the wellhead include payment for the impurities, such as the VOC and HAP 

content of the unprocessed natural gas. According to EIA, in 2009 the gross withdrawal of 

natural gas totaled 26,013 bcf, but 20,580 bcf was ultimately considered dry production (these 

figures exclude EIA estimates of flared and vented natural gas). Using these numbers, we apply 

a factor of 0.79 (20,580 bcf divided by 26,013 bcf) to the adjusted sums in the previous 

paragraph to estimate the volume of gas that is captured by controls that may ultimately be

consumed by final consumers.

After making these adjustments, we estimate that the final NSPS will potentially recover 

about 65 bcf of natural gas that will ultimately be consumed by natural gas consumers.7 EIA 

forecasts that the domestic dry natural gas production in 2015 will be 20,080 bcf. Consequently, 

the final NSPS may recover production representing about 0.3 percent of domestic dry natural 

gas production predicted in 2015. These estimates, however, do not account for adjustments 

producers might make, once compliance costs and potential revenues from additional natural gas 

recovery factor into economic decision-making. Also, as discussed in the previous paragraph, 

these estimates do not include the nonhydrocarbon gases removed, natural gas reinjected to 

repressurize wells, and natural gas consumed in production processes, and therefore will be 

lower than the estimates of the gross natural gas captured by implementing controls.

Clearly, this discussion raises the question as to why, if emissions can be reduced 

profitably using environmental controls, more producers are not adopting the controls in their 

own economic self-interest. This question is made clear when examining simple estimates of the 

rate of return to installing emissions controls that, using the engineering compliance costs 

 

7 To convert U.S. short tons of methane to a cubic foot measure, we use the conversion factor of 48.04 Mcf per U.S. 

short ton.
3-23

estimates, the estimates of natural gas product recovery, and assumed product prices (Table 3-6). 

The rates of return presented in are for evaluated controls where estimated revenues from 

additional product recovery exceed the costs. The rate of return is calculated using the simple 

formula:

estimated revenues

rateof return 1 100

estimated costs

 

       .

Table 3-6 Simple Rate of Return Estimate for Final NSPS Controls

Emission Point Control Option Rate of Return

New Completions of Hydraulically Fractured Wells Reduced Emissions 

Completions 4.6%

Re-completions of Existing Hydraulically Fractured 

Wells 

Reduced Emissions 

Completions 4.6%

Reciprocating Compressors (Processing Plants) Replace Packing 106.5%

Centrifigal Compressors (Processing Plants) Dry Seals/Route to 

Control 1,599.7%

Pneumatic Controllers (Oil and Gas Production ) Low Bleed/Route to 

Process 6,467.2%

Overall NSPS Low Bleed 5.4%

Note: The table presents only control options where estimated revenues from natural gas product recovery exceeds 

estimated annualized engineering costs

Recall from Table 2-23 in the Industry Profile, that EIA estimates an industry-level rate 

of return on investments for various segments of the oil and natural gas industry. While the 

numbers varies greatly over time because of industry and economic factors, EIA estimates a 10.7 

percent rate of return on investments for oil and natural gas production in 2008. While this 

amount is higher than the 4.6 percent rate estimated for RECs, it is significantly lower than the 

rate of returns estimated for other controls anticipated to have net savings.

Assuming financially rational producers, standard economic theory suggests that all oil 

and natural gas firms would incorporate all cost-effective improvements, which they are aware 

of, without government intervention. The cost analysis of this RIA nevertheless is based on the 

observation that emission reductions that appear to be profitable in our analysis have not been 

generally adopted. One possible explanation may be the difference between the average profit 

margin garnered by productive capital and the environmental capital where the primary
3-24

motivation for installing environmental capital would be to mitigate the emission of pollutants 

and confer social benefits as discussed in Chapter 4. 

Another explanation for why there appear to be negative cost control technologies that 

are not generally adopted is imperfect information. If emissions from the oil and natural gas 

sector are not well understood, firms may underestimate the potential financial returns to 

capturing emissions. Quantifying emissions is difficult and has been done in relatively few 

studies. Recently, however, advances in infrared imagery have made it possible to affordably 

visualize, if not quantify, methane emissions from any source using a handheld camera. This 

infrared camera has increased awareness within industry and among environmental groups and 

the public at large about the large number of emissions sources and possible scale of emissions 

from oil and natural gas production activities. Since, as discussed in the TSD chapter 

(UPDATED REFERENCE TO BE ADDED) referenced above, 15 percent of new natural gas

well completions with hydraulic fracturing and 15 percent of existing natural gas well 

recompletions with hydraulic fracturing are estimated to be controlled by either flare or REC in 

the baseline, it is unlikely that a lack of information will be a significant reason for these 

emission points to not be addressed in the absence of Federal regulation in 2015. However, for 

other emission points, a lack of information, or the cost associated with doing a feasibility study

of potential emission capture technologies, may continue to prevent firms from adopting these 

improvements in the absence of regulation.

Another explanation is the cost associated with irreversibility associated with 

implementing these environmental controls are not reflected in the engineering cost estimates 

above. Due to the high volatility of natural gas prices, it is important to recognize the value of 

flexibility taken away from firms when requiring them to install and use a particular emissions 

capture technology. If a firm has not adopted the technology on its own, then a regulation 

mandating its use means the firm loses the option to postpone investment in the technology in 

order to pursue alternative investments today, and the option to suspend use of the technology if 

it becomes unprofitable in the future. Therefore, the full cost of the regulation to the firm is the 

engineering cost and the lost option value minus the revenues from the sale of the additional 

recovered product. In the absence of quantitative estimates of this option value for each 

emission point affected by the NSPS and NESHAP improvements, the costs presented in this 
3-25

RIA may underestimate the full costs faced by the affected firms. With these caveats in mind, 

EPA believes it is analytically appropriate to analyze costs and economic impacts costs presented 

in Table 3-2 and Table 3-3 using the additional product recovery and associated revenues. 

3.2.2.2 NESHAP Sources

As discussed in Section 3.2.1.2, EPA examined three emissions points as part of its 

analysis for the final NESHAP Amendments. Unlike the controls for the final NSPS, the 

controls evaluated under the final NESHAP Amendments do not direct significant quantities of 

natural gas that would otherwise be flared or vented into the production stream. Table 3-7 shows 

the projected number of controls required, estimated unit-level capital and annualized costs, and 

estimated total annualized costs. The table also shows estimated emissions reductions for HAP, 

VOC, and methane, as well as a cost-effectiveness estimate for HAP reduction, based upon 

annualized engineering costs.
3-26

Table 3-7 Summary of Estimated Capital and Annual Costs, Emissions Reductions, 

and HAP Reduction Cost-Effectiveness for Final NESHAP Amendments

Source/Emissions 

Point

Projected 

No. of 

Controls 

Required

Emission Reductions 

(tons per year)

Capital 

Costs/ 

Unit 

(2008$)

Annualized 

Cost/Unit 

(2008$)

Total 

Annualized 

Cost 

(2008$) HAP VOC Methane

HAP 

Reduction 

CostEffectiveness 

(2008$/ton)

Production - Small 

Glycol Dehydrators 74 35,518 22,396 1,657,300 505 915 316 3,284

Transmission - 

Small Glycol 

Dehydrators 7 19,399 18,957 132,700 164 298 103 808

Storage Vessels 674 65,243 19,864 13,388,039 589 7,812 4,364 22,722

Reporting and 

Recordkeeping N/A N/A N/A 2,368,627 N/A N/A N/A N/A

Total 755 17,546,667 1,258 9,024 4,783 13,945

Note: Totals may not sum due to independent rounding.

Under the final NESHAP Amendments, about 750 controls will be required, costing a total 

of $18 million annually (Table 3-7). We include reporting and recordkeeping costs as a unique 

line item showing these costs for the entire set of final amendments. These controls will reduce 

HAP emissions by about 1,300 tons, VOC emissions by about 9,000 tons, and methane by about 

4,800 tons. The cost-per-ton to reduce HAP emissions is estimated at about $14,000 per ton. All 

figures are in 2008 dollars.

3.3 References 

Oil and Gas Journal. “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil 

Profits Grow.” November 1, 2010.

Oil and Gas Journal. “OGJ150.” September 21, 2009.

Oil and Gas Journal. “OGJ150 Financial Results Down in '09; Production, Reserves Up.” 

September 6, 2010.

Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push 

Global Gas Processing Capacity Ahead in 2009.” June 7, 2010.
4-1

4 BENEFITS OF EMISSIONS REDUCTIONS

4.1 Introduction

The final Oil and Natural Gas NSPS and NESHAP Amendments are expected to result in 

significant reductions in existing emissions and prevent new emissions from expansions of the 

industry. While we expect that these avoided emissions will result in improvements in air 

quality and reduce health effects associated with exposure to HAP, ozone, and fine particulate 

matter (PM2.5), we have determined that quantification of those health benefits cannot be 

accomplished for this rule in a defensible way. This is not to imply that there are no health 

benefits of the rules; 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. 

For the final NSPS, the HAP and climate benefits can be considered “co-benefits”, and for the 

final NESHAP Amendments, the ozone and PM2.5 health benefits and climate benefits can be 

considered “co-benefits”. These co-benefits occur because the control technologies used to 

reduce VOC emissions also reduce emissions of HAP and methane.

The final NSPS is anticipated to prevent 19,000 tons of HAP, 290,000 tons of VOC, and 

1.7 million tons of methane from new sources, while the final NESHAP Amendments is 

anticipated reduce 1,300 tons of HAP, 9,000 tons of VOC, and 4,800 tons of methane from 

existing sourcesThe specific control technologies for the final NSPS are anticipated to have 

minor secondary disbenefits, including an increase of 1.1 million tons of carbon dioxide (CO2), 

630 tons of nitrogen oxides NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total 

hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. 

Both rules would have additional emission changes associated with the energy system impacts. 

The net CO2-equivalent emission reductions are 31 million metric tons for the final NSPS and 

90,000 metric tons for the final NESHAP. As described in the subsequent sections, these 

pollutants are associated with substantial health effects, welfare effects, and climate effects. 

With the data available, we are not able to provide a credible benefits estimates for any of these 

pollutants for these rules, due to the differences in the locations of oil and natural gas emission 

points relative to existing information, and the highly localized nature of air quality responses 

associated with HAP and VOC reductions. In addition, we do not yet have interagency agreed 
4-2

upon valuation estimates for greenhouse gases other than CO2 that could be used to value the 

climate co-benefits associated with avoiding methane emissions. Instead, we provide a 

qualitative assessment of the benefits and co-benefits as well as a break-even analysis in Chapter 

6 of this RIA. A break-even analysis answers the question, “What would the benefits need to be 

for the benefits to exceed the costs.” While a break-even approach is not equivalent to a benefits 

analysis, we feel the results are illustrative, particularly in the context of previous benefit per ton 

estimates.

4.2 Direct Emission Reductions from the Oil and Natural Gas Rules

As described in Section 2 of this RIA, oil and natural gas operations in the U.S. include a 

variety of emission points for VOC and HAP including wells, 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 these rules, 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 these rules might affect attainment status without air quality modeling data.8 

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. In short, 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 

 

8 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. 
4-3

of other regulations that result in specific costs of control and emission reductions. However, 

some costs and benefits estimated in this RIA account for the same air quality improvements as 

estimated in an illustrative NAAQS RIA. 

By contrast, the emission reductions for this rule are from a specific class of wellcharacterized sources. In general, EPA is more confident in the magnitude and location of the 

emission reductions for these rules. It is important to note that emission reductions anticipated 

from these rules do not result in emission increases elsewhere (other than potential energy

disbenefits). 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. EPA remains forward 

looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result 

does not issue updated RIAs for existing NAAQS that retroactively update the baseline for 

NAAQS implementation. For more information on the relationship between the NAAQS and 

rules such as analyzed here, please see Section 1.2.4 of the SO2 NAAQS RIA (U.S. EPA, 

2010d). Table 4-1 shows the direct emission reductions anticipated for these rules. 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 are primarily at a global scale, but methane is also a 

precursor to ozone, a short-lived climate forcer that exhibits spatial and temporal variability. 

Table 4-1 Direct Emission Reductions Associated with the Oil and Natural Gas NSPS 

and NESHAP Amendments in 2015 (short tons per year) 

Pollutant NESHAP Amendments NSPS

HAP 1,258 19,028

VOC 9,024 292,532

Methane 4,783 1,721,763
4-4

4.3 Secondary Impacts Analysis for Oil and Gas Rules

The control techniques to avert leaks and vents of VOC and HAP are associated with 

several types of secondary impacts, which may partially offset the direct benefits of this rule. In 

this RIA, we refer to the secondary impacts associated with the specific control techniques as 

“producer-side” impacts.9 For example, by combusting VOC and HAP, combustion increases 

emissions of carbon monoxide, NOx, particulate matter and other pollutants. In addition to 

“producer-side” impacts, these control techniques would also allow additional natural gas 

recovery, which would contribute to additional combustion of the recovered natural gas and 

ultimately a shift in the national fuel mix. We refer to the secondary impacts associated with the 

combustion of the recovered natural gas as “consumer-side” secondary impacts. We provide a 

conceptual diagram of both categories of secondary impacts in Figure 4-1.

 

9

In previous RIAs, we have also referred to these impacts as energy disbenefits.
4-5

Figure 4-1 Conceptual Diagram of Secondary Impacts from Oil and Gas NSPS and 

NESHAP Amendments

Table 4-2 shows the estimated secondary “producer-side” impacts. Relative to the direct 

emission reductions anticipated from these rules, the magnitude of these secondary air pollutant 

impacts is small. Because the geographic distribution of these emissions from the oil and gas 

sector is not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009), we are 

unable to monetize the PM2.5 disbenefits associated with the producer-side secondary impacts. In 

addition, it is not appropriate to monetize the disbenefits associated with the increased CO2

emissions without monetizing the averted methane emissions because the overall global warming 

potential (GWP) is actually lower. Through the combustion process, methane emissions are 
4-6

converted to CO2 emissions, which have 21 times less global warming potential compared to 

methane (IPCC, 2007).10 

Table 4-2 Secondary Air Pollutant Impacts Associated with Control Techniques by 

Emissions Category (“Producer-Side”) (tons per year)

Emissions Category CO2 NOx PM CO THC

Total Completions of New Wells (NSPS) 1,120,184 576 14.7 3,133 1,185

 New Well Completions: REC/Combust 271,801 140 0.0 760 288

 New Well Completions: Combust 848,382 436 14.7 2,373 898

Total Recompletions of Existing Wells (NSPS) 109,732 56 1.3 307 116

 Existing Well Recompletions: REC/Combust 35,183 18 0.0 98 37

 Existing Well Recompletions: Combust 74,549 38 1.3 208 79

Pneumatic Controllers (NSPS) 22 1.0 2.6 0.0 0.0

Storage Vessels (NSPS) 856 0.5 0.0 2.4 0.9

Total NSPS 1,230,794 634 19 3,442 1,302

Total NESHAP (Storage Vessels) 5,543 2.9 0.1 16 6

For the “consumer-side” impacts associated with the NSPS, we modeled the impact of 

the final NSPS on the national fuel mix and associated CO2-equivalent emissions (Table 4-3).

11

 

We provide the modeled results of the “consumer-side” CO2-equivalent emissions in Table 7-12. 

The modeled results indicate that through a slight shift in the national fuel mix, the CO2-

equivalent emissions across the energy sector would increase by 0.54 million metric tons for the 

final NSPS in 2015. This is in addition to the other secondary impacts and directly avoided 

emissions, for a total 31 million metric tons of CO2-equivalent emissions averted as shown in 

Table 4-4. We estimate small increases other emissions (e.g., NOx, PM, SOx) associated with 

the additional national gas consumption or the change in the national fuel mix.

 

10 This issue is discussed in more detail in Section 4.7 of this RIA.

11 A full discussion of the energy modeling is available in Section 7 of this RIA. 
4-7

Table 4-3 Modeled Changes in Energy-related CO2-equivalent Emissions by Fuel Type 

for the Final Oil and Gas NSPS in 2015 (million metric tons) ("Consumer-Side")1

Fuel Type NSPS (million metric tons change in CO2-e)

Petroleum -0.44

Natural Gas 2.49

Coal -1.51

Other 0.00

Total modeled Change in CO2-e Emissions 0.54

1 These estimates reflect the modeled change in CO2-e emissions using NEMS shown in Table 7-12. Totals may not 

sum due to independent rounding.

Table 4-4 Total Change in CO2-equivalent Emissions including Secondary Impacts for 

the Final Oil and Gas NSPS in 2015 (million metric tons)

Emissions Source NSPS 

NESHAP

Amendments

Averted CO2-e Emissions from New Sources1-32.8 -0.09

Additional CO2-e Emissions from Combustion and Supplemental Energy 

(Producer-side)2 1.1 0.01

Total Modeled Change in Energy-related CO2-e Emissions (Consumerside)3 0.54 --

Total Change in CO2-e Emissions after Adjustment for Secondary 

Impacts -31.1 -0.09

1 This estimate reflects the GWP of the avoided methane emissions from new sources shown in Table 4-1 and has 

been converted from short tons to metric tons.

2 This estimate represents the secondary producer-side impacts associated with additional CO2 emissions from 

combustion and from additional electricity requirements shown in Table 4-2 and has been converted from short tons 

to metric tons.

3This estimate reflects the modeled change in the energy–related consumer-side impacts shown in Table 4-3. 

Totals may not sum due to independent rounding.

Based on these analyses, the net impact of both the direct and secondary impacts of these 

rules would be an improvement in ambient air quality, which would reduce exposure to various 

harmful pollutants, improve visibility impairment, reduce vegetation damage, and reduce 

potency of greenhouse gas emissions. Table 4-5 provides a summary of the direct and secondary

emissions changes for each rule.
4-8

Table 4-5 Summary of Emissions Changes for the Final Oil and Gas NSPS and 

NESHAP in 2015 (short tons per year)

Pollutant NSPS NESHAP 

Amendments

Change in Direct Emissions

VOC -290,000 -9,000

Methane -1,700,000 -4,800

HAP -19,000 -1,300

Change in Secondary Emissions (Producer-Side)

CO2 1,200,000 5,500

NOx 630 2.9

PM 19.0 0.1

CO 3,400 16

THC 1,300 6.0

Change in Secondary Emissions (ConsumerSide) CO2-e 600,000 N/A

Net Change in CO2-equivalent Emissions CO2-e

-34,000,000

(≈31,000,000 metric 

tons)

-95,000

(≈90,000 metric 

tons)

Note: Totals may not sum due to independent rounding.

4.4 Hazardous Air Pollutant (HAP) Benefits

Even though emissions of air toxics from all sources in the U.S. declined by approximately

42 percent since 1990, 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).12 The levels of air toxics to which 

people are exposed vary depending on where they live and work and the kinds of activities in 

which they engage. In order to identify and prioritize air toxics, emission source types and 

locations that are of greatest potential concern, U.S. EPA conducts the NATA. 13 The most 

recent NATA was conducted for calendar year 2005 and was released in March 2011. NATA 

includes four steps:

 

12 The 2005 NATA is available on the Internet at http://www.epa.gov/ttn/atw/nata2005/.

13 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/
4-9

1) Compiling a national emissions inventory of air toxics emissions from outdoor sources

2) Estimating ambient and exposure concentrations of air toxics across the United States

3) Estimating population exposures across the United States

4) Characterizing potential public health risk due to inhalation of air toxics including both 

cancer and noncancer effects

Based on the 2005 NATA, EPA estimates that about 5 percent of census tracts 

nationwide have increased cancer risks greater than 100 in a million. The average national 

cancer risk is about 50 in a million. Nationwide, the key pollutants that contribute most to the 

overall cancer risks are formaldehyde and benzene. 14,15 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,16 subchronic,17 or acute18 inhalation 

exposures 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. 

 

14 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.

15 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.

16 Chronic exposure is defined in the glossary of the Integrated Risk Information (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).

17 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).

18 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.
4-10

Figure 4-2 and Figure 4-3 depict the 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 are more than double acrolein emissions on a national 

basis, according to 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 toxic than 

acetaldehyde. 19 Thus, it is important to account for the toxicity and exposure, as well as the mass 

of the targeted emissions. 

Figure 4-2 Estimated Chronic Census Tract Carcinogenic Risk from HAP exposure 

from outdoor sources (2005 NATA)

 

19 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.
4-11

Figure 4-3 Estimated Chronic Census Tract Noncancer (Respiratory) Risk from HAP 

exposure from outdoor sources (2005 NATA)

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 these rules. In a 

few previous analyses of the benefits of reductions in HAP, EPA has quantified the benefits of 

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

those analyses, EPA relied on unit risk factors (URF) developed through risk assessment 

procedures.20 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. 

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 

 

20The unit risk factor is a quantitative estimate of the carcinogenic potency of a pollutant, often expressed as the 

probability of contracting cancer from a 70-year lifetime continuous exposure to a concentration of one μg/m3of 

a pollutant.
4-12

benefits of the regulation. While we used high-end risk estimates in past analyses, advice from 

the EPA’s Science Advisory Board (SAB) recommended that we avoid using high-end estimates 

in benefit analyses (U.S. EPA-SAB, 2002). Since this time, EPA has continued to develop better 

methods for analyzing the benefits of reductions in HAP.

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

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

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

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

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

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

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

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

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

In 2009, EPA convened a workshop to address the inherent complexities, limitations, and 

uncertainties in current methods to quantify the benefits of reducing HAP. Recommendations 

from this workshop included identifying research priorities, focusing on susceptible and 

vulnerable populations, and improving dose-response relationships (Gwinn et al., 2011). 

In summary, monetization of the benefits of reductions in cancer incidences requires 

several important inputs, including central estimates of cancer risks, estimates of exposure to 

carcinogenic HAP, and estimates of the value of an avoided case of cancer (fatal and non-fatal). 

Due to methodology and data limitations, we did not attempt to monetize the health benefits of 

reductions in HAP in this analysis. Instead, we provide a qualitative analysis of the health effects 

associated with the HAP anticipated to be reduced by these rules and we summarize the results 

of the residual risk assessment for the Risk and Technology Review (RTR). EPA remains 

committed to improving methods for estimating HAP benefits by continuing to explore 

additional concepts of benefits, including changes in the distribution of risk. 

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

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

distribution, or storage tanks. Emissions of eight HAP make up a large percentage the total HAP 
4-13

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, 2011a). 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. These rules combined are anticipated to avoid or reduce 20,000 tons of 

HAP per year. With the data available, it was not possible to estimate the tons of each individual 

HAP that would be reduced. 

EPA conducted a residual risk assessment for the NESHAP rule (U.S. EPA, 2012). The 

results for oil and gas production indicate that maximum lifetime individual cancer risks could be 

10 in-a-million for existing sources with a cancer incidence of 0.02 before and after controls. 

Approximately 120,000 people are estimated to have cancer risks at or above 1-in-1 million for 

oil and gas production. For existing natural gas transmission and storage, the maximum 

individual cancer risk decreases from 20-in-a-million with a cancer incidence of 0.001. 

Approximately 2,200 people are estimated to have cancer risks at or above 1-in-1 million for oil 

and gas transmission and storage. Benzene is the primary cancer risk driver. The results also 

indicate that significant noncancer impacts from existing sources are unlikely, especially after 

controls. It is important to note that the magnitude of the HAP emissions avoided by new 

sources with the NSPS are much higher than the HAP emissions reduced from existing sources 

with the NESHAP.

4.4.1 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.21,22,23 EPA states in its IRIS database that data indicate a causal 

 

21 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.

22 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. 

23 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.
4-14

relationship between benzene exposure and acute lymphocytic leukemia and suggest a 

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

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

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

Services (DHHS) has characterized benzene as a known human carcinogen.24,25 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.26,27 The most sensitive 

noncancer effect observed in humans, based on current data, is the depression of the absolute 

lymphocyte count in blood.28,29 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.30,31,32,33 EPA’s IRIS program has not 

yet evaluated these new data.

 

24 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.

25 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens 

available at: http://ntp.niehs.nih.gov/go/16183.

26 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197.

27 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541-554.

28 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.

29 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.

30 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. 

31 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.

32 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels 

of Benzene. Science 306: 1774-1776.

33 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.
4-15

4.4.2 Toluene34

Under the 2005 Guidelines for Carcinogen Risk Assessment, there is inadequate 

information to assess the carcinogenic potential of toluene because studies of humans chronically

exposed to toluene are inconclusive, toluene was not carcinogenic in adequate inhalation cancer 

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

leukemia were reported in a lifetime rat oral bioassay.

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

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

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

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

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

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

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

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

irritation, dizziness, headaches, and difficulty with sleep.

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

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

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

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.

4.4.3 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 

 

34 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>.
4-16

the eyes and skin in humans.35 No information is available on the chronic (long-term), 

reproductive, developmental, or carcinogenic effects of carbonyl sulfide in humans. Carbonyl 

sulfide has not undergone a complete evaluation and determination under U.S. EPA's IRIS 

program for evidence of human carcinogenic potential.36

4.4.4 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.37,38 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).39,40 The NTP (1999) carried out a chronic inhalation 

 

35 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.

36 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.

37 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.

38 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.

39International 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.
4-17

bioassay in mice and rats and found clear evidence of carcinogenic activity in male rats and some 

evidence in female rats, based on increased incidences of renal tubule adenoma or carcinoma in 

male rats and renal tubule adenoma in females. NTP (1999) also noted increases in the incidence 

of testicular adenoma in male rats. Increased incidences of lung alveolar/bronchiolar adenoma or 

carcinoma were observed in male mice and liver hepatocellular adenoma or carcinoma in female 

mice, which provided some evidence of carcinogenic activity in male and female mice (NTP, 

1999). IARC (2000) classified ethylbenzene as Group 2B, possibly carcinogenic to humans, 

based on the NTP studies.

4.4.5 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.41 Other reported effects include labored 

breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and 

kidneys.42 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.43 EPA has classified mixed xylenes in Category D, not classifiable 

with respect to human carcinogenicity.

4.4.6 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 

 

40 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.

41 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.

42 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.

43 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.
4-18

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

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

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

effects, neurophysiological changes and neuropathological effects upon inhalation exposure to nhexane. Under the Guidelines for Carcinogen Risk Assessment (U.S. EPA, 2005), the database 

for n-hexane is considered inadequate to assess human carcinogenic potential, therefore the EPA 

has classified hexane in Group D, not classifiable as to human carcinogenicity.

44

4.4.7 Other Air Toxics

In addition to the compounds described above, other toxic compounds might be affected 

by these rules, including hydrogen sulfide (H2S). Information regarding the health effects of 

those compounds can be found in EPA’s IRIS database.45

4.5 VOC

4.5.1 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 carbon dioxide (CO2) rather than to PM, but a portion of VOC 

emission contributes to ambient PM2.5 levels as organic carbon aerosols (U.S. EPA, 2009a). 

Therefore, reducing these emissions would reduce PM2.5 formation, human exposure to PM2.5, 

and the incidence of PM2.5-related health effects. However, we have not quantified the PM2.5-

related benefits in this analysis. Analysis of organic carbon measurements suggest only a

fraction of secondarily formed organic carbon aerosols are of anthropogenic origin. The current 

state of the science of secondary organic carbon aerosol formation indicates that anthropogenic 

VOC contribution to secondary organic carbon aerosol is often lower than the biogenic (natural) 

contribution. Given that a fraction of secondarily formed organic carbon aerosols is from 

anthropogenic VOC emissions and the extremely small amount of VOC emissions from this 

sector relative to the entire VOC inventory it is unlikely this sector has a large contribution to 

 

44 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>.

45 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris
4-19

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 time limitations under the court-ordered schedule and data limitations regarding 

locations of new well completions, we were unable to perform air quality modeling for this rule. 

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. 

4.5.2 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, 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, hospital admissions, and respiratory

morbidity such as asthma attacks, acute and chronic bronchitis, hospital and ER visits, work loss 

days, restricted activity days, and respiratory symptoms. Although EPA has not quantified these 

effects in previous benefits analyses, the scientific literature suggests that exposure to PM2.5 is 

also associated with adverse effects on birth weight, pre-term births, pulmonary function, other 

cardiovascular effects, and other respiratory effects (U.S. EPA, 2009a). 

EPA assumes that all fine particles, regardless of their chemical composition, are equally

potent in causing premature mortality because the scientific evidence is not yet sufficient to 

allow differentiation of effect estimates by particle type (U.S. EPA, 2009a). Based on our 

review of the current body of scientific literature, EPA estimates PM-related 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. 
4-20

Previous studies have estimated the monetized benefits-per-ton of reducing VOC 

emissions associated with effect that those emissions have on ambient PM2.5 levels and the health 

effects associated with PM2.5 exposure (Fann, Fulcher, and Hubbell, 2009). 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 City Study, a large cohort 

epidemiology study in the Eastern U.S.), an analysis year of 2015, and a 3 percent discount rate. 

Based on the methodology from Fann, Fulcher, and Hubbell (2009), we converted their 

estimates to 2008$ and applied EPA’s current VSL estimate.46 After these adjustments, the range 

of values increases to $680 to $7,000 per ton of VOC reduced for Laden et al. (2006). Using 

alternate assumptions regarding the relationship between PM2.5 exposure and premature mortality

from empirical studies and supplied by experts (Pope et al., 2002; Laden et al., 2006; Roman et 

al., 2008), additional benefit-per-ton estimates are available from this dataset, as shown in Table 

4-6. EPA generally presents a range of benefits estimates derived from Pope et al. (2002) to 

Laden et al. (2006) because they are both well-designed and peer reviewed studies, and EPA 

provides the benefit estimates derived from expert opinions in Roman et al. (2008) as a 

characterization of uncertainty. In addition to the range of benefits based on epidemiology

studies, this study also provided a range of benefits associated with reducing emissions in eight 

specific urban areas. The range of VOC benefits that reflects the adjustments as well as the 

range of epidemiology studies and the range of the urban areas is $280 to $7,000 per ton of VOC 

reduced.

While these ranges of benefit-per-ton estimates provide useful context for the break-even 

analysis, 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 

 

46 For more information regarding EPA’s current VSL estimate, please see Section 5.4.4.1 of the RIA for the 

proposed Federal Transport Rule (U.S. EPA, 2010a). EPA continues to work to update its guidance on valuing 

mortality risk reductions. 
4-21

between VOC emissions and PM2.5, 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. 
4-22

Table 4-6 Monetized Benefits-per-Ton Estimates for VOC (2008$)

Area Pope et 

al.

Laden et 

al.

Expert 

A

Expert 

B

Expert 

C

Expert 

D

Expert 

E

Expert 

F

Expert 

G

Expert 

H

Expert 

I

Expert 

J

Expert 

K

Expert 

L

Atlanta $620 $1,500 $1,600 $1,200 $1,200 $860 $2,000 $1,100 $730 $920 $1,200 $980 $250 $940

Chicago $1,500 $3,800 $4,000 $3,100 $3,000 $2,200 $4,900 $2,800 $1,800 $2,300 $3,000 $2,500 $600 $2,400

Dallas $300 $740 $780 $610 $590 $420 $960 $540 $360 $450 $590 $480 $120 $460

Denver $720 $1,800 $1,800 $1,400 $1,400 $1,000 $2,300 $1,300 $850 $1,100 $1,400 $1,100 $280 $850

NYC/ 

Philadelphia $2,100 $5,200 $5,500 $4,300 $4,200 $3,000 $6,900 $3,900 $2,500 $3,200 $4,200 $3,400 $830 $3,100

Phoenix $1,000 $2,500 $2,600 $2,000 $2,000 $1,400 $3,300 $1,800 $1,200 $1,500 $2,000 $1,600 $400 $1,500

Salt Lake $1,300 $3,100 $3,300 $2,600 $2,500 $1,800 $4,100 $2,300 $1,500 $1,900 $2,500 $2,100 $530 $2,000

San Joaquin $2,900 $7,000 $7,400 $5,800 $5,600 $4,000 $9,100 $5,200 $3,400 $4,300 $5,600 $4,600 $1,300 $4,400

Seattle $280 $680 $720 $530 $550 $390 $890 $500 $330 $420 $550 $450 $110 $330

National average $1,200 $3,000 $3,200 $2,400 $2,400 $1,700 $3,900 $2,200 $1,400 $1,800 $2,400 $1,900 $490 $1,800

* These estimates assume a 50 percent reduction in VOC emissions, an analysis year of 2015, and a 3 percent discount rate. All estimates are rounded to two 

significant digits. These estimates have been updated from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currency year and EPA’s current VSL 

estimate. Using a discount rate of 7 percent, the benefit-per-ton estimates would be approximately 9 percent lower. Assuming a 75 percent reduction in VOC 

emissions would increase the benefit-per-ton estimates by approximately 4 percent to 52 percent. Assuming a 25 percent reduction in VOC emissions would 

decrease the benefit-per-ton estimates by 5 percent to 52 percent. EPA generally presents a range of benefits estimates derived from Pope et al. (2002) to 

Laden et al. (2006) and provides the benefits estimates derived from the expert functions from Roman et al. (2008) as a characterization of uncertainty.
4-23

4.5.3 Organic PM welfare effects

According to the residual risk assessment for this sector (U.S. EPA, 2011a), 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 the 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). 

PAHs can accumulate in sediments and bioaccumulate in freshwater, flora, and fauna. 

The uptake of organics depends on the plant species, site of deposition, physical and chemical 

properties of the organic compound and prevailing environmental conditions (U.S. EPA, 2009a). 

PAHs can accumulate to high enough concentrations in some coastal environments to pose an 

environmental health threat that includes cancer in fish populations, toxicity to organisms living 

in the sediment and risks to those (e.g., migratory birds) that consume these organisms. 

Atmospheric deposition of particles is thought to be the major source of PAHs to the sediments 

of coastal areas of the U.S. Deposition of PM to surfaces in urban settings increases the metal 

and organic component of storm water runoff. This atmospherically-associated pollutant burden 

can then be toxic to aquatic biota. The contribution of atmospherically deposited PAHs to 

aquatic food webs was demonstrated in high elevation mountain lakes with no other 

anthropogenic contaminant sources.

The recently completed Western Airborne Contaminants Assessment Project (WACAP) 

is the most comprehensive database on contaminant transport and PM depositional effects on 

sensitive ecosystems in the Western U.S. (Landers et al., 2008). In this project, the transport, 

fate, and ecological impacts of anthropogenic contaminants from atmospheric sources were 

assessed from 2002 to 2007 in seven ecosystem components (air, snow, water, sediment, lichen, 

conifer needles, and fish) in eight core national parks. The study concluded that bioaccumulation 

of semi-volatile organic compounds occurred throughout park ecosystems, an elevational 

gradient in PM deposition exists with greater accumulation in higher altitude areas, and 

contaminants accumulate in proximity to individual agriculture and industry sources, which is 
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counter to the original working hypothesis that most of the contaminants would originate from 

Eastern Europe and Asia. 

4.5.4 Visibility Effects

Reducing secondary formation of PM2.5 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, 2011g; U.S. EPA, 2011a) 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.

4.6 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), combine 

in the presence of sunlight. In urban areas, compounds representing all classes of VOC and CO 

are important compounds for ozone formation, but biogenic VOC emitted from vegetation tend 

to be more important compounds in non-urban vegetated areas (U.S. EPA, 2006a). 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). Second, the complex 

non-linear chemistry of ozone formation introduces uncertainty to the development and 

application of a benefit-per-ton estimate. Third, the impact of reducing VOC emissions is 
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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 time limitations under the court-ordered schedule and data limitations, we were 

unable to perform air quality modeling for this rule. 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 well completions, we are unable to estimate the effect that reducing VOC

will have on ambient ozone concentrations without air quality modeling. 

4.6.1 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). Epidemiological 

researchers have associated ozone exposure with adverse health effects in numerous 

toxicological, clinical and epidemiological studies (U.S. EPA, 2006c). When adequate data and 

resources are available, EPA generally quantifies several health effects associated with exposure 

to ozone (e.g., U.S. EPA, 2010a; U.S. EPA, 2011a). These health effects include respiratory

morbidity such as asthma attacks, hospital and emergency department visits, school loss days, as 

well as premature mortality. Although EPA has not quantified these effects in benefits analyses 

previously, the scientific literature is suggestive that exposure to ozone is also associated with 

chronic respiratory damage and premature aging of the lungs. 

In a recent EPA analysis, EPA estimated that reducing 15,000 tons of VOC from 

industrial boilers resulted in $3.6 to $15 million of monetized benefits from reduced ozone 

exposure (U.S. EPA, 2011b).47 This implies a benefit-per-ton for ozone reductions of $240 to 

$1,000 per ton of VOC reduced. 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 

 

47 While EPA has estimated the ozone benefits for many scenarios, most of these scenarios also reduce NOx 

emissions, which make it difficult to isolate the benefits attributable to VOC reductions. 
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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 these rules, even as a bounding 

exercise. 

4.6.2 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, 2006a). Sensitivity to ozone is highly variable 

across species, with over 65 plan 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 plant species, including 

forest trees, reduced crop yields, visible foliar injury, reduced plant vigor (e.g., increased 

susceptibility to harsh weather, disease, insect pest infestation, and competition), species 

composition shift, and changes in ecosystems and associated ecosystem services. 

4.6.3 Ozone climate effects

Ozone is a well-known short-lived climate forcing (SLCF) greenhouse gas (GHG) (U.S. 

EPA, 2006a). 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

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 discernable influence of ground level ozone on climate leads to increases in global surface 

temperature and changes in hydrological cycles. 
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4.7 Methane (CH4)

4.7.1 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 which 

contributes to increased global warming and continuing climate change. Methane reacts in the 

atmosphere to form ozone and ozone also impacts global temperatures. Methane, in addition to 

other GHG emissions, contributes to warming of the atmosphere which over time leads to 

increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of 

global glaciers and ice, increasingly severe weather events, such as hurricanes of greater 

intensity, and sea level rise, among other impacts. 

According to the Intergovernmental Panel on Climate Change (IPCC) Fourth Assessment 

Report (2007), changes in methane concentrations since 1750 contributed 0.48 W/m2of forcing, 

which is about 18% 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 0.86 W/m2of forcing today, which is about 30% 

of the 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: 1990-2009 (published April 2011) estimates 2009 

methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries 

and petroleum transportation) to be 251.55 (MMtCO2-e). In 2009, total methane emissions from 

the oil and gas industry represented nearly 40 percent of the total methane emissions from all 

sources and account for about 5 percent of all CO2-equivalent (CO2-e) emissions in the U.S., 

with natural gas systems being the single largest contributor to U.S. anthropogenic methane 

emissions (U.S. EPA, 2011b, Table ES-2). It is important to note that the 2009 emissions 

estimates from well completions and recompletions exclude a significant number of wells 

completed in tight sand plays and the Marcellus Shale, due to availability of data when the 2009 

Inventory was developed. The estimate in this final rule includes an adjustment for tight sand 
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plays and the Marcellus Shale, and such an adjustment is also being considered as a planned 

improvement in next year's Inventory. This adjustment would increase the 2009 Inventory

estimate by about 80 MMtCO2-e. The total methane emissions from Petroleum and Natural Gas 

Systems based on the 2009 Inventory, adjusted for tight sand plays and the Marcellus Shale, is 

approximately 330 MMtCO2-e.

This rulemaking finalizes emission control technologies and regulatory alternatives that 

will significantly decrease methane emissions from the oil and natural gas sector in the United 

States. The NSPS is expected to reduce methane emissions annually by about 1.7 million short 

tons or approximately 33 million metric tons CO2-e. These reductions represent about 13

percent of the GHG emissions for this sector reported in the 1990-2009 U.S. GHG Inventory

(251.55 MMTCO2-e). This annual CO2-e reduction becomes about 31 million metric tons when 

the secondary impacts associated with increased combustion and supplemental energy use on the 

producer side and CO2-e emissions from changes in consumption patterns previously discussed 

are considered. However, it is important to note the emissions reductions are based upon 

predicted activities in 2015; EPA did not forecast sector-level emissions to 2015 for this 

rulemaking. The climate co-benefit from these reductions are equivalent of taking 

approximately 6 million typical passenger cars off the road or eliminating electricity use from 

about 4 million typical homes each year.48 

EPA estimates the social benefits of regulatory actions that have a small or “marginal” 

impact on cumulative global CO2 emissions using the “social cost of carbon” (SCC). The SCC 

is an estimate of the net present value of the flow of monetized damages from a one metric ton 

increase in CO2 emissions in a given year (or from the alternative perspective, the benefit to 

society of reducing CO2 emissions by one ton). The SCC includes (but is not limited to) climate 

damages due to changes in net agricultural productivity, human health, property damages from 

flood risk, and ecosystem services due to climate change. The SCC estimates currently used by 

the Agency were developed through an interagency process that included EPA and other 

executive branch entities, and concluded in February 2010. The Technical Support Document: 

Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 for the 

 

48 US Environmental Protection Agency. Greenhouse Gas Equivalency Calculator available at: 

http://www.epa.gov/cleanenergy/energy-resources/calculator.html accessed 02/13/12.
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final joint EPA/Department of Transportation Rulemaking to establish Light-Duty Vehicle 

Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards provides 

a complete discussion of the methods used to develop the SCC estimates (Interagency Working 

Group on Social Cost of Carbon, 2010). 

To estimate global social benefits of reduced CO2 emissions, the interagency group 

selected four SCC values for use in regulatory analyses: $6, $25, $40, and $76 per metric ton of 

CO2 emissions in 2015, in 2008 dollars.49 The first three values are based on the average SCC 

estimated using three integrated assessment models (IAMs), at discount rates of 5.0, 3.0, and 2.5 

percent, respectively. When valuing the impacts of climate change, IAMs couple economic and 

climate systems into a single model to capture important interactions between the components. 

SCCs estimated using different discount rates are included because the literature shows that the 

SCC is quite sensitive to assumptions about the discount rate, and because no consensus exists 

on the appropriate rate to use in an intergenerational context. The fourth value is the 95th 

percentile of the distribution of SCC estimates from all three models at a 3.0 percent discount 

rate. It is included to represent higher-than-expected damages from temperature change further 

out in the tails of the SCC distribution. 

The interagency group noted a number of limitations to the SCC analysis, including the 

incomplete way in which the integrated assessment models capture catastrophic and noncatastrophic impacts, their incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk 

aversion. The limited amount of research linking climate impacts to economic damages makes 

estimating damages from climate change even more difficult. The interagency group hopes that 

over time researchers and modelers will work to fill these gaps and that the SCC estimates used 

for regulatory analysis by the Federal government will continue to evolve with improvements in 

modeling. Additional details on these limitations are discussed in the SCC TSD. 

 

49 The interagency group concluded that a global measure of the benefits from reducing U.S. emissions is preferable. 

The development of a domestic SCC is greatly complicated by the relatively few region- or country-specific 

estimates of SCC in the literature. See Interagency Working Group on Social Cost of Carbon. 2010. Technical 

Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. 
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A significant limitation of the aforementioned interagency process particularly relevant to 

this rulemaking is that the social costs of non-CO2 GHG emissions were not estimated. 

Specifically, the interagency group did not directly estimate the social cost of non-CO2 GHGs 

using the three models. Moreover, the group determined that it would not transform the CO2

estimates into estimates for non-CO2 GHGs using global warming potentials (GWPs), which 

measure the ability of different gases to trap heat in the atmosphere (i.e., radiative forcing per 

unit of mass) over a particular timeframe relative to CO2. One potential method for 

approximating the value of marginal non-CO2 GHG emission reductions is to convert the 

reductions to CO2-equivalents which may then be valued using the SCC. Conversion to CO2-e is 

typically done using the GWPs for the non-CO2 gas. The GWP is an aggregate measure that 

approximates the additional energy trapped in the atmosphere over a given timeframe from a 

perturbation of a non-CO2 gas relative to CO2. The time horizon most commonly used is 100 

years. One potential problem with utilizing temporally aggregated statistics, such as the GWPs, 

is that the additional radiative forcing from the GHG perturbation is not constant over time and 

any differences in temporal dynamics between gases will be lost. This is a potentially

confounding issue given that the social cost of GHGs is based on a discounted stream of 

damages that are non-linear in temperature. For example, methane has an expected adjusted 

atmospheric lifetime of about 12 years and associated GWP of 21 (IPCC Second Assessment 

Report (SAR) 100-year GWP estimate). Gases with a relatively shorter lifetime, such as 

methane, have impacts that occur primarily in the near term and thus are not discounted as 

heavily as those caused by longer-lived gases such as CO2, while the GWP treats additional 

forcing the same independent of when it occurs in time. Furthermore, the baseline temperature 

change is lower in the near term and therefore the additional warming from relatively short lived 

gases will have a lower marginal impact relative to longer lived gases that have an impact further 

out in the future when baseline warming is higher. The GWP also relies on an arbitrary time 

horizon and constant concentration scenario. Both of which are inconsistent with the 

assumptions used by the SCC interagency workgroup. Finally, impacts other than temperature 

change also vary across gases in ways that are not captured by GWP. For instance, CO2

emissions, unlike methane will result in CO2 passive fertilization to plants. 
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The EPA recognizes that the methane reductions finalized in this rule will provide 

significant economic climate co-benefits to society. However, the 2009-2010 Interagency Social 

Cost of Carbon Work Group did not produce directly modeled estimates of the social cost of 

methane. In the absence of direct model estimates from the interagency analysis, EPA has used 

aA “global warming potential (GWP) approach” to estimate the dollar value of this rule’s 

methane co-benefits. Specifically, EPA of converted methane to CO2 equivalents using the 

GWP of methane, then multiplied these CO2-equivalent emission reductions by the social cost of 

carbon developed by the Interagency Social Cost of Carbon Work Group.

EPA requested comments from interested parties and the public about this interim

approach specifically and more broadly about appropriate methods to monetize the climate cobenefits of methane reductions. EPA’s response to these comments, as well as a summary of the 

public comments sent in response to this request, is provided in the response to comments 

document. 

Applying the GWP approach, these co-benefits equate to a range of approximately $130

to $1,600 per metric ton of methane reduced depending upon the discount rate assumed, with an

estimate of $840 per ton using the mean SCC at the 3 percent discount rate.

50

 When including

expected methane emission reductions from the NESHAP Amendments and NSPS and 

considering secondary impacts of the oil and gas rule, the 2015 co-benefits vary by discount rate 

and range from about $190 million to over $2.4 billion; the mean SCC at the 3 percent discount 

rate ($25 per metric ton) results in an estimate of $780 million in 2015 (Table 4-7). 

 

50 The per ton estimates range from approximately $110 to $1400 per short ton of methane reduced, depending on 

the discount rate assumed, with an estimate of $480 per short ton of methane, using the mean SCC at 3% 

discount rate.
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Table 4-7 Climate Methane Benefits Using ‘GWP’ Approach

SCC Value for 2015 emission reductions ($/ton 

CO2 in 2008 dollars) 1

Total Benefits based on 100 year GWP 

adjustment2(millions 2008$)

Final NSPS

Final NESHAP 

Amendments

$6 (mean 5% discount rate) 190 0.5

$25 (mean 3% discount rate) 780 2.3

$40 (mean 2.5% discount rate) 1,200 3.6

$76 (95 percentile at 3% discount rate) 2,400 6.8

Methane Emission Reductions 3(MMT CO2-e) 31 0.09

1

SCC values for 2015 from the SCC TSD in the light duty vehicle rule adjusted to reflect 2008$ using the CPI-U 

from the Bureau of Labor Statistics.

2 Estimates are given for illustrative purposes and represent the CO2-e estimate of methane reductions multiplied by 

the SCC estimates (“GWP approach”).CO2-e calculated using the GWP of 21 (SAR). These co-benefit estimates 

are not the same as would be derived using a social cost of methane directly computed from integrated assessment 

models. See Marten and Newbold (2011) for discussion of the limitations of the GWP approach. 

3 Estimates include methane reductions from the NSPS and NESHAP Amendments respectively and consider 

secondary impacts from Table 4-4.

As previously stated, these co-benefit estimates are not the same as would be derived 

using a directly computed social cost of methane (using the integrated assessment models 

employed to develop the SCC estimates) for a variety of reasons including the shorter 

atmospheric lifetime of methane relative to CO2 (about 12 years compared to CO2 whose 

concentrations in the atmosphere decay on timescales of decades to millennia). The climate 

impacts also differ between the pollutants for reasons other than the radiative forcing profiles and 

atmospheric lifetimes of these gases. Methane is a precursor to ozone and ozone is a short-lived 

climate forcer (details below). This use of the SAR GWP to approximate benefits may

underestimate the direct radiative forcing benefits of reduced ozone levels, and does not capture 

any secondary climate co-benefits involved with ozone-ecosystem interactions. In addition, a 

recent NCEE working paper suggests that this quick ‘GWP approach’ to benefits estimation will 

likely understate the climate benefits of methane reductions in most cases (Marten and Newbold, 

2011). This conclusion is reached using the 100 year GWP for methane of 25 as put forth in the 

IPCC Fourth Assessment Report as opposed to the lower value of 21 used in this analysis. Using 

the higher GWP estimate of 25 would increase these reported methane climate co-benefit 

estimates by about 19 percent. Although the IPCC Fourth Assessment Report suggested a GWP 

of 25, EPA has used GWP of 21 consistent with the IPCC SAR to estimate the methane climate 

co-benefits for this oil and gas rule. The use of the SAR GWP values allows comparability of 
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data collected in this final rule to the national GHG inventory that EPA compiles annually to 

meet U.S. commitments to the United Nations Framework Convention on Climate Change

(UNFCCC). To comply with international reporting standards under the UNFCCC, official 

emission estimates are to be reported by the U.S. and other countries using SAR GWP values. 

The UNFCCC reporting guidelines for national inventories were updated in 2002 but continue to 

require the use of GWPs from the SAR. The parties to the UNFCCC have also agreed to use 

GWPs based upon a 100-year time horizon although other time horizon values are available. 

The SAR GWP value for methane is also currently used to establish GHG reporting requirements 

as mandated by the GHG Reporting Rule (2010e) and is used by the EPA to determine Title V 

and Prevention of Significant Deterioration GHG permitting requirements as modified by the 

GHG Tailoring Rule (2010f).

EPA also undertook a literature search for estimates of the marginal social cost of 

methane. A range of marginal social cost of methane benefit estimates are available in published 

literature (Fankhauser (1994), Kandlikar (1995), Hammitt et al. (1996), Tol et al. (2003), Tol, et 

al. (2006), Hope (2005) and Hope and Newberry (2006). Most of these estimates are based upon 

modeling assumptions that are dated and inconsistent with the current SCC estimates. Some of 

these studies focused on marginal methane reductions in the 1990s and early 2000s and report 

estimates for only the single year of interest specific to the study. The assumptions underlying 

the social cost of methane estimates available in the literature differ from those agreed upon by 

the SCC interagency group and in many cases use older versions of the IAMs. Without 

additional analysis, the methane climate benefit estimates available in the current literature are 

not acceptable to use to value the methane reductions finalized in this rulemaking.

Given the uncertainties with both the ‘GWP approach’ estimates presented and estimates 

available in the literature, EPA chooses not to compare these co-benefit estimates to the costs of 

the rule for this final rule. Rather, the EPA presents the ‘GWP approach’ climate co-benefit 

estimates as an interim method to produce lower-bound estimates until the interagency group 

develops values for non-CO2 GHGs. 
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4.7.2 Methane as an ozone precursor

This rulemaking would reduce emissions of methane, a GHG and also a precursor to

ozone. In remote areas, methane is a dominant precursor to tropospheric ozone formation (U.S. 

EPA, 2006a). Approximately 40% 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 VOC, which affect ozone concentrations regionally

and at hourly time scales, methane emissions affect ozone concentrations globally and on 

decadal time scales given methane’s relatively long atmospheric lifetime (HTAP, 2010). 

Reducing methane emissions, therefore, can reduce global background ozone concentrations, 

human exposure to ozone, and the incidence of ozone-related health effects (West et al., 2006, 

Anenberg et al., 2009). These benefits are global and occur in both urban and rural areas. 

Reductions in background ozone concentrations can also have benefits for agriculture and 

ecosystems (UNEP/WMO, 2011). Studies show that controlling methane emissions can reduce 

global ozone concentrations and climate change simultaneously, but controlling other shorterlived ozone precursors such as NOx, carbon monoxide, or non-methane VOC may have larger

local health benefits from greater reductions in ozone concentrations (West and Fiore, 2005; 

West et al., 2006, 2007; Fiore et al. 2008; Dentener et al., 2005; Shindell et al., 2005, 2012; 

UNEP/WMO, 2011).VOC The health, welfare, and climate effects associated with ozone are 

described in the preceding sections. Without air quality modeling, we are unable to estimate the 

effect that reducing methane will have on ozone concentrations at particular locations.

4.7.3 Combined methane and ozone effects

A recent United Nations Environment Programme (UNEP) assessment provides the most 

comprehensive analysis to date of the health, climate, and agricultural benefits of measures to 

reduce methane, as well as black carbon, a component of fine particulate matter that absorbs

radiation (UNEP/WMO, 2011; Shindell et al., 2012). The UNEP assessment found that while 

reducing longer-lived GHGs such as CO2 is necessary to protect against long-term climate 

change, reducing global methane and black carbon emissions would have global health benefits 

by reducing exposure to ozone and PM2.5 as well as potentially slowing the rate of climate 

change within the first half of this century. Relative to a business as usual reference scenario, 
4-35

implementing methane mitigation measures that achieve approximately 40% reductions in global 

methane emissions were estimated to avoid approximately 0.3° C globally averaged warming in 

2050 (including the impacts of both methane itself and subsequently formed ozone) and 47,000 

ozone-related premature deaths and 27 million metric tons of ozone-related crop yield losses 

globally in 2030 (Shindell et al., 2012). These benefits, including global climate impacts of 

methane and resulting ozone changes, and global ozone-related health and agricultural impacts, 

were valued at $700 to $,5000 per metric ton51. The methane measures examined include 

extended methane recovery/utilization and reduced fugitive emissions from oil and gas 

production, which contributed the greatest climate benefit of all methane mitigation measures in 

North America and Europe (UNEP, 2011).

4.8 References

Anenberg, S.C., et al. 2009. “Intercontinental impacts of ozone pollution on human mortality,” 

Environ. Sci. & Technol., 43, 6482-6487.

Dentener, F., D. Stevenson, J. Cofala, R. Mechler, M. Amann, P. Bergamaschi, F. Raes, and R. 

Derwent. 2005. “The impact of air pollutant and methane emission controls on 

tropospheric ozone and radiative forcing: CTM calculations for the period 1990-2030,” 

Atmos. Chem. Phys., 5, 1731-1755. 

Fankhauser, S. 1994. “The social costs of greenhouse gas emissions: an expected value 

approach.” Energy Journal 15(2):157–184.

Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. “The influence of location, source, and emission 

type in estimates of the human health benefits of reducing a ton of air pollution.” Air 

Qual Atmos Health 2:169-176.

Fiore, A.M., J.J. West, L.W. Horowitz, V. Naik, and M.D. Schwarzkopf. 2008. “Characterizing 

the tropospheric ozone response to methane emission controls and the benefits to climate 

and air quality,” J. Geophys. Res., 113, D08307, doi:10.1029/2007JD009162

 

51 Benefit per ton values derived from Shindell et al. (2012) cannot be directly compared to, nor are they additive 

with, the ozone health benefit-per-ton estimates for the U.S. reported in Section 4.6.1, since they include climate 

and agricultural impacts, are calculated for global rather than U.S. impacts, and use different assumptions for the 

value of a statistical life. Similarly, these values cannot be compared to, nor are they additive with, the methane 

climate valuation estimates in Section 4.7.1 since they include health and agricultural benefits and use different 

assumptions for the Social Cost of Carbon.
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Forster, P. et al. 2007. Changes in Atmospheric Constituents and in Radiative Forcing. In: 

Climate Change 2007. The Physical Science Basis. Contribution of Working Group I to 

the Fourth Assessment Report of the Intergovernmental Panel on Climate Change 

[Solomon, S., D. Qin, M. Manning, Z. Chen, M. Marquis, K.B. Averyt, M. Tignor and 

H.L. Miller (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New 

York, NY, USA.

Gwinn, M.R., J. Craig, D.A. Axelrad, R. Cook, C. Dockins, N. Fann, R. Fegley, D.E. Guinnup, 

G. Helfand, B. Hubbell, S.L. Mazur, T. Palma, R.L. Smith, J. Vandenberg, and 

B. Sonawane. 2011. “Meeting report: Estimating the benefits of reducing hazardous air 

pollutants—summary of 2009 workshop and future considerations.” Environ Health 

Perspect. 119(1): p. 125-30.

Hammitt, J.K., A.K. Jain, J.L. Adams, and D.J. Wuebbles. 1996. “A welfare-based index for 

assessing environmental effects of greenhouse-gas emissions.” Nature, 381(6580):301–

303, 1996.

Hope, C. 2005. “The climate change benefits of reducing methane emissions.” Climatic Change

68(1):21–39.

Hope, C. and D. Newbery. 2006. “Calculating the Social Cost of Carbon” Forthcoming in 

Delivering a Low Carbon Electricity System: Technologies, Economics and Policy

Editors: Michael Grubb, Tooraj Jamasb and Michael G. Pollitt (University of Cambridge) 

Cambridge University Press. Available on the Internet at 

<http://www.dspace.cam.ac.uk/handle/1810/194738> Accessed March 30, 2011.

Industrial Economics, Inc (IEc). 2009. Section 812 Prospective Study of the Benefits and Costs of 

the Clean Air Act: Air Toxics Case Study—Health Benefits of Benzene Reductions in 

Houston, 1990–2020. Final Report, July 14, 2009. 

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

y_2009.pdf>. Accessed March 30, 2011.

Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. Technical Support 

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4-39

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supplemental_analysis_full.pdf>. Accessed March 30, 2011.

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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.

In addition, the EPA prepared an analysis of the potential costs and benefits associated 

with this action. The RIA available in the docket describes in detail the empirical basis for the 

EPA’s assumptions and characterizes the various sources of uncertainties affecting the estimates 

below. Table 5-1 shows the results of the cost and benefits analysis for these final rules. 
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Table 5-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil 

and Natural Gas NSPS and NESHAP Amendments in 2015 (millions of 2008$)1

NSPS NESHAP Amendments NSPS and NESHAP 

Amendments Combined

Total Monetized Benefits2 N/A N/A N/A

Total Costs3 -$18 million4

$18 million -$61,000

Net Benefits N/A N/A N/A

Non-monetized Benefits 19,000 tons of HAP 1,300 tons of HAP 20,000 tons of HAP

290,000 tons of VOC 9,000 tons of VOC 300,000 tons of VOC

1.7 million tons of methane 4,800 tons of methane 1.7 million tons of methane

Health effects of HAP 

exposure5

Health effects of HAP 

exposure

Health effects of HAP 

exposure

Health effects of PM2.5 and 

ozone exposure

Health effects of PM2.5 and 

ozone exposure

Health effects of PM2.5 and 

ozone exposure

Visibility impairment Visibility impairment Visibility impairment

Vegetation effects Vegetation effects Vegetation effects

Climate effects5 Climate effects5 Climate effects5

1 All estimates are for the implementation year (2015) and include estimated revenue from additional natural gas 

recovery as a result of the NSPS.

2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health 

effects associated with HAP, ozone, and particulate matter (PM) as well as climate effects associated with methane, we 

have determined that quantification of those benefits and co-benefits cannot be accomplished for this rule in a 

defensible way. This is not to imply that there are no benefits or co-benefits of the rules; 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. The specific control technologies for the final NSPS are anticipated to have minor secondary 

disbenefits, including an increase of 1.2 million tons of carbon dioxide (CO2), 630 tons of nitrogen oxides NOx, 19 tons 

of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as well as emission reductions associated with 

the energy system impacts. The specific control technologies for the NESHAP is anticipated to have minor secondary 

disbenefits, including an increase of 5,500 tons of CO2, 2.9 tons of NOx, 16 tons of CO, and 6.0 tons of total 

hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO2-

equivalent emission reductions are 31 million metric tons.

3 The engineering compliance costs are annualized using a 7 percent discount rate. 

4 The negative cost for the NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon 

condensate recovery that are estimated as a result of the final NSPS. Possible explanations for why there appear to be 

negative cost control technologies are discussed in the engineering costs analysis section in the RIA. 

5

For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC 

emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co-benefits.
5-3

5.2 Paperwork Reduction Act

The information collection requirements in this rule have been submitted for approval to 

OMB under the PRA, 44 U.S.C. 3501, et seq. The ICR document prepared by EPA has been 

assigned EPA ICR number 1716.07. 

[Note: The summary of the results of the ICR and supporting statement will be provided.]

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When these ICRs 

are approved by OMB, the agency will publish a technical amendment to 40 CFR part 9 in the 

Federal Register to display the OMB control numbers for the approved information collection 

requirements contained in the final rule.

5.3 Regulatory Flexibility Act

The Regulatory Flexibility Act 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 (SISNOSE). 

Small entities include small businesses, small organizations, and small governmental 

jurisdictions. For purposes of assessing the impact of this rule on small entities, a small entity is 

defined as: (1) A small business whose parent company has no more than 500 employees (or 

revenues of less than $7 million for firms that transport natural gas 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-forprofit enterprise which is independently owned and operated and is not dominant in its field.

For the final NSPS, the EPA performed an analysis for impacts on a sample of expected 

affected small entities by comparing compliance costs to entity revenues. Based upon the 

analysis in the RIA, which is in the Docket, when revenue from additional natural gas product 

recovered is not included, we estimate that 120 of the 127 small firms analyzed (94 percent) are 

likely to have impacts less than 1 percent in terms of the ratio of annualized compliance costs to 

revenues. Meanwhile, seven firms (6 percent) are likely to have impacts greater than 1 percent. 
5-4

Three of these seven firms are likely to have impacts greater than 3 percent. However, when 

revenue from additional natural gas product recovery is included, we estimate that none of the

analyzed firms will have an impact greater than 1 percent.

For the final NESHAP Amendments, we estimate that 54 of the 108 firms (50 percent) 

that own potentially affected facilities are small entities. The EPA performed an analysis for 

impacts on all expected affected small entities by comparing compliance costs to entity revenues. 

Among the small firms, 45 of the 54 (83 percent) are likely to have impacts of less than 1 percent 

in terms of the ratio of annualized compliance costs to revenues. Meanwhile, nine firms (17 

percent) are likely to have impacts greater than 1 percent. Three of these nine firms are likely to 

have impacts greater than 3 percent. While these nine firms might receive significant impacts 

from the final NESHAP amendments, they represent a very small slice of the oil and gas industry

in its entirety, less than 0.2 percent of the estimated 6,427 small firms in NAICS 211. 

After considering the economic impact of the combined NSPS and NESHAP 

amendments on small entities, I certify this action will not have a SISNOSE. While both the 

NSPS and NESHAP amendment would individually result in a no SISNOSE finding, the EPA 

performed an additional analysis in order to certify the rule in its entirety. This analysis 

compared compliance costs to entity revenues for the total of all the entities affected by the 

NESHAP amendments and the sample of entities analyzed for the NSPS. When revenues from 

additional natural gas product sales are not included, 153 of the 169 small firms (91 percent) in 

the sample are likely to have impacts of less than 1 percent in terms of the ratio of annualized 

compliance costs to revenues. Meanwhile, 16 firms (9 percent) are likely to have impacts greater 

than 1 percent. Six of these 16 firms are likely to have impacts greater than 3 percent. When 

revenues from additional natural gas product sales are included, 160 small firms (95 percent) in 

the sample are likely to have impacts of less than 1 percent. Nine firms (5 percent) are likely to 

have impacts greater than 1 percent, while only three of these nine are likely to have impacts 

greater than 3 percent. 

Our determination is informed by the fact that many affected firms are expected to 

receive revenues from the additional natural gas and condensate recovery engendered by the 

implementation of the controls evaluated in this RIA. As much of the additional natural gas 

recovery is estimated to arise from completion-related activities, we expect the impact on wellrelated compliance costs to be significantly mitigated. This conclusion is enhanced because the 
5-5

returns to REC activities occur without a significant time lag between implementing the control 

and obtaining the recovered product, unlike many control options where the emissions reductions 

accumulate over long periods of time; the reduced emission completions and recompletions 

occur over a short span of time, during which the additional product recovery is also 

accomplished.

Although this final rule will not impact a substantial number of small entities, the EPA, 

nonetheless, has tried to reduce the impact of this rule on small entities by setting the final 

emissions limits at the MACT floor, the least stringent level allowed by law.

5.4 Unfunded Mandates Reform Act

This final action does not contain a federal mandate under the provisions of Title III of 

the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538 for state, local, and 

tribal governments, in the aggregate, or to the private sector. The action would not result in 

expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, or 

to the private sector in any 1 year. Thus, this final rule is not subject to the requirements of 

sections 202 or 205 of UMRA.

This final rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments because it contains no requirements that apply to such governments nor does it 

impose obligations upon them.

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, as 

specified in Executive Order 13132. These final rules primarily affect private industry, and do 

not impose significant economic costs on state or local governments. Thus, Executive Order 

13132 does not apply to this action. 
5-6

5.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments

This action does have tribal implications, as specified in Executive Order 13175 (65 FR 

67249, November 9, 2000) because the growth of the oil and gas production industry in Indian 

country. As a result, EPA conducted early outreach to the tribes, prior to proposal in 2010. We 

met with the Inter Tribal Environmental Council, which include many of the Region VI tribes, 

The Tribal leadership summit in Region X, and Tribal Energy Conference hosted by Ft. Belknap, 

and the National Tribal Forum. 

After the Proposal was published letters were sent to all tribal leaders offering to consult 

on the rule. An outreach and consultation call was held on October 12, 2011. Tribes that 

participated on this call were: Fond du Lac Band of Lake Superior Chippewa, Fort Belknap 

Indian Community, Forest County Potawatomi Community, Southern Ute Indian Tribe, and 

Pueblo of Santa Clara. All these tribes counted this as information only, not consultation. There 

were no issues raised during this call. The tribes were listening to the presentation and the call 

was ended without comment.

In this meeting the tribes were presented the information in the proposal then asked 

general clarifying questions but did not provide specific comments. Comments on the proposal 

were received from an affiliate of the Southern Ute Indian Tribe. The commenter expressed 

concern about the impacts of the rule on natural gas and oil production operations on the 

Southern Ute Indian reservation and requested additional time to evaluate the impacts. In 

response to this and other requests, the comment period was extended. More specific comments 

can be found in the docket. 

5.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks

This action is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) 

because it is not economically significant as defined in Executive Order 12866, and because the 

EPA does not believe the environmental health or safety risks addressed by this action present a 

disproportionate risk to children. This action would not relax the control measures on existing 

regulated sources. The EPA’s risk assessments (included in the docket for this rule) demonstrate 
5-7

that the existing regulations are associated with an acceptable level of risk and provide an ample 

margin of safety to protect public health. 

5.8 Executive Order 13211: Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined in Executive Order 13211 (66 

FR 28,355, May 22, 2001), because it is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. These final rules will result in the addition of control 

equipment and monitoring systems for existing and new sources within the oil and natural gas 

industry. The final NESHAP Amendments are unlikely to have a significant adverse effect on 

the supply, distribution, or use of energy. As such, the final NESHAP Amendments are not 

“significant energy actions” as defined in Executive Order 13211, (66 FR 28355, May 22, 2001). 

The final NSPS is also unlikely to have a significant adverse effect on the supply, 

distribution, or use of energy. As such, the final NSPS is not a “significant energy action” as 

defined in Executive Order 13211 (66 FR 28355, May 22, 2001). The basis for the determination 

is as follows.

We use the NEMS to estimate the impacts of the final NSPS 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 U.S. DOE and is 

used to produce the Annual Energy Outlook, a reference publication that provides detailed 

forecasts of the United States energy economy. 

Emission controls for the NSPS capture VOC emissions that otherwise would be vented 

to the atmosphere. Since methane is co-emitted with VOC, a large proportion of the averted 

methane emissions can be directed into natural gas production streams and sold. One pollution 

control requirement of the final NSPS also captures saleable condensates. The revenues from 

additional natural gas and condensate recovery are expected to offset the costs of implementing 

the final NSPS. 

The analysis of energy impacts for the final NSPS that includes the additional product 

recovery shows that domestic natural gas production is estimated to increase (about 60 billion 

cubic feet or 0.3 percent) and natural gas prices to decrease ($0.05/Mcf or 1.1 percent at the 
5-8

wellhead for producers in the lower 48 states) in 2015, the year of analysis. Domestic crude oil 

production is not estimated to change, while crude oil prices are estimated to decrease slightly 

($0.01/barrel or less than about 0.01 percent at the wellhead for producers in the lower 48 states) 

in 2015, the year of analysis. All prices are in 2008 dollars.

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.

5.9 National Technology Transfer and Advancement Act

Section 12(d) of the NTTAA of 1995, Public Law 104–113, 12(d) (15 U.S.C. 272 note) 

directs the EPA to use VCS in its regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. Voluntary consensus standards are technical standards 

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are 

developed or adopted by VCS bodies. The NTTAA directs EPA to provide Congress, through 

OMB, explanations when the EPA decides not to use available and 

applicable VCS. 

This final action does not involve technical standards. Therefore, the EPA is not 

considering the use of any VCS.

5.10 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive 

policy on EJ. Its main provision directs Federal agencies, to the greatest extent practicable and 

permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, 

disproportionately high and adverse human health or environmental effects of their programs, 

policies and activities on minority populations and low income populations in the United States.

The EPA has determined that this final rule will not have disproportionately high and 

adverse human health or environmental effects on minority or low-income populations because it 

increases the level of environmental protection for all affected populations without having any
5-9

disproportionately high and adverse human health or environmental effects on any population, 

including any minority, low-income, or indigenous populations. 

To examine the potential for any environmental justice issues that might be associated 

with each source category, we evaluated the percentages of various social, demographic, and 

economic groups within the at-risk population living near the facilities where these source 

categories are located and compared them to national averages. The development of 

demographic analyses to inform the consideration of environmental justice issues in EPA 

rulemakings is an evolving science. 

The EPA conducted a demographic analysis, focusing on populations within 50 km of 

any facility in each of the source categories that are estimated to have HAP exposures which 

result in cancer risks of 1-in-1 million or greater or non-cancer hazard indices of 1 or greater 

based on estimates of current HAP emissions. The results of this analysis are documented in the 

technical report: Risk and Technology Review – Analysis of Socio-economic Factors for 

Populations Living Near Oil & Natural Gas Production Facilities located in the docket for this 

rulemaking.

As described in the preamble, our risk assessments demonstrate that the regulations for 

the oil and natural gas production and natural gas transmission and storage source categories, are 

associated with an acceptable level of risk and that the additional requirements will provide an 

ample margin of safety to protect public health. Our analyses also show that, for these source 

categories, there is no potential for an adverse environmental effect or human health multipathway effects, and that acute and chronic noncancer health impacts are unlikely. The EPA has 

determined that, although there may be an existing disparity in HAP risks from these sources 

between some demographic groups, no demographic group is exposed to an unacceptable level 

of risk.

EPA defines “Environmental Justice” to include meaningful involvement of all people 

regardless of race, color, national origin, or income with respect to the development, 

implementation, and enforcement of environmental laws, regulations, and polices. To promote 

meaningful involvement, EPA conducted three public hearings on the proposal. The hearings 

were held in Pittsburgh, PA on September 27, 2011, Denver, CO on September 28, 2011 and 

Arlington, TX on September 29, 2011. A total of 261 people spoke at the three hearings and 735 

people attended the hearings. The attendees at the hearings included private citizens, community-
5-10

based and environmental organizations, industry representatives, associations representing 

industry and local and state government officials.

5.11 Congressional Review Act

U.S.C. 801, et seq., as added by the Small Business Regulatory Enforcement Fairness Act 

of 1996, generally provides that, before a rule may take effect, the agency promulgating the rule 

must submit a rule report, which includes a copy of the rule, to each House of the Congress and 

to the Comptroller General of the United States. The EPA will submit a report containing this 

final rule and other required information to the United States Senate, the United States House of 

Representatives, and the Comptroller General of the United States prior to publication of the 

final rule in the Federal Register. A major rule cannot take effect until 60 days after it is 

published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 

804(2). 
6-1

6 COMPARISON OF BENEFITS AND COSTS

Because we are unable to estimate the monetary value of the emissions reductions from 

the rule, we have chosen to rely upon a break-even analysis to estimate what the monetary value 

benefits would need to attain in order to equal the costs estimated to be imposed by the rule. A 

break-even analysis answers the question, “What would the benefits need to be for the benefits to 

exceed the costs.” While a break-even approach is not equivalent to a benefits analysis or even a 

net benefits analysis, we feel the results are illustrative, particularly in the context of previously

modeled benefits.

The total engineering cost of the final NSPS in the analysis year of 2015 when the 

additional natural gas and condensate recovery is included in the analysis is estimated at -$18

million. EPA anticipates that this rule would prevent 290,000 tons of VOC, 1.7 million tons of 

methane, and 19,000 tons of HAP in 2015 from new sources. In 2015, EPA estimates the costs 

for the NESHAP Amendments to be 18 million.52 EPA anticipates that this rule would reduce 

9,000 tons of VOC, 4,800 tons of methane, and 1,300 tons of HAP in 2015 from existing 

sources. For the NESHAP Amendments, a break-even analysis suggests that HAP emissions 

would need to be valued at $14,000 per ton for the benefits to exceed the costs if the health

benefits, and ecosystem and climate co-benefits from the reductions in VOC and methane 

emissions are assumed to be zero. If we assume the health benefits from HAP emission 

reductions are zero, the VOC emissions would need to be valued at $1,900 per ton or the 

methane emissions would need to be valued at $3,700 per ton for the benefits to exceed the costs. 

All estimates are in 2008 dollars. 

For the final NSPS, the revenue from additional natural gas recovery already exceeds the 

costs, which renders a break-even analysis unnecessary. However, as discussed in Section 3.2.2., 

estimates of the annualized engineering costs that include revenues from natural gas product 

recovery depend heavily upon assumptions about the price of natural gas and hydrocarbon 

condensates in analysis year 2015. Therefore, we have also conducted a break-even analysis for 

the price of natural gas. For the NSPS, a break-even analysis suggests that the price of natural 

 

52 See Section 3 of this RIA for more information regarding the cost estimates for the NESHAP. 
6-2

gas would need to be at least $3.79 per Mcf in 2015 for the revenue from product recovery to 

exceed the annualized costs. EIA forecasts that the price of natural gas would be $4.22 per Mcf 

in 2015. In addition to the revenue from product recovery, the NSPS would avert emissions of 

VOC, HAP, and methane, which all have value that could be incorporated into the break-even 

analysis. Figure 6-1 illustrates one method of analyzing the break-even point with alternate 

natural gas prices and VOC benefits. If, as an illustrative example, the price of natural gas was 

only $3.00 per Mcf, VOC would need to be valued at $220 per ton for the benefits to exceed the 

costs. All estimates are in 2008 dollars.

Figure 6-1 Illustrative Break-Even Diagram for Alternate Natural Gas Prices for the 

NSPS

With the data available, we are not able to provide a credible benefit-per-ton estimate for 

any of the pollutant reductions for these rules to compare to the break-even estimates. Based on 

the methodology from Fann, Fulcher, and Hubbell (2009), average PM2.5 health-related benefits 

of VOC emissions are valued at $280 to $7,000 per ton across a range of eight urban areas.53 In

addition, ozone benefits have been previously valued at $240 to $1,000 per ton of VOC reduced. 

 

53 See Section 4.5 of this RIA for more information regarding PM2.5 benefits and Section 4.6 for more information 

regarding ozone benefits.

$(1,000)

$(900)

$(800)

$(700)

$(600)

$(500)

$(400)

$(300)

$(200)

$(100)

$-

$100 

$200 

$300 

$400 

$500 

$600 

$- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 

VOC 

Cost-effectiveness ($/ton 

reduction) Natural Gas

Price ($/Mcf)

in 2015

EIA Forecast 

Price in 2015

($4.22/Mcf)

RIA Assumed 

Price in 2015

($4.00/Mcf)

CostEffectiveness

as Function of

NaturalGas

Price

Assumption
6-3

Using the GWP approach, the climate co-benefits range from approximately $110 to $1,400 per 

short ton of methane reduced depending upon the discount rate assumed with a per ton estimate 

of $760 at the 3 percent discount rate.

These break-even benefit-per-ton estimates assume that all other pollutants have zero 

value. Of course, it is inappropriate to assume that the value of reducing any of these pollutants 

is zero. Thus, the real break-even estimate is actually lower than the estimates provided above

because the other pollutants each have non-zero benefits that should be considered. 

Furthermore, a single pollutant can have multiple effects (e.g., VOC contribute to both ozone and 

PM2.5 formation that each have health and welfare effects) that would need to be summed in 

order to develop a comprehensive estimate of the monetized benefits associated with reducing 

that pollutant. 

As previously described, the revenue from additional natural gas recovery already 

exceeds the costs of the NSPS, but even if the price of natural gas was only $3.00 per Mcf, it is 

likely that the VOC benefits would exceed the costs, As a result, even if VOC emissions from 

oil and natural gas operations result in monetized benefits that are substantially below the 

average modeled benefits, there is a reasonable chance that the benefits of these rules would 

exceed the costs, especially if we were able to monetize all of the benefits associated with ozone 

formation, visibility, HAP, and methane. 

Table 6-1 and Table 6-2 present the summary of the benefits, costs, and net benefits for 

the NSPS and NESHAP Amendments, respectively. Table 6-3 provides a summary of the direct 

and secondary emissions changes for each rule.
6-4

Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil 

and Natural Gas NSPS in 2015 (millions of 2008$)1

Final4

Total Monetized Benefits2 N/A

Total Costs3 -$18 million

Net Benefits N/A

Non-monetized Benefits 19,000 tons of HAP5

290,000 tons of VOC

1.7 million tons of methane

Health effects of HAP exposure5

Health effects of PM2.5 and ozone exposure

Visibility impairment

Vegetation effects

Climate effects5

1 All estimates are for the implementation year (2015) and include estimated revenue from additional natural gas 

recovery as a result of the NSPS.

2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health 

effects associated with HAP, ozone, and particulate matter (PM) as well as climate effects associated with methane, 

we have determined that quantification of those benefits and co-benefits cannot be accomplished for this rule in a 

defensible way. This is not to imply that there are no benefits or co-benefits of the rules; 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. The specific control technologies for the final NSPS are anticipated to have minor 

secondary disbenefits, including an increase of 1.2 million tons of carbon dioxide (CO2), 630 tons of nitrogen oxides 

NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as well as emission reductions 

associated with the energy system impacts. The net CO2-equivalent (CO2-e) emission reductions are 31 million 

metric tons. 

3 The engineering compliance costs are annualized using a 7 percent discount rate. 

4 The negative cost for the NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon 

condensate recovery that are estimated as a result of the final NSPS. Possible explanations for why there appear to 

be negative cost control technologies are discussed in the engineering costs analysis section in the RIA. 

5 Reduced exposure to HAP and climate effects are co-benefits.
6-5

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

and Natural Gas NESHAP Amendments in 2015 (millions of 2008$)1

Final

Total Monetized Benefits2 N/A

Total Costs3 $18 million

Net Benefits N/A

Non-monetized Benefits 1,300 tons of HAP

9,000 tons of VOC4

4,800 tons of methane4

Health effects of HAP exposure

Health effects of PM2.5 and ozone exposure4

Visibility impairment4

Vegetation effects4

Climate effects4

1 All estimates are for the implementation year (2015).

2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health 

effects associated with HAP, ozone, and PM as well as climate effects associated with methane, we have 

determined that quantification of those benefits and co-benefits cannot be accomplished for this rule in a defensible 

way. This is not to imply that there are no benefits or co-benefits of the rules; 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. The specific control technologies for the NESHAP is anticipated to have minor 

secondary disbenefits, including an increase of 5,500 tons of CO2, 2.9 tons of NOx, 16 tons of CO, and 6.0 tons of 

total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO2-

equivalent emission reductions are 90,000 metric tons. 

3 The cost estimates are assumed to be equivalent to the engineering cost estimates. The engineering compliance 

costs are annualized using a 7 percent discount rate.

4 Reduced exposure to VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects, and climate 

effects are co-benefits.
6-6

Table 6-3 Summary of Emissions Changes for the Final Oil and Gas NSPS and 

NESHAP in 2015 (short tons per year)

Pollutant NSPS NESHAP

Change in Direct Emissions

VOC -290,000 -9,000

Methane -1,700,000 -4,800

HAP -19,000 -1,300

Change in Secondary Emissions (Producer-Side) 1

CO2 1,200,000 5,500

NOx 630 2.9

PM 19.0 0.1

CO 3,400 16

THC 1,300 6.0

Change in Secondary Emissions (Consumer-Side) CO2-e 600,000 N/A

Net Change in CO2-equivalent Emissions CO2-e

-34,000,000

(≈31,000,000 metric 

tons)

-95,000

(≈90,000 metric 

tons)
7-1

7 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS

7.1 Introduction

This section includes three sets of analyses for both the NSPS and NESHAP 

Amendments:

 Energy System Impacts

 Employment Impacts

 Small Business Impacts Analysis

7.2 Energy System Impacts Analysis of Final NSPS

We use the National Energy Modeling System (NEMS) to estimate the impacts of the 

final 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 NSPS might alter the mix of fuels 

consumed at a national level. With this information we estimate how the changed fuel mix 

affects national level CO2-equivalent greenhouse gas emissions from energy sources. We 

additionally combine these estimates of changes in CO2-equivalent greenhouse gas emissions 

from energy sources and emissions co-reductions of methane from the engineering analysis with 

NEMS analysis to estimate the net change in CO2-equivalent greenhouse gas emissions from 

energy-related sources, but this analysis is reserved for the secondary environmental impacts 

analysis within Section 4.

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 

results. Economically, it is possible to view the recovered natural gas as an explicit output or as 

contributing to an efficiency gain at the producer level. For example, the analysis for the final

NSPS shows that about 93 percent of the natural gas captured by emissions controls suggested 

by the rule is captured by performing RECs on new and existing wells that are completed after 
7-2

being hydraulically fractured. The assumed $4/Mcf price for natural gas is the price paid to 

producers at the wellhead. In the natural gas industry, production is metered at or very near to 

the wellhead, and producers are paid based upon this metered production. Depending on the 

situation, the gas captured by RECs is sent through a temporary or permanent meter. Payments 

for the gas are typically made within 30 days.

To preview the energy systems modeling using NEMS, results show that after economic 

adjustments to the new regulations are made by producers, the captured natural gas represents 

both increased output (a slight increment in aggregate production) and increased efficiency

(producing slightly more for less). However, because of differing objectives for the regulatory

analysis we treat the associated savings differently in the engineering cost analysis (as an explicit 

output) and in NEMS (as an efficiency gain).

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. NEMS is used to produce the 

Annual Energy Outlook, a reference publication that provides detailed forecasts of the energy
7-3

economy from the current year to 2035. DOE first developed NEMS in the 1980s, and the 

model has been undergone frequent updates and expansion since. DOE uses the modeling 

system extensively to produce issue reports, legislative analyses, and respond to Congressional 

inquiries. 

EIA is legally required to make the NEMS system source code available and fully

documented for the public. The source code and accompanying documentation is released 

annually when a new Annual Energy Outlook is produced. Because of the availability of the 

NEMS model, numerous agencies, national laboratories, research institutes, and academic and 

private-sector researchers have used NEMS to analyze a variety of issues.

NEMS models the dynamics of energy markets and their interactions with the broader 

U.S. economy. The system projects the production of energy resources such as oil, natural gas, 

coal, and renewable fuels, the conversion of resources through processes such as refining and 

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.doe.gov/oiaf/aeo/overview/index.html>.
7-4

Figure 7-1 Organization of NEMS Modules (source: U.S. Energy Information 

Administration)

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 2035. 

However, as this RIA is concerned with estimating regulatory impacts in the first year of full 

implementation, our analysis focuses upon estimated impacts in the year 2015, with regulatory

costs first imposed in 2011. For this RIA, we draw upon the same assumptions and model used 

in the Annual Energy Outlook 2011.54 The RIA baseline is consistent with that of the Annual 

Energy Outlook 2011 which is used extensively in Section 2 in the Industry Profile. 

 

54 Assumptions for the 2011 Annual Energy Outlook can be found at 

<http://www.eia.gov/forecasts/aeo/assumptions/index.cfm>. 
7-5

7.2.2 Inputs to National Energy Modeling System

To model potential impacts associated with the NSPS, 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, 2010). The treatment of oil and gas resources is detailed in that oil, shale oil, 

conventional gas, shale gas, tight sands gas, and coalbed methane (CBM) are explicitly modeled. 

New exploration and development is pursued in the OGSM if the expected net present value of 

extracted resources exceeds expected costs, including costs associated with capital, exploration, 

development, production, and taxes. Detailed technology and reservoir-level production 

economics govern finding and success rates and costs. 

The structure of the OGSM is amenable to analyzing potential impacts of the Oil and 

Natural Gas 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, as 

well as add additional costs to existing projects. 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 NSPS. However, we are unable to 

explicitly model the additional production of condensates expected to be recovered by reduced 

emissions completions, although we incorporate expected revenues from the condensate 

recovery in the economic evaluation of new drilling projects.

While the oil production simulated by the OGSM is sent to the refining module (the 

Petroleum 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 transmitted 

through a simplified arc-node representation of pipeline infrastructure based upon pipeline 

economics.
7-6

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 and future recompletions for new wells are added to drilling, 

completion, and stimulation costs, as these are, in effect, associated with activities that occur 

within a single time period, although they may be repeated periodically, as in the case of 

recompletions. Costs required for reduced emissions recompletions on existing wells are added 

to stimulation expenses for existing wells exclusively. Other costs are operations and 

maintenance-type costs and are added to fixed operation and maintenance (O&M) expenses 

associated with new projects. The one-shot and continuing O&M expenses are estimated and 

entered on a per well basis, depending on whether the costs would apply to oil wells, natural gas 

wells, both oil and natural gas wells, or a subset of either. We base the per well cost estimates on 

the engineering costs including revenues from additional product recovery. This approach is 

appropriate given the structure of the NEMS algorithm that estimates the net present value of 

drilling projects.

One concern in basing the regulatory costs inputs into NEMS on the net cost of the 

compliance activity (estimated annualized cost of compliance minus estimated revenue from 

product recovery) 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 retired capital. A caveat to this is that the estimated 

unit-level capital costs of controls which are newly required at a national-level as a result of the 

regulation—RECs, for example—may not incorporate potential additional transitional costs as 

the supply of control equipment adjusts to new demand.

Table 7-1 shows the incremental O&M expenses that accrue to new drilling projects as a 

result of producers having to comply with the NSPS. 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 
7-7

costs, we first identify which emissions reductions 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 2015, we used 19,097 new natural gas wells and 12,193 new oil wells 

as the basis of these calculations. We then divide the estimated compliance costs for the given 

emissions point (from Table 3-3) by the appropriate number of expected new wells in the year of 

analysis. The result yields an approximation of a per well compliance costs. We assume this 

approximation is representative of the incremental cost faced by a producer when evaluating a 

prospective drilling project.

Like the engineering analysis, we assume that hydraulically fractured well completions 

and recompletions will be required of wells drilled into tight sand, shale gas, and coalbed 

methane formations. While costs for well recompletions reflect the cost of a single 

recompletion, the engineering cost analysis assumed that one in one hundred new wells drilled 

after the implementation of the promulgation and implementation of the NSPS are completed 

using hydraulic fracturing will receive a recompletion in any given year using hydraulic 

fracturing. Meanwhile, within NEMS, wells are assumed to be stimulated every five years. We 

assume these more frequent stimulations are less intensive than stimulation using hydraulic 

fracturing but add costs such that the recompletions costs reflect the same assumptions as the 

engineering analysis. In entering compliance costs into NEMS, we also account for reduced 

emissions completions, completion combustion, and recompletions performed in absence of the 

regulation, using the same assumptions as the engineering costs analysis (Table 7-2). 
7-8

Table 7-1 Summary of Additional Annualized O&M Costs (on a Per New Well Basis)

for Environmental Controls Entered into NEMS

Emissions Sources/Points Emissions Control

Per Well Costs 

(2008$)

Wells Applied To in 

NEMS

Equipment Leaks

Well Pads Subpart VV Not in Final Oil and Gas

Gathering and Boosting Stations Subpart VV Not in Final Gas

Processing Plants Subpart VVa $14 None

Transmission Compressor Stations Subpart VV Not in Final Gas

Reciprocating Compressors

Well Pads Annual Monitoring/ 

Maintenance Not in Final None

Gathering/Boosting Stations AMM $10 Gas

Processing Plants AMM -$26 Gas

Transmission Compressor Stations AMM Not in Final Gas

Underground Storage Facilities AMM Not in Final Gas

Centrifugal Compressors

Processing Plants Dry Seals/Route to 

Process or Control -$37 Gas

Transmission Compressor Stations Dry Seals/Route to 

Process or Control Not in Final Gas

Pneumatic Controllers -

Oil and Gas Production Low Bleed/Route to 

Process -$695 Oil and Gas

Natural Gas Transmission and Storage Low Bleed/Route to 

Process Not in Final Gas

Storage Vessels

High Throughput 95% control $197 Oil and Gas

Low Throughput 95% control Not in Final None
7-9

Table 7-2 Summary of Additional Per Completion/Recompletion Costs (2008$) for 

Environmental Controls Entered into NEMS

Emissions 

Sources/Points Emissions Control

Per Completion Costs 

(2008$)

Wells Applied To in 

NEMS

Well Completions

Hydraulically Fractured 

Gas Wells REC -$828 New Tight Sand/ Shale 

Gas/CBM

Conventional Gas Wells Combustion Not in Final None

Oil Wells Combustion Not in Final None

Well Recompletions

Hydraulically Fractured 

Gas Wells (post-NSPS 

wells)

REC -$1,036

Existing Tight Sand/ 

Shale Gas /Coalbed 

Methane

Hydraulically Fractured 

Gas Wells (existing 

wells)

REC -$1,036

Existing Tight Sand/ 

Shale Gas /Coalbed 

Methane

Conventional Gas Wells Combustion Not in Final None

Oil Wells Combustion Not in Final None

7.2.2.2 Adding Averted Methane Emissions into Natural Gas Production

A significant benefit of controlling 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 

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 

final NSPS.

With the exception of recompletions on existing wells, we enter the increased natural gas 

recovery into NEMS on a per-well basis for new wells, following an estimation procedure 
7-10

similar to that of entering compliance costs into NEMS on a per well basis for new wells. For 

the final NSPS, we estimate that natural gas recovery is 5,065 Mcf per well. We make a 

simplifying assumption that natural gas recovery accruing to new wells accrues to new wells in 

shale gas, tight sands, and CBM fields. We make these assumptions because new wells in these 

fields are more likely to satisfy criteria such that RECs are required, which contributed that large 

majority of potential natural gas recovery. Note that these per well natural gas recovery is lower 

than the per well estimate when RECs are implemented. The estimate is lower because we 

account for emissions that are combusted, RECs that are implemented absent Federal regulation, 

as well as the likelihood that natural gas is used during processing and transmission or reinjected.

We treat the potential natural gas recovery associated with recompletions of existing 

wells differently in that we estimated the natural gas recovery by natural gas resource type based 

on a combination of the engineering analysis and production patterns from the 2011 Annual 

Energy Outlook. We estimate that additional natural gas product recovered by recompleting 

existing wells to be about 6.9 bcf, with 2.8 bcf accruing to shale gas, 3.4 bcf accruing to tight 

sands, and 0.8 bcf accruing to CBM, respectively (total may be different due to independent 

rounding). This quantity is distributed within the NGTDM to reflect regional production by

resource type.

7.2.2.3 Fixing Canadian Drilling Costs to Baseline Path

Domestic drilling costs serve as a proxy for Canadian drilling costs in the Canadian oil 

and natural gas sub-model within the NGTDM. This implies that, without additional 

modification, additional costs imposed by a U.S. regulation will also impact drilling decisions in 

Canada. Changes in international oil and gas trade are important in the analysis, as a large 

majority of natural gas imported into the U.S. originates in Canada. To avoid this problem, we 

fixed Canadian drilling costs using U.S. drilling costs from the baseline scenario. This solution 

enables a more accurate analysis of U.S.-Canada energy trade, as increased drilling costs in the 

U.S. as a result of environmental regulation serve to increase Canada’s comparative advantage.
7-11

7.2.3 Energy System Impacts

As mentioned earlier, we estimate impacts to drilling activity, reserves, 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, as well as whether and to what extent the NSPS 

might alter the mix of fuels consumed at a national level. In each of these estimates, we present 

estimates for the baseline year of 2015 and results for the NSPS. For context, we provide 

estimates of production activities in 2011.

7.2.3.1 Impacts on Drilling Activities

Because the potential costs of the NSPS are concentrated in production activities, we first 

report estimates of impacts on crude oil and natural gas drilling activities and production and 

price changes at the wellhead. Table 7-3 presents estimates of successful wells drilled in the 

U.S. in 2015, the analysis year.

Table 7-3 Successful Oil and Gas Wells Drilled, NSPS

Future Scenario, 2015

2011 Baseline Under Final NSPS

Successful Wells Drilled

Natural Gas 16,373 19,097 19,139

Crude Oil 10,352 11,025 11,025

Total 26,725 30,122 30,164

% Change in Successful Wells Drilled from Baseline

Natural Gas 0.22%

Crude Oil 0.00%

Total 0.14%

We estimate that the number of successful natural gas wells drilled increases slightly for the final 

NSPS, while the number of successful crude oil wells drilled does not change. The number of 

successful natural gas wells drilled is estimated to increase about 0.22%. Table 7-4 presents the 

forecast of successful wells by well type, for onshore drilling in the lower 48 states. The results 
7-12

show that conventional well drilling is unaffected by the NSPS, as reduced emission completion 

and completion combustion requirements are directed not toward wells in conventional reserves 

but toward wells that are hydraulically fractured, the wells in so-called unconventional reserves. 

The number of successful wells drilled increase in tight sands, shale gas, as well as coalbed 

methane.

Table 7-4 Successful Wells Drilled by Well Type (Onshore, Lower 48 States), NSPS

Future Scenario, 2015

2011 Baseline Under Final NSPS

Successful Wells Drilled

Conventional Gas Wells 7,267 7,607 7,607

Tight Sands 2,441 2,772 2,788

Shale Gas 5,007 7,022 7,030

Coalbed Methane 1,593 1,609 1,627

Total 16,308 19,010 19,052

% Change in Successful Wells Drilled from Baseline

Conventional Gas Wells 0.00%

Tight Sands 0.58%

Shale Gas 0.11%

Coalbed Methane 1.12%

Total 0.22%

Well drilling in tight sands is estimated to increase slightly, about 0.58 percent. Drilling in shale 

gas is forecast to increase from the baseline by 0.11 percent. Wells in CBM reserves are also 

estimated to increase from the baseline by 1.12 percent. 

7.2.3.2 Impacts on Production, Prices, and Consumption

Table 7-5 shows estimates of the changes in the domestic production of natural gas and 

crude oil under the NSPS, as of 2015. Domestic crude oil production is not forecast to change 

under the NSPS, again because impacts on crude oil drilling of the NSPS are expected to be 

negligible. 
7-13

Table 7-5 Annual Domestic Natural Gas and Crude Oil Production, NSPS

Future Scenario, 2015

2011 Baseline Under Final NSPS

Domestic Production

Natural Gas (trillion cubic feet) 21.05 22.43 22.49

Crude Oil (million barrels/day) 5.46 5.81 5.81

Natural Gas 0.27%

Crude Oil 0.00%

Natural gas production, on the other hand, increases from the baseline under the NSPS. A main 

driver for this increase is the additional natural gas recovery engendered by the control 

requirements. Another driver for the increases under the NSPS is the increase in natural gas well 

drilling. For the NSPS, the NEMS analysis shown in Table 7-5 estimates a 60 bcf increase in 

domestic natural gas production. This amount is less than the amount estimated in the 

engineering analysis to be captured by emissions controls implemented as a result of the NSPS 

(approximately 82 bcf). This difference is because NEMS models the adjustment of energy

markets to the now relatively more efficient natural gas production sector. At the new natural 

gas supply and demand equilibrium in 2015, the modeling estimates 60 bcf more gas is produced 

at a relatively lower wellhead price (which will be presented momentarily). However, at the new 

equilibrium, producers implementing emissions controls still capture and sell approximately 82

bcf of natural gas. For example, as shown in Table 7-4, about 11,400 new unconventional 

natural gas wells are completed under the final NSPS; using assumptions from the engineering 

cost analysis about RECs required under State regulations and exploratory wells and relatively 

low pressure wells exempted from REC requirements, about 8,750 NSPS-required RECs would 

be performed on new natural gas well completions, according to the NEMS analysis, not 

including the recompletions of existing wells. This recovered natural gas substitutes for natural 

gas that would be produced from the ground absent the rule. In effect, then, about 20 bcf of 

natural gas that would have been extracted and emitted into the atmosphere is left in the 

formation for future extraction.

As we showed for natural gas drilling, Table 7-6 shows natural gas production from 

onshore wells in the lower 48 states by type of well, predicted for 2015, the analysis year. 
7-14

Production from all types of wells is estimated to increase under the NSPS, with CBM increasing 

the most at 0.89 percent. 

Table 7-6 Natural Gas Production by Well Type (Onshore, Lower 48 States), NSPS

Future Scenario, 2015

2011 Baseline Under Final NSPS

Natural Gas Production by Well Type (trillion cubic feet)

Conventional Gas Wells 4.06 3.74 3.75

Tight Sands 5.96 5.89 5.93

Shale Gas 5.21 7.20 7.22

Coalbed Methane 1.72 1.67 1.68

Total 16.95 18.51 18.58

% Change in Natural Gas Production by Well Type from Baseline

Conventional Gas Wells 0.14%

Tight Sands 0.54%

Shale Gas 0.24%

Coalbed Methane 0.89%

Total 0.37%

Note: Totals may not sum due to independent rounding.

Table 7-7 presents estimates of national average wellhead natural gas and crude oil prices 

for onshore production in the lower 48 states, estimated for 2015, the year of analysis. Wellhead

natural gas and crude oil prices are forecast to decrease under the NSPS. The decrease in 

wellhead natural gas price form the baseline is attributable largely to the increased productivity 

of natural gas wells as a result of capturing a portion of completion and recompletion emissions.
7-15

Table 7-7 Lower 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS 

Future Scenario, 2015

2011 Baseline Under Final NSPS

Lower 48 Average Wellhead Price

Natural Gas (2008$ per Mcf) 4.07 4.22 4.17

Crude Oil (2008$ per barrel) 83.65 94.60 94.59

% Change in Lower 48 Average Wellhead Price from Baseline

Natural Gas -1.18%

Crude Oil -0.01%

Table 7-8 presents estimates of the price of natural gas to final consumers in 2008 dollars per 

million BTU. The production price decreases estimated as a result of the final NSPS are largely 

passed on to consumers but distributed unequally across consuming sectors. Electric power 

sector consumers of natural gas are estimated to receive the largest price decrease while the 

transportation and residential sectors are forecast to receive the smallest price decreases. 

Table 7-8 Delivered Natural Gas Prices by Sector (2008$ per million BTU), 2015, NSPS

Future Scenario, 2015

2011 Baseline Under Final NSPS

Delivered Prices (2008$ per million BTU)

Residential 10.52 10.35 10.30

Commercial 9.26 8.56 8.51

Industrial 4.97 5.08 5.04

Electric Power 4.81 4.77 4.73

Transportation 12.30 12.24 12.19

Average 6.76 6.59 6.55

% Change in Delivered Prices from Baseline

Residential -0.48%

Commercial -0.58%

Industrial -0.59%

Electric Power -0.84%

Transportation -0.41%

Average -0.61%
7-16

Final consumption of natural gas is also estimated to increase in 2015 from the baseline 

under the NSPS, as is shown on Table 7-9. Like delivered price, the consumption shifts are 

distributed differently across sectors. 

Table 7-9 Natural Gas Consumption by Sector, NSPS 

Future Scenario, 2015

2011 Baseline Under Final NSPS

Consumption (trillion cubic feet)

Residential 4.76 4.81 4.82

Commercial 3.22 3.38 3.38

Industrial 6.95 8.05 8.06

Electric Power 7.00 6.98 7.00

Transportation 0.03 0.04 0.04

Pipeline Fuel 0.64 0.65 0.65

Lease and Plant Fuel 1.27 1.20 1.21

Total 23.86 25.11 25.16

% Change in Consumption from Baseline

Residential 0.21%

Commercial 0.00%

Industrial 0.12%

Electric Power 0.29%

Transportation 0.00%

Pipeline Fuel 0.00%

Lease and Plant Fuel 0.83%

Total 0.20%

Note: Totals may not sum due to independent rounding.

7.2.3.3 Impacts on Imports and National Fuel Mix

The NEMS modeling estimates that the impact from the NSPS is not sufficiently large to 

affect the trade balance of natural gas. As shown in Table 7-10, estimates of crude oil imports do 

not vary from the baseline in 2015 under the NSPS. 
7-17

Table 7-10 Net Imports of Natural Gas and Crude Oil, NSPS

Future Scenario, 2015

2011 Baseline Under Final NSPS

Net Imports

Natural Gas (trillion cubic feet) 2.75 2.69 2.68

Crude Oil (million barrels/day) 9.13 8.70 8.70

% Change in Net Imports

Natural Gas -0.37%

Crude Oil 0.00%

Meanwhile, net imports of natural gas are estimated to decrease about 10 bcf (0.37 percent) 

under the NSPS, as the increased production substitutes for imported natural gas.

Table 7-11 evaluates estimates of energy consumption by energy type at the national 

level for 2015, the year of analysis. The NSPS is estimated to have small effects at the national 

level. We estimate an increase in 0.03 quadrillion BTU in 2015, a 0.03 percent increase. The 

percent contribution of natural gas is projected to increase, while the percent contribution of 

liquid fuels and coal is expected to decrease under the NSPS. 
7-18

Table 7-11 Total Energy Consumption by Energy Type (Quadrillion BTU), NSPS

Future Scenario, 2015

2011 Baseline Under Final NSPS

Consumption (quadrillion BTU)

Liquid Fuels 37.41 39.10 39.09

Natural Gas 24.49 25.77 25.82

Coal 20.42 19.73 19.71

Nuclear Power 8.40 8.77 8.77

Hydropower 2.58 2.92 2.92

Biomass 2.98 3.27 3.27

Other Renewable Energy 1.72 2.14 2.14

Other 0.30 0.31 0.31

Total 98.29 102.02 102.05

% Change in Consumption from Baseline

Liquid Fuels -0.03%

Natural Gas 0.19%

Coal -0.10%

Nuclear Power 0.00%

Hydropower 0.00%

Biomass 0.00%

Other Renewable Energy 0.00%

Other 0.00%

Total 0.03%

Note: Totals may not sum due to independent rounding.

With the national profile of energy consumption estimated to change slightly under the 

NSPS in 2015, the year of analysis, it is important to examine whether aggregate energy-related 

CO2-equivalent greenhouse gas (GHG) emissions also shift. A more detailed discussion of 

changes in CO2-equivalent GHG emissions from a baseline is presented within the benefits 

analysis in Section 4. Here, we present a single NEMS-based table showing estimated changes 

in energy-related “consumer-side” GHG emissions. We use the terms “consumer-side” 

emissions to distinguish emissions from the consumption of fuel from emissions specifically 

associated with the extraction, processing, and transportation of fuels in the oil and natural gas 

sector under examination in this RIA. We term the emissions associated with extraction, 

processing, and transportation of fuels “producer-side” emissions. 
7-19

Table 7-12 Modeled Change in Energy-related "Consumer-Side" CO2-equivalent GHG 

Emissions

Future Scenario, 2015

2011 Baseline Under Final NSPS

Energy-related CO2-equivalent GHG Emissions (million metric tons CO2-equivalent)

Petroleum 2,359.59 2,433.60 2,433.16

Natural Gas 1,283.78 1,352.20 1,354.69

Coal 1,946.02 1,882.08 1,880.57

Other 11.99 11.99 11.99

Total 5,601.39 5,679.87 5,680.41

% Change in Energy-related CO2-equivalent GHG Emissions from Baseline

Petroleum -0.02%

Natural Gas 0.18%

Coal -0.08%

Other 0.00%

Total 0.01%

Note: Excludes “producer-side” emissions and emissions reductions estimated to result from NSPS. Totals may not 

sum due to independent rounding.

As is shown in Table 7-12, the final NSPS is predicted to slightly increase consumer-side 

aggregate energy-related CO2-equivalent GHG emissions by about 540,000 metric tons (0.01 

percent), mainly because consumer-side emissions from natural gas combustion increase slightly

more than they are offset by reductions in petroleum and coal consumption.

7.3 Employment Impact Analysis

While a standalone analysis of employment impacts is not included in a standard costbenefit analysis, such an analysis is of particular concern in the current economic climate of 

sustained high unemployment. 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” (emphasis added). Therefore, we seek to inform 

the discussion of labor demand and job impacts by providing an estimate of the employment 

impacts of the regulations using labor requirements for the installation, operation, and 

maintenance of control requirements, as well as reporting and recordkeeping requirements. 
7-20

Unlike several recent RIAs, however, we do not provide employment impacts estimates based on 

the study by Morgenstern et al. (2002); we discuss this decision after presenting estimates of the 

labor requirements associated with reporting and recordkeeping and the installation, operation, 

and maintenance of control requirements.

7.3.1 Employment Impacts from Pollution Control Requirements

Regulations set in motion new orders for pollution control equipment and services. New 

categories of employment have been created in the process of implementing regulations to make 

our air safer to breathe. When a new regulation is promulgated, a response of industry is to order 

pollution control equipment and services in order to comply with the regulation when it becomes 

effective. Revenue and employment in the environmental technology industry have grown 

steadily between 2000 and 2008, reaching an industry total of approximately $300 billion in 

revenues and 1.7 million employees in 2008.55 While these revenues and employment figures 

represent gains for the environmental technologies industry, they are costs to the regulated 

industries required to install the equipment. Moreover, it is not clear the 1.7 million employees 

in 2008 represent new employment as opposed to workers being shifted from the production of 

goods and services to environmental compliance activities. 

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. Morgenstern 

et al. (2002) examined how regulated industries respond to regulation. They found that 

environmental regulations can have three distinct effects; the demand effect, the cost effect, and 

the factor substitution effect ...The authors found that, on average for the industries they studied, 

employment increases in regulated firms. Of course, these firms may also reassign existing 

employees to perform these activities.

 

55 In 2008, the industry totaled approximately $315 billion in revenues and 1.9 million employees including indirect 

employment effects, pollution abatement equipment production employed approximately 4.2 million workers in 

2008. These indirect employment effects are based on a multiplier for indirect employment = 2.24 (1982 value 

from Nestor and Pasurka - approximate middle of range of multipliers 1977-1991). Environmental Business 

International (EBI), Inc., San Diego, CA. Environmental Business Journal, monthly (copyright). 

http://www.ebiusa.com/ EBI data taken from the Department of Commerce International Trade Administration 

Environmental Industries Fact Sheet from April 2010: 

http://web.ita.doc.gov/ete/eteinfo.nsf/068f3801d047f26e85256883006ffa54/4878b7e2fc08ac6d85256883006c45

2c?OpenDocument
7-21

Environmental regulations support employment in many basic industries. 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. Bezdek et al. (2008) found that investments in environmental 

protection industries create jobs and displace jobs, but the net effect on employment is positive.

The focus of this part of the analysis is on labor requirements related to the compliance 

actions of the affected entities within the affected sector. We do not estimate any potential 

changes in labor outside of the oil and natural gas sector. This analysis estimates the 

employment impacts due to the installation, operation, and maintenance of control equipment, as 

well as employment associated with new reporting and recordkeeping requirements.

It is important to highlight that unlike the typical case where to reduce a bad output (i.e., 

emissions) a firm often has to reduce production of the good output, many of the emission 

controls required by the final NSPS will simultaneously increase production of the good output 

and reduce production of bad outputs. That is, these controls jointly produce environmental 

improvements and increase output in the regulated sector. New labor associated with 

implementing these controls to comply with the new regulations can also be viewed as additional 

labor increasing output while reducing undesirable emissions. To the extent, however, that these 

rules require unprofitable investments for some operations, there is the possibility that they may

cause fewer completions to be undertaken, and less gas production, thus creating downward 

pressure on labor demand, both in the regulated sector and on those sectors using natural gas as 

an input. This RIA excludes these potential adverse effects on the labor market.

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 U.S. EPA does not 

currently have this information. The employment analysis uses a bottom-up engineering-based 

methodology to estimate employment impacts. The engineering cost analysis summarized in 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 
7-22

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.

In other employment analyses U.S. EPA distinguished between employment changes 

within the regulated industry and those changes outside the regulated industry (e.g. a contractor 

from outside the regulated facility is employed to install a control device). For this regulation 

however, the structure of the industry makes this difficult. The mix of in-house versus 

contracting services used by firms is very case-specific in the oil and natural gas industry. For 

example, sometimes the owner of the well, processing plant, or transmission pipelines uses in–

house employees extensively in daily operations, while in other cases the owner relies on outside 

contractors for many of these services. For this reason, we make no distinction in the 

quantitative estimates between labor changes within and outside of the regulated sector.

The results of this employment estimate are presented in Table 7-13 for the final NSPS 

and in Table 7-14 for the final NESHAP Amendments. The tables breaks 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. For both 

the final NSPS and NESHAP Amendments, reporting and recordkeeping requirements were 

estimated for the entire rules rather than by anticipated control requirements; the reporting and 

recordkeeping estimates are consistent with estimates EPA submitted as part of its Information 

Collection Request (ICR). 

The up-front labor requirement is estimated at 50 FTEs for the final NSPS and about 120 

FTEs for the final NESHAP Amendments. These up-front FTE labor requirements can be 

viewed as short-term labor requirements required for affected entities to comply with the new 

regulation. Ongoing requirements are estimated at about 1,100 FTEs for the final NSPS and 

about 94 FTEs for the final NESHAP Amendments. These ongoing FTE labor requirements can 
7-23

be viewed as sustained labor requirements required for affected entities to continuously comply 

with the new regulation.

Two main categories contain the majority of the labor requirements for the final rules: 

implementing reduced emissions completions (RECs) and reporting and recordkeeping 

requirements for the final NSPS. Also, note that pneumatic controllers have no up-front 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 

the regulation. In this instance, we assume the incremental labor requirements are zero.

Implementing RECs are estimated to require about 1,000 FTE, about 88 percent of the 

total continuing labor requirements for the final NSPS.56 We denote REC-related requirements 

as continuing, or annual, as the REC requirements will in fact recur annually, albeit at different 

wells each year. The REC requirements are associated with certain new well completions or 

existing well recompletions, which while individual completions occur over a short period of 

time (days to a few weeks), new wells and other existing wells are completed or recompleted 

annually. Because of these reasons, we assume the REC-related labor requirements are annual.

7.3.2 Employment Impacts Primarily on the Regulated Industry

In previous RIAs, we transferred parameters from a study by Morgenstern et al. (2002) to 

estimate employment effects of new regulations. (See, for example, the Regulatory Impact 

Analysis for the finalized Mercury and Air Toxics Standards, promulgated on December 16, 

2011). The fundamental insight of Morgenstern, et al. is that environmental regulations can be 

understood as requiring regulated firms to add a new output (environmental quality) to their 

product mixes. Although legally compelled to satisfy this new demand, regulated firms have to 

finance this additional production with the proceeds of sales of their other (market) products.

Satisfying this new demand requires additional inputs, including labor, and may alter the relative 

proportions of labor and capital used by regulated firms in their production processes.

 

56 As shown on earlier in this section, we project that the number of successful natural gas wells drilled in 2015 will 

decline slightly from the baseline projection. Therefore, there may be small employment losses in drillingrelated employment that partly offset gains in employment from compliance-related activities.
7-24

Using plant-level Census information between the years 1979 and 1991, Morgenstern et 

al. estimate the size of each effect for four polluting and regulated industries (petroleum refining, 

plastic material, pulp and paper, and steel). On average across the four industries, each additional 

$1 million (1987$) spending on pollution abatement results in a (statistically insignificant) net 

increase of 1.55 (+/- 2.24) jobs. As a result, the authors conclude that increases in pollution 

abatement expenditures did not necessarily cause economically significant employment changes

in those industries at that time.

For this version of RIA for the final NSPS and NESHAP Amendments, however, we 

chose not to quantitatively estimate employment impacts using Morgenstern et al. because of 

reasons specific to the oil and natural gas industry and final rules. We believe the transfer of 

parameter estimates from the Morgenstern et al. study to the final NSPS and NESHAP 

Amendments is beyond the range of the study for two reasons. 
7-25

Table 7-13 Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and 

Maintaining Control Equipment Requirements, NSPS, 2015

Source/Emissions Point Emissions Control

Projected 

No. of 

Affected 

Units

Per Unit 

Onetime 

Labor 

Estimate 

(hours)

Per Unit 

Annual 

Labor 

Estimate 

(hours)

Total 

OneTime 

Labor 

Estimate 

(hours)

Total 

Annual 

Labor

Estimate 

(hours)

One-time 

Full-Time 

Equivalent

Annual 

Full-Time 

Equivalent

Well Completions and Recompletions

New Hydraulically Fractured Gas Wells

Reduced Emissions 

Completion (REC) 8,382 0 218 0 1,823,282 0.0 876.6

Existing Hydraulically Fractured Gas Wells REC 1,085 0 218 0 235,901 0.0 113.4

Hydraulically Fractured Gas Wells Combustion 1,498 0 22 0 32,327 0.0 15.5

Equipment Leaks

Processing Plants

NSPS Subpart 

VVA 29 587 887 17,023 25,723 8.2 12.4

Reciprocating Compressors

Gathering/Boosting Stations

Annual 

Monitoring/ 

Maintenance 

(AMM) 210 1 1 210 210 0.1 0.1

Processing Plants AMM 209 1 1 209 209 0.1 0.1

Centrifigal Compressors

Processing Plants

Dry Seals/Route to 

Process or Control 13 355 0 4,615 0 2.2 0.0

Pneumatic Controllers

Oil and Gas Production

Low Bleed/Route 

to Process 13,632 0 0 0 0 0.0 0.0

Storage Vessels

High Throughput 95% control 304 271 190 82,279 57,582 39.6 27.7

Reporting and Recordkeeping for Complete NSPS All N/A N/A 0 229,810 0.0 102.5

TOTAL N/A N/A N/A 104,336 2,405,045 50.2 1,148.3

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.
7-26

Table 7-14 Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and 

Maintaining Control Equipment Requirements, Final NESHAP Amendments, 2015

Source/Emissions Point Emissions Control

Projected 

No. of 

Affected 

Units

Per Unit 

One-time 

Labor 

Estimate 

(hours)

Per Unit 

Annual 

Labor 

Estimate 

(hours)

Total OneTime Labor 

Estimate 

(hours)

Total 

Annual 

Labor 

Estimate 

(hours)

One-time 

Full-Time 

Equivalent

Annual 

Full-Time 

Equivalent

Small Glycol Dehydrators 

Production

Combustion devices, recovery devices, 

process modifications 74 27 285 2,000 21,120 1.0 10.2

Transmission

Combustion devices, recovery devices, 

process modifications 7 27 285 189 1,998 0.1 1.0

Storage Vessels

Production Combustion devices, recovery devices 674 311 198 209,753 133,231 100.8 64.1

Reporting and Recordkeeping for Complete NESHAP Amendments N/A N/A N/A 36,462 39,923 17.5 19.2

TOTAL 808 N/A N/A 248,404 196,272 119.4 94.4

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.
7-27

First, the possibility that the revenues producers are estimated to receive from additional natural 

gas recovery as a result of the final NSPS might offset the costs of complying with the rule 

presents challenges to estimating employment effects (see Section 3.2.2.1 of the RIA for a 

detailed discussion of the natural gas recovery). The Morgenstern et al. paper, for example, is 

intended to analyze the impact of environmental compliance expenditures on industry

employment levels, and it may not be appropriate to draw on their demand and net effects when 

compliance costs are expected to be negative. 

Second, the final regulations primarily affect the natural gas production, processing, and 

transmission segments of the industry. While the natural gas processing segment of the oil and 

natural gas industry is similar to petroleum refining, which is examined in Morgenstern et al., the 

production side of the oil and natural gas (drilling and extraction, primarily) and natural gas 

pipeline transmission are not similar to petroleum refining. Because of the likelihood of negative 

compliance costs for the final NSPS and the segments of the oil and natural gas industry affected 

by the rules are not examined by Morgenstern et al., we decided not to use the parameters 

estimated by Morgenstern et al. to estimate within-industry employment effects for the final oil 

and natural gas NESHAP Amendments and NSPS. 

That said, the likelihood of additional natural gas recovery is an important component of 

the market response to the rule, as it is expected that this additional natural gas recovery will 

reduce the price of natural gas. Because of the estimated fall in prices in the natural gas sector 

due to the final NSPS, prices in other sectors that consume natural gas are likely drop slightly

due to the decrease in energy prices. This small production increase and price decrease may

have a slight stimulative effect on employment in industries that consume natural gas.

7.4 Small Business Impacts Analysis

The Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement 

Fairness Act (SBREFA) 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 
7-28

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

small businesses, small governmental jurisdictions, and small not-for-profit enterprises.

After considering the economic impact of the final rules on small entities for both the 

NESHAP and NSPS, the analysis indicates that these rules will not have a significant economic 

impact on a substantial number of small entities (or “SISNOSE”). The supporting analyses for 

these determinations are presented in this section of the RIA.

As discussed in previous sections of the economic impact analysis, under the final NSPS, 

some affected producers are likely to be able to recover natural gas that would otherwise be 

vented to the atmosphere, as well as recover saleable condensates that would otherwise be 

emitted. EPA estimates that the revenues from this additional natural gas product recovery will 

offset the costs of implementing control options implemented as a result of the final NSPS. 

However, not all components of the final NSPS are estimated to have cost savings. Therefore, 

we analyze potential impacts to better understand the potential distribution of impacts across 

industry segments and firms. Unlike the controls for the final NSPS, the controls evaluated 

under the final NESHAP Amendments do not recover significant quantities of natural gas 

products. 

7.4.1 Small Business National Overview

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

the engineering cost analysis. The U.S. Census Bureau’s Statistics of U.S. Businesses (SUSB) 

provides national information on the distribution of economic variables by industry and 

enterprise size. The Census Bureau and the Office of Advocacy of the Small Business 

Administration (SBA) supported and developed these files for use in a broad range of economic 

analyses.

57 Statistics include the total number of establishments, and receipts for all entities in an 

industry; however, many of these entities may not necessarily be covered by the final rule. SUSB 

also provides statistics by enterprise employment and receipt size (Table 7-15 and Table 7-16). 

The Census Bureau’s definitions used in the SUSB are as follows:

 

57See http://www.census.gov/csd/susb/ and http://www.sba.gov/advocacy/ for additional details.
7-29

 Establishment: A single physical location where business is conducted or where 

services or industrial operations are performed. 

 Firm: A firm is a business organization consisting of one or more domestic 

establishments in the same state and industry that were specified under common 

ownership or control. The firm and the establishment are the same for singleestablishment firms. For each multi-establishment firm, establishments in the same 

industry within a state will be counted as one firm- the firm employment and annual 

payroll are summed from the associated establishments.

 Receipts: Receipts (net of taxes) are defined as the revenue for goods produced, 

distributed, or services provided, including revenue earned from premiums, 

commissions and fees, rents, interest, dividends, and royalties. Receipts exclude all 

revenue collected for local, state, and federal taxes. 

 Enterprise: An enterprise is a business organization consisting of one or more 

domestic establishments that were specified under common ownership or control. The 

enterprise and the establishment are the same for single-establishment firms. Each 

multi-establishment company forms one enterprise—the enterprise employment and 

annual payroll are summed from the associated establishments. Enterprise size 

designations are determined by the sum of employment of all associated 

establishments.

Because the SBA’s business size definitions (SBA, 2008) apply to an establishment’s “ultimate 

parent company,” we assumed in this analysis that the “firm” definition above is consistent with 

the concept of ultimate parent company that is typically used for SBREFA analyses, and the 

terms are used interchangeably. 
7-30

Table 7-15 Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007

Owned by Firms with:

NAICS NAICS Description

SBA Size 

Standard 

(effective 

Nov. 5, 

2010)

< 20 

Employees 

20-99 

Employees 

100-499 

Employees 

Total < 

500 

Employees 

> 500 

Employees Total Firms

Number of Firms by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 500 5,759 455 115 6,329 95 6,424

211112 Natural Gas Liquid Extraction 500 77 9 12 98 41 139

213111 Drilling Oil and Gas Wells 500 1,580 333 97 2,010 49 2,059

486210 Pipeline Transportation of Natural Gas $7.0 million 63 12 9 84 42 126

Total Employment by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 500 21,170 16,583 17,869 55,622 77,664 133,286

211112 Natural Gas Liquid Extraction 500 372 305 1,198 1,875 6,648 8,523

213111 Drilling Oil and Gas Wells 500 5,972 13,787 16,893 36,652 69,774 106,426

486210 Pipeline Transportation of Natural Gas $7.0 million 241 382 1,479 2,102 22,581 24,683

Estimated Receipts by Firm Size ($1000)

211111 Crude Petroleum and Natural Gas Extraction 500 12,488,688 15,025,443 17,451,805 44,965,936 149,141,316 194,107,252

211112 Natural Gas Liquid Extraction 500 209,640 217,982 1,736,706 2,164,328 37,813,413 39,977,741

213111 Drilling Oil and Gas Wells 500 1,101,481 2,460,301 3,735,652 7,297,434 16,550,804 23,848,238

486210 Pipeline Transportation of Natural Gas $7.0 million 332,177 518,341 1,448,020 2,298,538 18,498,143 20,796,681

Source: U.S. Census Bureau. 2010. “Number of Firms, Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterprise Receipt Size for the 

United States, All Industries: 2007.” <http://www.census.gov/econ/susb/>
7-31

Table 7-16 Distribution of Small and Large Firms by Number of Firms, Total 

Employment, and Estimated Receipts by Firm Size and NAICS, 2007

Percent of Firms

NAICS NAICS Description Total Firms

Small 

Businesses 

Large 

Businesses Total Firms

Number of Firms by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 6,424 98.5% 1.5% 100.0%

211112 Natural Gas Liquid Extraction 139 70.5% 29.5% 100.0%

213111 Drilling Oil and Gas Wells 2,059 97.6% 2.4% 100.0%

486210 Pipeline Transportation of Natural Gas 126 48.4% 51.6% 100.0%

Total Employment by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 133,286 41.7% 58.3% 100.0%

211112 Natural Gas Liquid Extraction 8,523 22.0% 78.0% 100.0%

213111 Drilling Oil and Gas Wells 106,426 34.4% 65.6% 100.0%

486210 Pipeline Transportation of Natural Gas 24,683 N/A* N/A* N/A*

Estimated Receipts by Firm Size ($1000)

211111 Crude Petroleum and Natural Gas Extraction 194,107,252 23.2% 76.8% 100.0%

211112 Natural Gas Liquid Extraction 39,977,741 5.4% 94.6% 100.0%

213111 Drilling Oil and Gas Wells 23,848,238 30.6% 69.4% 100.0%

486210 Pipeline Transportation of Natural Gas 20,796,681 N/A* N/A* N/A*

Note: Employment and receipts could not be broken down between small and large businesses because of nondisclosure requirements.

Source: SBA

While the SBA and Census Bureau statistics provide informative broad contextual 

information on the distribution of enterprises by receipts and number of employees, it is also 

useful to additionally contrast small and large enterprises (where large enterprises are defined as 

those that are not small, according to SBA criteria) in the oil and natural gas industry. The 

summary statistics presented in previous tables indicate that there are a large number of 

relatively small firms and a small number of large firms. Given the majority of expected impacts 

of the final rules arises from well completion-related requirements, which impacts production 

activities, exclusively, some explanation of this particular market structure is warranted as it 

pertains to production and small entities. An important question to answer is whether there are 

particular roles that small entities serve in the production segment of the oil and natural gas 

industry that may be disproportionately affected by the final rules.
7-32

The first important broad distinction among firms is whether they are independent or 

integrated. Independent firms concentrate on exploration and production (E&P) activities, while 

integrated firms are vertically integrated and often have operations in E&P, processing, refining, 

transportation, and retail. To our awareness, there are no small integrated firms. Independent 

firms may own and operate wells or provide E&P-related services to the oil and gas industry. 

Since we are focused on evaluating potential impacts to small firms owning and operating new 

and existing hydraulically fractured wells, we should narrow down on this sector. 

In our understanding, there is no single industry niche for small entities in the production 

segment of the industry since small operators have different business strategies and that small 

entities can own different types of wells. The organization of firms in oil and natural gas 

industry also varies greatly from firm to firm. Additionally, oil and natural gas resources vary

widely geographically and can vary significantly within a single field. 

Among many important roles, independent small operators historically pioneered 

exploration in new areas, as well as developed new technologies. By taking on these relatively 

large risks, these small entrepreneurs (wildcatters) have been critical sources of industrial 

innovation and opened up critical new energy supplies for the U.S. (IHS Global Insight). In 

recent decades, as the oil and gas industry has concentrated via mergers, many of these smaller 

firms have been absorbed into large firms. 

Another critical role, which provides an interesting contrast to small firms pioneering 

new territory, is that smaller independents maintain and operate a large proportion of the 

Nation’s low producing wells, which are also known as marginal or stripper wells (Duda et al. 

2005). While marginal wells represent about 80 percent of the population of producing wells, 

they produce about 15 percent of domestic production, according to EIA (Table 7-17).
7-33

Table 7-17 Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009

Type of Wells Wells (no.) Wells (%)

Production 

(MMbbl for oil 

and Bcf gas) Production (%)

Crude Oil

Stripper Wells (<15 boe per year) 310,552 85% 311 19%

Other Wells (>=15 boe per year) 52,907 15% 1,331 81%

Total Crude Oil Wells 363,459 100% 1,642 100%

Natural Gas

Natural Gas Stripper Wells (<15 boe per year) 338,056 73% 2,912 12%

Other Natural Gas Wells (>=15 boe per year) 123,332 27% 21,048 88%

Total Natural Gas Wells 461,388 100% 23,959 100%

Source: U.S. Energy Information Administration, Distribution of Wells by Production Rate Bracket.

<http://www.eia.gov/pub/oil_gas/petrosystem/us_table.html> Accessed 7/10/11.

Note: Natural gas production converted to barrels oil equivalent (boe) uses the conversion of 0.178 barrels of crude 

oil to 1000 cubic feet natural gas.

Many of these wells were likely drilled and initially operated by major firms (although 

the data are not available to quantify the percentage of wells initially drilled by small versus 

large producers). Well productivity levels typically follow a steep decline curve; high 

production in earlier years but sustained low production for decades. Because of relatively low 

overhead of maintaining and operating few relatively co-located wells, some small operators 

with a particular business strategy purchase low producing wells from the majors, who 

concentrate on new opportunities. As small operators have provided important technical 

innovation in exploration, small operators have also been sources of innovation in extending the 

productivity and lifespan of existing wells (Duda et al. 2005).

7.4.2 Small Entity Economic Impact Measures

The final Oil and Natural Gas NSPS and NESHAP Amendments will affect the owners of 

the facilities that will incur compliance costs to control their regulated emissions. The owners, 

either firms or individuals, are the entities that will bear the financial impacts associated with 

these additional operating costs. The final rule has the potential to impact all firms owning 

affected facilities, both large and small. 
7-34

The analysis provides EPA with an estimate of the magnitude of impacts the final NSPS 

and NESHAP Amendments may have on the ultimate domestic parent companies that own 

facilities EPA expects might be impacted by the rules. The analysis focuses on small firms 

because they may have more difficulty complying with a new regulation or affording the costs 

associated with meeting the new standard. This section presents the data sources used in the 

analysis, the methodology we applied to develop estimates of impacts, the results of the analysis, 

and conclusions drawn from the results. 

The small business impacts analysis for the NSPS and NESHAP Amendments relies 

upon a series of firm-level sales tests (represented as cost-to-revenue ratios) for firms that are 

likely to be associated with NAICS codes listed in Table 7-15. For both the NSPS and NESHAP 

Amendments, we obtained firm-level employment, revenues, and production levels using various 

sources, including the American Business Directory, the Oil and Gas Journal, corporate 

websites, and publically-available financial reports. Using these data, we estimated firm-level 

compliance cost impacts and calculated cost-to-revenue ratios to identify small firms that might 

be significantly impacts by the rules. The approaches taken for the NSPS and NESHAP 

Amendments differed; more detail on approaches for each set of rules is presented in the

following sections.

For the sales test, we divided the estimates of annualized establishment compliance costs 

by estimates of firm revenue. This is known as the cost-to-revenue ratio, or the “sales test.” The 

“sales test” is the impact methodology EPA employs in analyzing small entity impacts as

opposed to a “profits test,” in which annualized compliance costs are calculated as a share of 

profits. The sales test is often used because revenues or sales data are commonly available for 

entities impacted by EPA regulations, and profits data normally made available are often not the 

true profit earned by firms because of accounting and tax considerations. Revenues as typically

published are correct figures and are more reliably reported when compared to profit data. The 

use of a “sales test” for estimating small business impacts for a rulemaking such as this one is 

consistent with guidance offered by EPA on compliance with SBREFA58 and is consistent with 

guidance published by the U.S. SBA’s Office of Advocacy that suggests that cost as a percentage 

 

58 The SBREFA compliance guidance to EPA rulewriters regarding the types of small business analysis that should 

be considered can be found at <http://www.epa.gov/sbrefa/documents/rfaguidance11-00-06.pdf>
7-35

of total revenues is a metric for evaluating cost increases on small entities in relation to increases 

on large entities (U.S. SBA, 2010).

598

7.4.3 Small Entity Economic Impact Analysis, Final NSPS

7.4.3.1 Overview of Sample Data and Methods

The final NSPS covers emissions points within various stages of the oil and natural gas 

production process. We expect that firms within multiple NAICS codes will be affected, namely 

the NAICS categories presented in Table 7-15. Because of the diversity of the firms potentially 

affected, we decided to analyze three distinct groups of firms within the oil and natural gas 

industry, while accounting for overlap across the groups. We analyze firms that are involved in 

oil and natural gas extraction that are likely to drill and operate wells, while a subset are 

integrated firms involved in multiple segments of production, as well as retailing products. We 

also analyze firms that primarily operate natural gas processing plants. A third set of firms we 

analyzed contains firms that primarily operate natural gas compression and pipeline 

transmission.

To identify firms involved in the drilling and primary production of oil and natural gas, 

we relied upon the annual Oil and Gas Journal 150 Survey (OGJ 150) as described in the 

Industry Profile in Section 2. While the OGJ 150 lists public firms, we believe the list is 

reasonably representative of the larger population of public and private firms operating in this 

segment of the industry. While the proportion of small firm in the OGJ 150 is smaller than the 

proportion evaluated by the Census SUSB, the OGJ 150 provides detailed information on the 

production activities and financial returns of the firms within the list, which are critical 

ingredients to the small business impacts analysis. We drew upon the OGJ 150 lists published 

for the years 2008 and 2009 (Oil and Gas Journal, September 21, 2009 and Oil and Gas Journal, 

September 6, 2010). The year 2009 saw relatively low levels of drilling activities because of the 

economic recession, while 2008 saw a relatively high level of drilling activity because of high 

fuel prices. Combined, we believe these two years of data are representative. 

 

59U.S. SBA, Office of Advocacy. A Guide for Government Agencies, How to Comply with the Regulatory 

Flexibility Act, Implementing the President’s Small Business Agenda and Executive Order 13272, June 2010.
7-36

To identify firms that process natural gas, 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 the most recent list of U.S. gas processing facilities60 and other 

resources, such as the American Business Directory and company websites, to best identify the 

parent company of the facilities. To identify firms that compress and transport natural gas via 

pipelines, we examined the periodic OGJ survey 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.

61 For these firms, we also used the American Business Directory and corporate 

websites to best identify the ultimate owner of the facilities or companies.

After combining the information for exploration and production firms, natural gas 

processing firms, and natural gas pipeline transmission firms in order to identify overlaps across 

the list, the approach yielded a sample of 274 firms that would potentially be affected by the final 

NSPS in 2015 assuming their 2015 production activities were similar to those in 2008 and 2009. 

We estimate that 127 (46 percent) of these firms are small according to SBA criteria. We 

estimate 119 firms (43 percent) are not small firms according to SBA criteria. We are unable to 

classify the remaining 28 firms (10 percent) because of a lack of required information on 

employee counts or revenue estimates.

Table 7-18 shows the estimated revenues for 246 firms for which we have sufficient data 

that would be potentially affected by the final NSPS based upon their activities in 2008 and 

2009. We segmented the sample into four groups, production and integrated firms, processing 

firms, pipeline firms, and pipelines/processing firms. For the firms in the pipelines/processing 

group, we were unable to determine the firms’ primary line of business, so we opted to group 

together as a fourth group.

 

60 Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing 

Capacity Ahead in 2009.” June 7, 2010.

61 Oil and Gas Journal. “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow.” 

November 1, 2010.
7-37

Table 7-18 Estimated Revenues for Firms in Sample, by Firm Type and Size

Number of Firms

Estimated Revenues (millions, 2008 dollars)

Firm Type/Size Total Average Median Minimum Maximum

Production and Integrated

Small 77 18,451.9 239.6 76.3 0.1 1,116.9

Large 47 1,345,292.0 28623.2 1,788.3 12.9 310,586.0

Subtotal 124 1,363,743.9 10,997.9 344.6 0.1 310,586.0

Pipeline

Small 11 694.5 63.1 4.6 0.5 367.0

Large 36 166,290.2 4,619.2 212.9 7.1 112,493.0

Subtotal 47 166,984.6 3,552.9 108.0 0.5 112,493.0

Processing

Small 39 4,972.1 127.5 26.9 1.9 1,459.1

Large 23 177,632.1 8,881.6 2,349.4 10.4 90,000.0

Subtotal 62 182,604.2 3,095.0 41.3 1.9 90,000.0

Pipelines/Processing

Small 0 N/A N/A N/A N/A N/A

Large 13 175,128.5 13,471.4 6,649.4 858.6 71,852.0

Subtotal 13 175,128.5 13,471.4 6,649.4 858.6 71,852.0

Total

Small 127 24,118.5 189.9 34.9 0.1 1,459.1

Large 119 1,864,342.8 16,071.9 1,672.1 7.1 310,586.0

Total 246 1,888,461.3 7,771.4 164.9 0.1 310,586.0

Sources: Oil and Gas Journal. “OGJ150.” September 21, 2009; Oil and Gas Journal. “OGJ150 Financial Results 

Down in '09; Production, Reserves Up.” September 6, 2010. 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. Oil and Gas Journal. “Natural Gas Pipelines Continue Growth 

Despite Lower Earnings; Oil Profits Grow.” November 1, 2010. American Business Directory was used to 

determine number of employees.

As shown in Table 7-18, there is a wide variety of revenue levels across firm size, as well as 

across industry segments. The estimated revenues within the sample are concentrated on 

integrated firms and firms engaged in production activities (the E&P firms mentioned earlier).
7-38

The oil and natural gas industry is capital-intensive. To provide more context on the 

potential impacts of new regulatory requirements, Table 7-19 presents descriptive statistics for 

small and large integrated and production firms from the sample of firms (117 of the 124 

integrated and production firms listed in the Oil and Gas Journal; capital and exploration 

expenditures for 7 firms were not reported in the Oil and Gas Journal).

Table 7-19 Descriptive Statistics of Capital and Exploration Expenditures, Small and 

Large Firms in Sample, 2008 and 2009 (million 2008 dollars)

Capital and Exploration Expenditures (millions, 2008 dollars)

Firm Size Number Total Average Median Minimum Maximum

Small 74 13,262.9 179.2 60.4 0.1 2,401.9

Large 43 127,505.6 2,965.2 982.7 0.1 22,518.7

Total 117 140,768.5 1,203.1 192.8 0.1 22,518.7

Sources: Oil and Gas Journal. “OGJ150.” September 21, 2009; Oil and Gas Journal. “OGJ150 Financial Results 

Down in '09; Production, Reserves Up.” September 6, 2010. American Business Directory was used to 

determine number of employees.

The average 2008 and 2009 total capital and exploration expenditures for the sample of 117 

firms were approximately $140 billion in 2008 dollars). About 9 percent of this total was spent 

by small firms. Average capital and explorations expenditures for small firms are about 6 

percent of large firms; median expenditures of small firms are about 6 percent of large firms’ 

expenditures. For small firms, capital and exploration expenditures are high relative to revenue, 

which appears to hold true more generally for independent E&P firms compared to integrated 

major firms. This would seem to indicate the capital-intensive nature of E&P activities. As 

expected, this would drive up ratios comparing estimated engineering costs to revenues and 

capital and exploration expenditures. 

Table 7-20 breaks down the estimated number of natural gas and crude oil wells drilled 

by the 121 firms in the sample for which the Oil and Gas Journal information reported welldrilling estimates. Note the fractions on the minimum and maximum statistics; the fractions 

reported are due to our assumptions to estimate oil and natural gas wells drilled from the total 

wells drilled reported by the Oil and Gas Journal. The OGJ150 lists new wells drilled by firm in 

2008 and 2009, but the drilling counts are not specific to crude oil or natural gas wells. We 
7-39

apportion the wells drilled to natural gas and crude oil wells using the distribution of well drilling 

in 2009 (63 percent natural gas and 37 percent oil). 

Table 7-20 Descriptive Statistics of Estimated Wells Drilled, Small and Large Firms in 

Sample, 2008 and 2009 (million 2008 dollars)

Estimated Average Wells Natural Gas and Crude Oil Wells Drilled 

(2008 and 2009)

Well Type Firm Size Number of Firms Total Average Median Minimum Maximum

Natural Gas

Small 77 2,049.5 26.6 5.7 0.2 259.3

Large 44 9,723.1 221.0 153.2 0.6 868.3

Subtotal 121 11,772.5 97.3 28.3 0.2 868.3

Crude Oil

Small 77 1179.6 15.3 3.3 0.1 149.2

Large 44 5596.3 127.2 88.1 0.4 499.7

Subtotal 121 6,775.9 56.0 16.3 0.1 499.7

Total

Small 7 3,229.1 41.9 9.0 0.3 408.5

Large 44 15,319.4 348.2 241.3 1.0 1,368.0

Total 121 18,548.4 153.3 44.6 0.3 1,368.0

Sources: Oil and Gas Journal. “OGJ150.” September 21, 2009; Oil and Gas Journal. “OGJ150 Financial Results 

Down in '09; Production, Reserves Up.” September 6, 2010. American Business Directory was used to 

determine number of employees.

This table highlights the fact that many firms drill relatively few wells; the median for small 

firms is approximately 6 natural gas wells compared to 153 for large firms. Later in this section, 

we examine whether this distribution has implications for the engineering costs estimates, as well 

as the estimates of expected natural product recovery from controls such as RECs.

Unlike the analysis that follows for the analysis of impacts on small business from the 

NESHAP Amendments, we have no specific data on potentially affected facilities under the 

NSPS. The NSPS will apply to new and modified sources, for which data are not fully available 

in advance, particularly in the case of new and modified sources such as well completions and 

recompletions which are spatially diffuse and potentially large in number. 

The engineering cost analysis estimated compliance costs in a top-down fashion, 

projecting the number of new sources at an annual level and multiplying these estimates by
7-40

model unit-level costs to estimate national impacts. To estimate per-firm compliance costs in 

this analysis, we followed a procedure similar to that of entering estimate compliance costs in 

NEMS on a per well basis. We first use the OGJ150-based list to estimate engineering 

compliance costs for integrated and production companies that may operate facilities in more 

than one segment of the oil and natural gas industry. We then estimate the compliance costs per 

crude oil and natural gas well by totaling all compliance costs estimates in the engineering cost 

estimates for the final NSPS and dividing that cost by the total number of crude oil and natural 

gas wells forecast as of 2015, the year of analysis. These compliance costs include the expected 

revenue from natural gas and condensate recovery that result from implementation of some 

controls. 

This estimation procedure yielded an estimate of crude oil well compliance costs of $225 

per drilled well and natural gas well compliance costs of $17,500 without considering estimated 

revenues from product recovery and $225 and -$1070 per drilled crude oil and natural gas well, 

respectively, with estimated revenues from product recovery included. Note that the divergence 

of estimated per well costs between crude oil and natural gas wells is because the final NSPS 

requirements are primary directed toward natural gas wells. Also note that the per well cost 

savings estimate for natural gas wells is different than the estimated cost of implementing a 

REC; this difference is because this estimate is picking up savings from other control options. 

We then estimate a single-year, firm-level compliance cost for this subset of firms by

multiplying the per well cost estimates with the well count estimates.

The OGJ reports plant processing capacity in terms of MMcf/day. In the energy system 

impacts analysis, the NEMS model estimates a 6.5 percent increase (from 21.05 tcf in 2011 to 

22.43 tcf in 2015) in domestic natural gas production from 2011 to 2015, the analysis year. On 

this, basis, we estimate that natural gas processing capacity for all plants in the OGJ list will 

increase 1.3 percent per year. This annual increment is equivalent to an increase in national gas 

processing capacity of 350 bcf per year. We assume that the engineering compliance costs 

estimates associated with processing are distributed according to the proportion of the increased 

national processing capacity contributed by each processing plant. These costs are estimated at 

$7.2 million without estimated revenues from product recovery and $6.2 with estimated revenues 
7-41

from product recovery, respectively, in 2008 dollars, or about $21/MMcf without revenues and 

$17/MMcf with revenues. 

The OGJ report on pipeline companies has the advantage that it reports expenditures on 

plant additions. We assume that the firm-level compression and transmission-related NSPS 

compliance costs are proportional to the expenditures on plant additions and that these additions 

reflect a representative year or this analysis. We estimate the annual compression and 

transmission-related NSPS compliance costs at $5.5 million without estimated revenues from 

product recovery and $3.7 million with estimated revenues from product recovery, respectively, 

in 2008 dollars. 

7.4.3.2 Small Entity Impact Analysis, Final NSPS, Results

Summing estimated annualized engineering compliance costs across industry segment 

and individual firms in our sample, we estimate firms in the OGJ-based sample will face about 

220 million in 2008 dollars, about 64 percent of the estimated annualized costs of the final NSPS 

without including revenues from additional product recovery $327 million). When including 

revenues from additional product recovery, the estimated compliance costs for the firms in the 

sample is about -$720,000.

Table 7-21 presents the distribution of estimated final NSPS compliance costs across firm 

size for the firms within our sample. Evident from this table, about 96 percent of the estimated 

engineering compliance costs accrue to the integrated and production segment of the industry, 

again explained by the fact that completion-related requirements contribute the bulk of the 

estimated engineering compliance costs (as well as estimated emissions reductions). About 16 

percent of the total estimated engineering compliance costs (and about 17 percent of the costs 

accruing the integrated and production segment) are focused on small firms.
7-42

Table 7-21 Distribution of Estimated Final NSPS Compliance Costs Without Revenues 

from Additional Natural Gas Product Recovery across Firm Size in Sample of Firms

Number of 

Firms

Estimated Engineering Compliance Costs Without Estimated Revenues from 

Natural Gas Product Recovery (2008 dollars)

Firm Type/Size Total Average Median Minimum Maximum

Production and Integrated

Small 77 35,182,059 456,910 95,299 1,463 4,552,593

Large 47 175,543,216 3,734,962 2,631,873 15,433 15,255,379

Subtotal 124 210,725,275 1,699,397 438,547 1,463 15,255,379

Pipeline

Small 11 3,738 340 123 20 1,264

Large 36 1,641,771 45,605 4,218 41 994,491

Subtotal 47 1,645,509 35,011 2,498 20 994,491

Processing

Small 39 482,232 12,365 1,906 191 279,864

Large 23 870,458 37,846 8,236 38 429,043

Subtotal 62 1,352,690 21,818 2,764 38 429,043

Pipelines/Processing

Small 0 --- --- --- --- ---

Large 13 5,828,374 448,336 159,519 2,040 2,892,799

Subtotal 13 5,828,374 448,336 159,519 2,040 2,892,799

Total

Small 127 35,668,029 280,851 22,511 20 4,552,593

Large 119 183,883,819 1,545,242 48,054 38 15,255,379

Total 246 219,551,848 892,487 33,520 20 15,255,379

These distributions are similar when the revenues from expected natural gas recovery are 

included (Table 7-22). About 9 percent of the total savings from the final NSPS is expected to 

accrue to small firms (about 23 percent of the savings to the integrated and production segment 

accrue to small firms). Note also in Table 7-22 that the pipeline and processing segments (and 

the pipeline/processing firms) are not expected to experience net cost savings (negative costs) 

from the final NSPS.
7-43

Table 7-22 Distribution of Estimated Final NSPS Compliance Costs With Revenues 

from Additional Natural Gas Product Recovery across Firm Size in Sample of Firms

Number of 

Firms

Estimated Engineering Compliance Costs With Estimated Revenues from 

Natural Gas Product Recovery (millions, 2008 dollars)

Firm Type/Size Total Average Median Minimum Maximum

Production and Integrated

Small 77 -1,930,670 -25,074 -5,341 -255,773 22,919

Large 47 -6,565,092 -139,683 -126,073 -847,055 924,574

Subtotal 124 -8,495,763 -68,514 -15,463 -847,055 924,574

Pipeline

Small 11 3,629 330 119 19 1,226

Large 36 1,593,661 44,268 4,095 40 965,348

Subtotal 47 1,597,289 33,985 2,425 19 965,348

Processing

Small 39 349,635 8,965 1,382 138 202,911

Large 23 631,112 27,440 5,971 28 311,071

Subtotal 62 980,747 15,819 2,004 28 311,071

Pipelines/Processing

Small 0 --- --- --- --- ---

Large 13 5,198,212 399,862 143,446 1,511 2,777,165

Subtotal 13 5,198,212 399,862 143,446 1,511 2,777,165

Total

Small 127 -1,577,407 -12,421 -902 -255,773 202,911

Large 119 857,892 7,209 2,419 -847,055 2,777,165

Total 246 -719,514 -2,925 103 -847,055 2,777,165
7-44

Table 7-23 Summary of Sales Test Ratios, Without Revenues from Additional Natural 

Gas Product Recovery for Firms Affected by Final NSPS

Number of 

Firms

Descriptive Statistics for Sales Test Ratio Without Estimated 

Revenues from Natural Gas Product Recovery (%)

Firm Type/Size Average Median Minimum Maximum

Production and Integrated

Small 77 0.97% 0.22% 0.01% 23.17%

Large 47 0.19% 0.14% 0.00% 1.28%

Subtotal 124 0.67% 0.18% 0.00% 23.17%

Pipeline

Small 11 0.00% 0.00% 0.00% 0.01%

Large 36 0.01% 0.00% 0.00% 0.06%

Subtotal 47 0.01% 0.00% 0.00% 0.06%

Processing

Small 39 0.02% 0.01% 0.00% 0.15%

Large 23 0.01% 0.00% 0.00% 0.16%

Subtotal 62 0.02% 0.01% 0.00% 0.16%

Pipelines/Processing

Small 0 --- --- --- ---

Large 13 0.00% 0.00% 0.00% 0.01%

Subtotal 13 0.00% 0.00% 0.00% 0.01%

Total

Small 127 0.59% 0.07% 0.00% 23.17%

Large 119 0.08% 0.00% 0.00% 1.28%

Total 246 0.35% 0.02% 0.00% 23.17%

The mean cost-sales ratio for all businesses when estimated product recovery is excluded 

from the analysis of the sample data is 0.35 percent, with a median ratio of 0.02 percent, a 

minimum of less than 0.01 percent, and a maximum of over 23 percent (Table 7-23). For small 

firms in the sample, the mean and median cost-sales ratios are 0.59percent and 0.07 percent, 

respectively, with a minimum of less than 0.01 percent and a maximum of over 23 percent 

(Table 7-23). Each of these statistics indicates that, when considered in the aggregate, impacts 

are relatively higher on small firms than large firms when the estimated revenue from additional 

natural gas product recovery is excluded. However, as the next table shows, the reverse is true 

when these revenues are included.
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Table 7-24 Summary of Sales Test Ratios, With Revenues from Additional Natural Gas 

Product Recovery for Firms Affected by Final NSPS

Number of 

Firms

Descriptive Statistics for Sales Test Ratio With Estimated Revenues 

from Natural Gas Product Recovery (%)

Firm Type/Size Average Median Minimum Maximum

Production and Integrated

Small 77 -0.05% -0.01% -1.06% 0.01%

Large 47 -0.01% -0.01% -0.07% 0.14%

Subtotal 124 -0.03% -0.01% -1.06% 0.14%

Pipeline

Small 11 0.00% 0.00% 0.00% 0.01%

Large 36 0.01% 0.00% 0.00% 0.06%

Subtotal 47 0.01% 0.00% 0.00% 0.06%

Processing

Small 39 0.01% 0.01% 0.00% 0.11%

Large 23 0.01% 0.00% 0.00% 0.11%

Subtotal 62 0.01% 0.00% 0.00% 0.11%

Pipelines/Processing

Small 0 --- --- --- ---

Large 13 0.00% 0.00% 0.00% 0.01%

Subtotal 13 0.00% 0.00% 0.00% 0.01%

Total

Small 127 -0.03% 0.00% -1.06% 0.11%

Large 119 0.00% 0.00% -0.07% 0.14%

Total 246 -0.01% 0.00% -1.06% 0.14%

The mean cost-sales ratio for all businesses when estimated product recovery is included 

is in the sample is -0.01 percent, with a median ratio of less than 0.01 percent, a minimum of 

-1.06 percent, and a maximum of 0.14 percent (Table 7-24). For small firms in the sample, the 

mean and median cost-sales ratios are -0.03 percent and less than 0.01 percent, respectively, with 

a minimum of -1.06 percent and a maximum of 0.11 percent (Table 7-24). Each of these 

statistics indicates that, when considered in the aggregate, impacts are small on small business 

when the estimated revenue from additional natural gas product recovery are included, the 

reverse of the conclusion found when these revenues are excluded.

Meanwhile, Table 7-25 presents the distribution of estimated cost-sales ratios for the 

small firms in our sample with and without including estimates of the expected natural gas 

product recover from implementing controls. When revenues estimates are included, all 127 
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firms (100 percent) have estimated cost-sales ratios less than 1 percent. While less than 1 

percent, the highest cost-sales ratios for small firms in the sample experiencing impacts are 

largely driven by costs accruing to processing and pipeline firms. That said, the incremental 

costs imposed on firms that process natural gas or transport natural gas via pipelines are not 

estimated to create significant impacts on a cost-sales ratio basis at the firm-level.

Table 7-25 Impact Levels of Final NSPS on Small Firms as a Percent of Small Firms in 

Sample, With and Without Revenues from Additional Natural Gas Product Recovery

Without Estimated Revenues from Natural 

Gas Product Recovery

With Estimated Revenues from Natural 

Gas Product Recovery

Impact Level

Number of Small 

Firms in Sample 

Estimated to be 

Affected

% of Small Firms in 

Sample Estimated to 

be Affected

Number of Small 

Firms in Sample 

Estimated to be 

Affected

% of Small Firms in 

Sample Estimated to 

be Affected

C/S Ratio less than 1% 120 94.5% 127 100.00%

C/S Ratio 1-3% 4 3.1% 0 0.00%

CS Ratio greater than 3% 3 2.4% 0 0.00%

When the estimated revenues from product recovery are not included in the analysis, four firms 

(about 3 percent) are estimated to have sales test ratios between 1 and 3 percent. Three firms 

(about 2 percent) are estimated to have sales test ratios greater than 3 percent. These results 

noted, the exclusion of product recovery is somewhat artificial. While the mean engineering 

compliance costs and revenues estimates are valid, drawing on the means ignores the distribution 

around the mean estimates, which risks masking effects. Because of this risk, the following 

section offers a qualitative discussion of small entities with regard to obtaining REC services, the 

validity of the cost and performance of RECs for small firms, as well as offers a discussion about 

whether older equipment, which may be disproportionately owned and operated be smaller 

producers, would be affected by the final NSPS.
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7.4.3.3 Small Entity Impact Analysis, Final NSPS, Additional Qualitative Discussion

3.5.3.3.1 Small Entities and Reduced Emissions Completions

Because REC requirements of the final NSPS are expected to contribute the large 

majority of engineering compliance costs, it is important to examine these requirements more 

closely in the context small entities. Important issues to resolve are the scale of REC costs 

within a drilling project, how the payment system for recovered natural gas functions, whether 

small entities pursue particular “niche” strategies that may influence the costs or performance in 

a way that makes the estimates costs and revenues invalid.

According to the most recent natural gas well cost data from EIA, the average cost of 

drilling and completing a producing natural gas well in 2007 was about $4.8 million (adjusted to 

2008 dollars). This average includes lower cost wells that may be relatively shallow or are not 

hydraulically fractured. Hydraulically fractured wells in deep formations may cost up to $10 

million. RECs contracted from a service provider are estimated to cost $33,200 (in 2008 dollars) 

or roughly 0.3%-0.7% of the typical cost of a drilling and completing a natural gas well. As this

range does not include revenues expected from natural gas and hydrocarbon condensate recovery

expected to offset REC implementation costs, REC costs likely represent a small increment of 

the overall burden of a drilling project.

To implement an REC, a service provider, which may itself be a small entity, is typically

contracted to bring a set of equipment to the well pad temporarily to capture the stream that 

would otherwise be vented to the atmosphere. Typically, service providers are engaged in a long 

term drilling program in a particular basin covering multiple wells on multiple well pads. For 

gas captured and sold to the gathering system, Lease Automatic Custody Transfer (LACT) 

meters are normally read daily automatically, and sales transactions are typically settled at the 

end of the month. Invoices from service providers are generally delivered in 30-day increments 

during the well development time period, as well as at the end of the working contract for that 

well pad. The conclusion from the information, based on the available information, in most 

cases, the owner/operator incurs the REC cost within the same 30 day period that the 

owner/operator receives revenue as a result of the REC. 
7-48

We assume small firms are performing RECs in CO and WY, as in many instances RECs 

are required under state regulation. In addition to State regulations, some companies are 

implementing RECs voluntarily such as through participation in the EPA Natural Gas STAR 

Program and the focus of recent press reports. 

As described in more detail below, many small independent E&P companies often do not 

conduct any of the actual field work. These firms will typically contract the drilling, completion, 

testing, well design, environmental assessment, and maintenance. Therefore, we believe it is 

likely that small independent E&P firms will contract for RECs from service providers if 

required to perform RECs. An important reminder is that performing a REC is a straightforward 

and inexpensive extension of drilling, completion, and testing activities.

To the extent that very small firms may specialize in operating relatively few lowproducing stripper wells, it is important to ask whether low-producing wells are likely candidates 

for re-fracturing/re-completion and, if so, whether the expected costs and revenues would be 

valid. These marginal gas wells are likely to be older and in conventional formations, and as 

such are unlikely to be good candidates for re-fracturing/completion. To the extent the marginal 

wells may be good candidates for re-fracturing/completion, the REC costs are valid estimates. 

The average REC cost is valid for RECs performed on any well, regardless of the operator size. 

The reason for this is that the REC service is contracted out to specialty service providers who 

charge daily rates for the REC equipment and workers. The cost is not related to any well 

characteristic. 

Large operators may receive a discount for offering larger contracts which help a service 

provider guarantee that REC equipment will be utilized. However, we should note that the 

existence of a potential discount for larger contracts is based on a strong assumption; we do not 

have evidence to support this assumption. Since contracting REC equipment is analogous to 

contracting for drilling equipment, completion equipment, etc., the premium would likely be in 

the same range as other equipment contracted by small operators. Since the REC cost is a small 

portion of the overall well drilling and completion cost, the effect of any bulk discount disparity 

between large and small operators will be small, if in fact it does exist.
7-49

Although small operators may own the majority of marginal and stripper wells, they will 

make decisions based on economics just as any sized company would. For developing a new 

well, any sized company will expect a return on their investment meaning the potential for 

sufficient gas, condensate, and/or oil production to pay back their investment and generate a 

return that exceeds alternative investment opportunities. Therefore, small or large operators that 

are performing hydraulic fracture completions will experience the same distribution of REC 

performance. For refracturing an existing well, the well must be a good candidate to respond to 

the re-fracture/completion with a production increase that merits the investment in the refracture/completion. 

Plugging and abandoning wells is complex and costly, so sustaining the productivity of 

wells is important for maximizing the exploitation of proven domestic resources. However, 

many marginal gas wells are likely to be older and in conventional formations, and as such are 

unlikely to be good candidates for re-fracturing/completion, which means they are likely

unaffected by the final NSPS. 

3.5.3.3.2 Age of Equipment and Final Regulations

Given a large fraction of domestic oil and natural gas production is produced from older 

and generally low productivity wells, it is important to examine whether the requirements of 

these rules might present impediments to owners and operators of older equipment. The NSPS is 

a standard that applies to new or modified sources. Because of this, NSPS requirements target 

new or modified affected facilities or equipment, such as processing plants and compressors. 

While the requirements may apply to modifications of existing facilities, it is important to 

discuss well completion-related requirements aside from other requirements in the NSPS 

distinctly. 

Excluding well completion requirements from the cost estimates, the non-completion 

NSPS requirements (related to equipment leaks at processing plants, reciprocating and 

centrifugal compressors, pneumatic controllers, and storage vessels) are estimated to require

about $15 million in annualized engineering costs. EPA also estimates that the annualized costs 

of these requirements will be mostly if not fully offset by revenues expected from natural gas 

recovery. EPA does not expect these requirements to disproportionately affect producers with 
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older equipment. Meanwhile, the REC and emissions combustion requirements in the final

NSPS relate to well completion activities at new hydraulically fractured natural gas wells and 

existing wells which are recompleted after being fractured or re-fractured. These requirements 

constitute the bulk of the expected engineering compliance expenditures (about $320 million in 

annualized costs) and expected revenues from natural gas product recovery (about $330 million 

in revenues, annually). 

While age of the well and equipment may be an important factor for small and large 

producers in determining whether it is economical to fracture or re-fracture an existing well, this 

equipment is unlikely to be subject to the NSPS. To comply with completion-related 

requirements, producers are likely to rely heavily on portable and temporary completion 

equipment brought to the wellpad over a short period of time (a few days to a few weeks) to 

capture and combust emissions that are otherwise vented. The equipment at the wellhead—

newly installed in the case of new well completions or already in place and operating in the case 

of existing wells—is not likely to be subject to the NSPS requirement.

7.4.4 Small Entity Economic Impact Analysis, Final NESHAP Amendments

The Final NESHAP Amendments will affect facilities operating three types of 

equipment: glycol dehydrators at production facilities, glycol dehydrators at transmission and 

compression facilities, and storage vessels. We identified likely affected facilities in the 

National Emissions Inventory (NEI) and estimated the number of newly required controls of 

each type that would be required by the NESHAP Amendments for each facility. We then used 

available data sources to best identify the ultimate owner of the equipment that would likely

require new controls and linked facility-level compliance cost estimates to firm-level 

employment and revenue data. These data were then used to calculate an estimated compliance 

costs to revenues ratio to identify small businesses that might be significantly impacted by the 

NESHAP.

While we were able to identify the owners all but 14 facilities likely to be affected, we 

could not obtain employment and revenue levels for all of these firms. Overall, we expect about 

381 facilities to be affected, and these facilities are owned by an estimated 155 firms. We were 

unable to obtain financial information on 47 (30 percent) of these firms due to inadequate data. 
7-51

In some instances, firms are private, and financial data is not available. In other instance, firms 

may no longer exist, since NEI data are not updated continuously. From the ownership 

information and compliance cost estimates from the engineering analysis, we estimated total 

compliance cost per firm. 

Of the 108 firms for which we have financial information, we identified 54 small firms 

and 54 large firms that would be affected by the NESHAP Amendments. Annual compliance 

costs for small firms are estimated at $2.6 million (17 percent of the total compliance costs), and 

annual compliance costs for large firms are estimated at $10 million (66 percent of the total 

compliance costs). The facilities for which we were unable to identify the ultimate owners, 

employment, and revenue levels would have an estimated annual compliance cost of $2.6 million 

(17percent of the total). All figures are in 2008 dollars.

The average estimated annualized compliance cost for the 54 small firms identified in the 

dataset is $48,000, while the mean annual revenue figure for the same firms is over $109 million, 

or less than 1 percent for a average sales-test ratio for all 54 firms (Table 7-26). The median 

sale-test ratio for these firms is smaller at 0.17 percent. Large firms are likely to see an average 

of $183,000 in annual compliance costs, whereas average revenue for these firms exceeds $30 

billion since this set of firms includes many of the very large, integrated energy firms. For large 

firms, the average sales-test ratio is about 0.01 percent, and the median sales-test ratio is less 

than 0.01 percent (Table 7-26).

Table 7-26 Summary of Sales Test Ratios for Firms Affected by Final NESHAP 

Amendments

Firm Size

No. of Known 

Affected Firms

% of Total Known 

Affected Firms Mean C/S Ratio Median C/S Ratio

Min. C/S 

Ratio

Max. 

C/S 

Ratio

Small 54 50% 0.72% 0.17% < 0.01% 8.5%

Large 54 50% 0.01% < 0.01% < 0.01% 0.3%

All 108 100% 0.37% 0.02% < 0.01% 8.5%

Among the small firms, 45 of the 54 (83 percent) are likely to have impacts of less than 1

percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile nine firms 

(17 percent) are likely to have impacts greater than 1 percent (Table 7-27). Three of these nine

firms are likely to have impacts greater than 3 percent (Table 7-27) While these nine firms might 
7-52

receive significant impacts from the final NESHAP Amendments, they represent a very small 

slice of the oil and gas industry in its entirety, less than 0.2 percent of the estimated 6,427 small 

firms in NAICS 211 (Table 7-27).

Table 7-27 Affected Small Firms as a Percent of Small Firms Nationwide, Final

NESHAP Amendments

Firm Size

Number of Small 

Firms Affected 

Nationwide 

% of Small Firms 

Affected 

Nationwide 

Affected Firms 

as a % of 

National Firms 

(6,427)

C/S Ratio less than 1% 45 83.3% 0.70%

C/S Ratio 1-3% 6 11.1% 0.09%

CS Ratio greater than 3% 3 5.6% 0.05%

7.4.5 Conclusions for NSPS and NESHAP Amendments

While both the NSPS and NESHAP amendment would individually result in a no 

SISNOSE finding, the EPA performed an additional analysis in order to certify the rule in its 

entirety. This analysis compared compliance costs to entity revenues for the total of all the 

entities affected by the NESHAP Amendments and the sample of entities analyzed for the NSPS. 

When revenues from additional natural gas product sales are not included, 153 of the 169 small 

firms (91 percent) are likely to have impacts of less than 1 percent in terms of the ratio of 

annualized compliance costs to revenues (Table 7-28). Meanwhile, 16 firms (9 percent) are 

likely to have impacts greater than 1 percent. Six of these 16 firms are likely to have impacts 

greater than 3 percent. When revenues from additional natural gas product sales are included, 

160 small firms (95 percent) are likely to have impacts of less than 1 percent. Nine firms (5 

percent) are likely to have impacts greater than 1 percent, while only three of these nine are 

likely to have impacts greater than 3 percent.

Table 7-28 Affected Small Firms as a Percent of Small Firms Nationwide, Final NSPS 

and NESHAP Amendments

Without Estimated Revenues from Natural 

Gas Product Recovery

With Estimated Revenues from Natural 

Gas Product Recovery

Impact Level

Number of Small 

Firms in Sample 

Estimated to be 

Affected

% of Small Firms in 

Sample Estimated to 

be Affected

Number of Small 

Firms in Sample 

Estimated to be 

Affected

% of Small Firms in 

Sample Estimated to 

be Affected

C/S Ratio less than 1% 153 90.5% 160 94.7%

C/S Ratio 1-3% 10 5.9% 6 3.6%
7-53

CS Ratio greater than 3% 6 3.6% 3 1.8%

The number of significantly impacted small businesses is unlikely to be sufficiently large 

to declare a SISNOSE. Our judgment in this determination is informed by the fact that many 

affected firms are expected to receive revenues from the additional natural gas and condensate 

recovery engendered by the implementation of the controls evaluated in this RIA. As much of 

the additional natural gas recovery is estimated to arise from completion-related activities, we 

expect the impact on well-related compliance costs to be significantly mitigated. This conclusion 

is enhanced because the returns to reduced emissions completion activities occur without a 

significant time lag between implementing the control and obtaining the recovered product 

unlike many control options where the emissions reductions accumulate over long periods of 

time; the reduced emission completions and recompletions occur over a short span of time, 

during which the additional product recovery is also accomplished.

7.5 References 

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and jobs: national and regional analyses.” Journal of Environmental Management 

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Duda, J.R., G. Covatch, D. Remson, S. Wang. 2005. Projections of marginal wells and their 

contributions to oil and natural gas supplies. Society of Petroleum Engineers Eastern 

regional Meeting, SPE98014. 

Gabriel, S.A., A.S. Kydes, and P. Whitman. 2001. “The National Energy Modeling System: a 

large-scale energy-economic equilibrium model.” Operations Research 49:1: 14-25.

IHS Global Insight. “The Economic Contribution of the Onshore Independent oil and Natural 

Gas Producers to the U.S. Economy.” Prepared for the Independent Petroleum 

Association of America. April 2011. 

<http://www.ipaa.org/news/docs/IHSFinalReport.pdf> Accessed July 23, 2011.

Morgenstern, R.D. W.A. Pizer, and J. Shih. 2002. "Jobs versus the environment: an industrylevel perspective," Journal of Environmental Economics and Management 43(3):412-

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Oil and Gas Journal. “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil 

Profits Grow.” November 1, 2010.
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Oil and Gas Journal. “OGJ150.” September 21, 2009.

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<http://www.eia.gov/FTPROOT/modeldoc/m063(2010).pdf> Accessed March 30, 2011.

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2010. DOE/EIA-M062(2010) 

<http://www.eia.gov/FTPROOT/modeldoc/m062(2010).pdf> Accessed March 30, 2011.