Regulatory Impact Analysis 

Proposed 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 

July 2011 
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 NSPS RESULTS ............................................................................................................................................ 1-2

1.3 NESHAP AMENDMENTS RESULTS .............................................................................................................. 1-5

1.4 ORGANIZATION OF THIS REPORT .................................................................................................................. 1-7

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

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
iv 

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 VOCS......................................................................................................................................................... 4-18

4.5.1 VOCs 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 VOCS 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 as an ozone precursor ........................................................................................................ 4-27

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

4.8 REFERENCES .............................................................................................................................................. 4-34

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

5.3.1 Proposed NSPS .................................................................................................................................. 5-5

5.3.2 Proposed NESHAP Amendments ...................................................................................................... 5-5

5.4 UNFUNDED MANDATES REFORM ACT ......................................................................................................... 5-6

5.5 EXECUTIVE ORDER 13132: FEDERALISM .................................................................................................... 5-6

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 ..................................................................................................................................................................... 5-7

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 .................................................................. 5-9

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

POPULATIONS AND LOW-INCOME POPULATIONS ................................................................................................. 5-10

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

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

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

7.2 ENERGY SYSTEM IMPACTS ANALYSIS OF PROPOSED 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
v 

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 .................................................................. 7-13

7.2.3.3 Impacts on Imports and National Fuel Mix ............................................................................ 7-17

7.3 EMPLOYMENT IMPACT ANALYSIS .............................................................................................................. 7-20

7.3.1 Employment Impacts from Pollution Control Requirements ........................................................... 7-21

7.3.2 Employment Impacts Primarily on the Regulated Industry ............................................................. 7-24

7.4 SMALL BUSINESS IMPACTS ANALYSIS ....................................................................................................... 7-28

7.4.1 Small Business National Overview ................................................................................................. 7-29

7.4.2 Small Entity Economic Impact Measures ........................................................................................ 7-34

7.4.3 Small Entity Economic Impact Analysis, Proposed NSPS .............................................................. 7-36

7.4.3.1 Overview of Sample Data and Methods ................................................................................. 7-36

7.4.3.2 Small Entity Impact Analysis, Proposed NSPS, Results ........................................................ 7-42

7.4.3.3 Small Entity Impact Analysis, Proposed NSPS, Additional Qualitative Discussion.............. 7-48

7.4.3.4 Small Entity Impact Analysis, Proposed NSPS, Screening Analysis Conclusion .................. 7-51

7.4.4 Small Entity Economic Impact Analysis, Proposed NESHAP Amendments .................................. 7-52

7.5 REFERENCES .............................................................................................................................................. 7-54

 
vi 

LIST OF TABLES 

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

Regulatory Options in 2015 (millions of 2008$)1

 .............................................................................. 1-4

Table 1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed 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 Price 2-14

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 NSPS Options................................................. 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 Estimated Engineering Compliance Costs, NSPS (2008$) .............................................................. 3-18

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

Options, 2015 ................................................................................................................................... 3-21

Table 3-6 Simple Rate of Return Estimate for NSPS Control Options ............................................................ 3-23

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

Table 4-1 Direct Emission Reductions Associated with Options for 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 Proposed 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 Proposed Oil and 

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

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

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

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

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

NSPS and NESHAP Amendments in 2015 (millions of 2008$)1 ....................................................... 5-2
vii 

Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed 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 Proposed Oil and Natural Gas 

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

Table 6-3 Summary of Emissions Changes for the Proposed 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 Options ..................................................................... 7-11

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

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

Table 7-6 Natural Gas Production by Well Type (Onshore, Lower 48 States), NSPS Options ....................... 7-15

Table 7-7 Lower 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS Options .............................. 7-16

Table 7-8 Delivered Natural Gas Prices by Sector (2008$ per million BTU), 2015, NSPS Options ............... 7-16

Table 7-9 Natural Gas Consumption by Sector, NSPS Options ....................................................................... 7-17

Table 7-10 Net Imports of Natural Gas and Crude Oil, NSPS Options .............................................................. 7-18

Table 7-11 Total Energy Consumption by Energy Type (Quadrillion BTU), NSPS Options ............................ 7-19

Table 7-12 Modeled Change in Energy-related "Consumer-Side" CO2-equivalent GHG Emissions ................ 7-20

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

Maintaining Control Equipment Requirements, Proposed NSPS Option in 2015 ........................... 7-26

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

Maintaining Control Equipment Requirements, Proposed NESHAP Amendments in 2015 ........... 7-27

Table 7-15 Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007 .... 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 ......................................................................................... 7-32

Table 7-17 Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009 ............................... 7-34

Table 7-18 Estimated Revenues for Firms in Sample, by Firm Type and Size .................................................. 7-38

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

2008 and 2009 (million 2008 dollars) .............................................................................................. 7-39

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

(million 2008 dollars) ....................................................................................................................... 7-40

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

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

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

Gas Product Recovery across Firm Size in Sample of Firms ........................................................... 7-44

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

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

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

Firms Affected by Proposed NSPS .................................................................................................. 7-46

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

Without Revenues from Additional Natural Gas Product Recovery ................................................ 7-47

Table 7-26 Summary of Sales Test Ratios for Firms Affected by Proposed NESHAP Amendments ................ 7-53

Table 7-27 Affected Small Firms as a Percent of Small Firms Nationwide, Proposed NESHAP amendments . 7-53

 
viii 

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 Proposed 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 proposal 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 (VOCs) from Natural Gas Processing Plants, and proposes NSPS for 

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

addition, this proposal 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 proposes 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 proposed 

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

the NESHAP amendments are being proposed in the same rulemaking package (i.e., same 

Preamble), we have chosen to present the economic impact analysis for the proposed 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 proposed NSPS and NESHAP amendments. We also 

estimate potential impacts of the proposed 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 proposed emission controls for the NSPS capture VOC emissions that otherwise 

would be vented to the atmosphere. Since methane is co-emitted with VOCs, a large proportion 
1-2 

of the 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 proposed option. In the economic impact 

and energy economy analyses for the NSPS, we present results for three regulatory options that 

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

additional product recovery. 

1.2 NSPS Results 

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

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

including 37,000 tons of hazardous air pollutants (HAPs), 540,000 tons of VOCs, and 3.4 

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 HAPs, 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 proposed NSPS are likely to result in 

significant climate co-benefits. The specific control technologies for the proposed NSPS are 

anticipated to have minor secondary disbenefits, including an increase of 990,000 tons of 

carbon dioxide (CO2), 510 tons of nitrogen oxides NOx, 7.6 tons of PM, 2,800 tons of CO, 

and 1,000 tons of total hydrocarbons (THC) as well as emission reductions associated with 

the energy system impacts. The net CO2-equivalent emission reductions are 62 million 

metric tons.

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

be $740 million. The total annualized engineering costs of the proposed NSPS will be $740 

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

included, the annualized engineering costs of the proposed NSPS are estimated at $-45 

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 $180 million, given EPA estimates that 180 billion cubic feet of natural gas 
1-3 

will be recovered by implementing the proposed NSPS option. All estimates are in 2008 

dollars. 

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

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

natural gas production is likely to increase slightly (about 20 billion cubic feet or 0.1 percent) 

and average natural gas prices to decrease slightly (about $0.04/Mcf or 0.9 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 

$0.02/barrel or less than 0.1 percent at the wellhead for onshore production in the lower 48 

states). All prices are in 2008 dollars. 

 Small Entity Analyses: EPA performed a screening analysis for impacts on small entities by 

comparing compliance costs to revenues. For the proposed NSPS, we found that there will 

not be a significant impact on a substantial number of small entities (SISNOSE). 

 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 proposed NSPS is 

estimated at 230 full-time-equivalent employees. The annual labor requirement to comply 

with proposed NSPS is estimated at about 2,400 full-time-equivalent employees. 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. 
1-4 

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

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

 Option 1: Alternative Option 2: Proposed4

 Option 3: Alternative 

Total Monetized Benefits2 N/A N/A N/A 

Total Costs3 -$19 million -$45 million $77 million 

Net Benefits N/A N/A N/A 

Non-monetized Benefits 17,000 tons of HAPs5

 37,000 tons of HAPs5 37,000 tons of HAPs5

 270,000 tons of VOCs 540,000 tons of VOCs 550,000 tons of VOCs 

1.6 million tons of 

methane5 3.4 million tons of methane5

 3.4 million tons of methane5

Health effects of HAP 

exposure5

Health effects of HAP 

exposure5

Health effects of HAP 

exposure5

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 HAPs, 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 proposed NSPS are anticipated to have minor 

secondary disbenefits, including an increase of 990,000 tons of CO2, 510 tons of NOx, 7.6 tons of PM, 2,800 tons of 

CO, and 1,000 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system 

impacts. The net CO2-equivalent emission reductions are 62 million metric tons. 

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

4 The negative cost for the NSPS Options 1 and 2 reflects the inclusion of revenues from additional natural gas and 

hydrocarbon condensate recovery that are estimated as a result of the proposed 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 HAPs and climate effects are co-benefits. 
1-5 

1.3 NESHAP Amendments Results 

For the proposed NESHAP amendments, the key results of the RIA follow and are summarized 

in Table 1-2: 

 Benefits Analysis: The proposed NESHAP amendments are anticipated to reduce a 

significant amount of existing emissions, including 1,400 tons of HAPs, 9,200 tons of VOCs, 

and 4,900 tons of methane. Results from the residual risk assessment indicate that for 

existing natural gas transmission and storage, the maximum individual cancer risk decreases 

from 90-in-a-million before controls to 20-in-a-million after controls with benzene as the 

primary cancer risk driver. While we expect that these avoided emissions will result in 

improvements in ambient air quality and reductions in health effects associated with 

exposure to HAPs, 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 proposed 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 93 thousand metric tons. 

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

amendments to be $52 million. Total annualized engineering costs of the proposed NESHAP 

amendments are estimated to be $16 million. All estimates are in 2008 dollars. 

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

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

impacts on the national energy economy. 

 Small Entity Analyses: EPA performed a screening analysis for impacts on small entities by 

comparing compliance costs to revenues. For the proposed NESHAP amendments, we found 

that there will not be a significant impact on a substantial number of small entities 

(SISNOSE).

 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 proposed NESHAP 

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

requirement to comply with proposed NESHAP Amendments is estimated at about 102 fulltime-equivalent employees. 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.
1-6 

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

valued at $12,000 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 $1,700 per ton or the methane emissions would need to 

be valued at $3,300 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. 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 

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

 Option 1: Proposed (Floor) 

Total Monetized Benefits2 N/A 

Total Costs3 $16 million 

Net Benefits N/A 

Non-monetized Benefits 1,400 tons of HAPs 

9,200 tons of VOCs4

4,900 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 HAPs, 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 proposed NESHAP are 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 THC as well as emission reductions associated with the energy system impacts. The net CO2-equivalent 

emission reductions are 93 thousand 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 

effects are co-benefits. 
1-7 

1.4 Organization of this Report 

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

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

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

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

costs. Section 7 presents energy system impact, employment impact, and small 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 propose 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 proposed 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 proposed 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 20o

 or less, while a light or naphthenic crude oil, which 

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

30's to the low 40's. 

Crude oils recovered in the production phase 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 40o

 or more. In addition, condensates may include hydrocarbon 

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

gas transmission and storage processes and operations. 

2.2.4 Other Recovered Hydrocarbons 

Various hydrocarbons may be recovered through the processing of the extracted 

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

gasoline, propane, butane, and liquefied petroleum gas (LPG). 
2-4 

2.2.5 Produced Water 

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

separated from the extracted hydrocarbon streams in various production processes and 

operations. 

2.3 Oil and Natural Gas Production Processes 

2.3.1 Exploration and Drilling 

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

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

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

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

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

quantities. 

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

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

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

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

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

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

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

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

casing and the wellbore with cement. 

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

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

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

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

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

have made it possible to steer the drill in different directions (directional drilling) from the 
2-5 

surface without stopping the drill to switch directions and allowing for a more controlled and 

precise drilling trajectory. 

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

(U.S. DOE, 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 proposal 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, and 

undiscovered 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

Crude Oil (million bbl)

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

Producing Wells

0

1,000

2,000

3,000

4,000

5,000

Crude Oil (bbl)/Well

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

B). Natural Gas Wells

0

100

200

300

400

500

600

19901991199219931994199519961997199819992000200120022003200420052006200720082009

Producing Wells

0

10

20

30

40

50

60

70

Natural Gas 

(MMcf)/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 proposed 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

Successful 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 ($/MMcf, 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

Employment

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. Product

Rank by 

Total 

Assets Company Employees 

Total Assets 

($ millions) 

Total 

Rev. ($ 

millions) 

Net Inc. 

($ 

millions) 

Liquids 

(Million 

bbl) 

Natural 

Gas 

(Bcf) 

Liquids 

(Million 

bbl) 

Na

G

(B

1 ExxonMobil Corp. 102,700 233,323 310,586 19,280 725 2,383 112 2 Chevron Corp. 64,000 164,621 171,636 10,563 674 1,821 177 

3 ConocoPhillips 30,000 152,588 152,840 4,858 341 1,906 153 

4 Anadarko Petroleum Corp. 4,300 50,123 9,000 -103 88 817 63 

5 Marathon Oil Corp. 28,855 47,052 54,139 1,463 90 351 23 

6 Occidental Petroleum Corp. 10,100 44,229 15,531 2,915 179 338 99 

7 XTO Energy Inc. 3,129 36,255 9,064 2,019 32 855 32 

8 Chesapeake Energy Corp. 8,200 29,914 7,702 -5,805 12 835 12 

9 Devon Energy Corp. 5,400 29,686 8,015 -2,479 72 966 43 

10 Hess Corp. 13,300 29,465 29,569 740 107 270 26 

11 Apache Corp. 3,452 28,186 8,615 -284 106 642 35 

12 El Paso Corp. 4,991 22,505 4,631 -539 6 219 6 

13 EOG Resources Inc. 2,100 18,119 14,787 547 29 617 26 

14 Murphy Oil Corp. 8,369 12,756 18,918 838 48 68 6 

15 Noble Energy Inc. 1,630 11,807 2,313 -131 29 285 17 

16 Williams Cos. Inc. 4,801 9,682 2,219 400 0 3,435 0 3

17 Questar Corp. 2,468 8,898 3,054 393 4 169 4 

18 Pioneer Nat. Resources Co. 1,888 8,867 1,712 -52 19 157 17 

19 Plains Expl. & Prod. Co. 808 7,735 1,187 136 18 78 18 

20 Petrohawk Energy Corp. 469 6,662 41,084 -1,025 2 174 2 

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 proposed 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 proposed 

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, welfare, 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 industry to provide context for 

estimated reductions as a result of the regulatory options evaluated. 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 (510,000 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 

2.24 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 proposal 

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. EPA is soliciting public 

comment and data relevant to several emissions-related issues related to the proposed NSPS. 

The comments we receive during the public comment period will help inform the rule 

development process as we work toward promulgating a final action. 

Centrifugal and reciprocating compressors (TSD Chapter 6): 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. Turbine-powered 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, 
3-3 

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. 

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 (TSD Chapter 8): 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 openended 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 
3-4 

and gas production, processing, and transmission facility, equipment leaks of volatile emissions 

from these components can be significant. Natural gas processing 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 (TSD Chapter 5): 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. Gasdriven 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 (TSD Chapter 7): Crude oil, condensate, and produced water are typically 

stored in fixed-roof storage vessels. Some vessels used for storing produced water may be opentop 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 
3-5 

working, breathing, and flash losses. Working losses occur due to the emptying and filling of 

storage tanks. Breathing losses are the release of gas 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 (TSD Chapter 4): 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 re-fracturing 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 
3-6 

that uncontrolled well completion emissions for a hydraulically fractured well are about 23 tons 

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 proposed 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 

 

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. 
3-7 

dehydration. Solid desiccant dehydration, which is typically only used for lower throughputs, 

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 proposed 
3-8 

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. 

3.2.2.1 NSPS Sources 

Table 3-1 shows the emissions sources, points, and controls analyzed in three NSPS 

regulatory options, which we term Option 1, Option 2, and Option 3. Option 2 was selected for 

proposal. The proposed Option 2 contains reduced emission completion (REC) and completion 

combustion requirements for a subset of newly drilled natural gas wells that are hydraulically 

fractured. Option 2 also requires a subset of wells that are worked over, or recompleted, using 

hydraulic fracturing to implement RECs. The proposed Option 2 requires emissions reductions 

from reciprocating compressors at gathering and boosting stations, processing plants, 

transmission compressor stations, and underground storage facilities. The proposed Option 2 

also requires emissions reductions from centrifugal compressors, processing plants, and 

transmission compressor stations. Finally, the proposed Option 2 requires emissions reductions 

from pneumatic controllers at oil and gas production facilities and natural gas transmission and 

storage and reductions from high throughput storage vessels. 

 
3-9 

Table 3-1 Emissions Sources, Points, and Controls Included in NSPS Options 

Emissions Sources and Points Emissions Control Option 1 Option 2 

(proposed) Option 3 

Well Completions of Post-NSPS Wells 

Hydraulically Fractured Gas Wells that 

Meet Criteria for Reduced Emissions 

Completion (REC) 

REC X X X 

Hydraulically Fractured Gas Wells that 

Do Not Meet Criteria for REC Combustion X X X 

 Conventional Gas Wells Combustion 

 Oil Wells Combustion 

Well Recompletions 

Hydraulically Fractured Gas Wells (postNSPS wells) REC X X X 

Hydraulically Fractured Gas Wells (preNSPS wells) REC X X 

 Conventional Gas Wells Combustion 

 Oil Wells Combustion 

Equipment Leaks 

 Well Pads NSPS Subpart VV X 

 Gathering and Boosting Stations NSPS Subpart VV X 

 Processing Plants NSPS Subpart VVa X X 

 Transmission Compressor Stations NSPS Subpart VV X 

Reciprocating Compressors 

 Well Pads Annual Monitoring/ 

Maintenance (AMM) 

 Gathering/Boosting Stations AMM X X X 

 Processing Plants AMM X X X 

 Transmission Compressor Stations AMM X X X 

 Underground Storage Facilities AMM X X X 

Centrifugal Compressors 

 Processing Plants Dry Seals/Route to Process or 

Control X X X 

 Transmission Compressor Stations Dry Seals/Route to Process or 

Control X X X 

Pneumatic Controllers - 

 Oil and Gas Production Low Bleed/Route to Process X X X 

 Natural Gas Transmission and Storage Low Bleed/Route to Process X X X 

Storage Vessels 

 High Throughput 95% control X X X 

 Low Throughput 95% control 

 
3-10 

The distinction between Option 1 and the proposed Option 2 is the inclusion of 

completion combustion and REC requirements for recompletions at existing wells and an 

equipment leak standard for natural gas processing plants in Option 2. Option 2 requires the 

implementation of completion combustion and REC for existing wells as well as wells 

completed after the implementation date of the proposed NSPS. Option 1 applies the 

requirement only to new wells, not existing wells. The main distinction between proposed 

Option 2 and Option 3 is the inclusion of a suite of equipment leak standards. These equipment 

leak standards would apply at well pads, gathering and boosting stations, and transmission 

compressor stations. Option 1 differs from Option 3 in that it does not include the combustion 

and REC requirements at existing wells or the full suite of equipment leak standards. 

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 

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 
3-11 

To estimate total annualized engineering compliance costs, we added the annualized costs 

of each item without accounting for different expected lifetimes. An alternative approach would 

be to establish an overall, representative project time horizon and annualize 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 compressorrelated controls five times, but only require a single installation of controls on storage vessels. 

This approach, however, is equivalent to the approach selected; that is to sum the annualized 

costs across options, without establishing a representative project time horizon. 

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 

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 TSD6

 and applied to well count data found in the 

proprietary HPDI® database. The underlying assumption is that wells found in coal bed 

 

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 

methane, shale, and tight sand formations require re-fracture, on average, every 10 years. In 

other words, 10 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 12,050 

recompletions of existing wells that will require either a REC under the proposed NSPS in 2015. 

It 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. 

Third, for well completion requirements, annualized costs are set equal to capital costs. 

We chose to equate the capital and annualized cost because 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. We reasoned that the absence of a 

continuing requirement makes it appropriate to equate capital and annualized costs. 

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 

revenues this product recovery. Several emission controls for the NSPS capture VOC emissions 
3-13 

that otherwise would be vented to the atmosphere. Since methane is co-emitted with VOCs, 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 assumed price for natural gas is within the range of variation of wellhead prices for 

the 2010-11 period. 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 $180 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 reporting and recordkeeping costs for 

the proposed NSPS Option 2 are estimated at $18,805,398 and are included in Table 3-3. 

Because of time constraints, we were unable to estimate reporting and recordkeeping costs 

customized for Options 1 and 3; for these options, we use the same $18,805,398 for reporting 

and recordkeeping costs for these options. 

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 
3-14 

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. 

Several evaluated emissions sources and points are estimated to have net financial 

savings when including the revenue from additional natural gas recovery. These sources form 

the core of the three NSPS options evaluated in this RIA. Table 3-4 presents the estimated 

engineering costs, emissions reductions, and VOC reduction cost-effectiveness for the three 

NSPS options evaluated in the RIA. The resulting total national annualized cost impact of the 

proposed NSPS rule (Option 2) is estimated at $740 million per year without considering 

revenues from additional natural gas recovery. Annual costs for the proposed NSPS are 

estimated at -$45 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 9,313 $33,237 $33,237 -$2,173 

Hydraulically Fractured Gas Wells 

that Do Not Meet Criteria for REC 

(Completion Combustion) 446 $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) 12,050 $33,237 $33,237 -$2,173 

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 $7,522 $45,160 $33,884 

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 16 $75,000 $10,678 -$123,730 

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 $14,528 $13,946 

Low Throughput 17,086 $65,243 $14,528 $13,946 
3-16 

Table 3-3 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-E

Emissions Sources and Points, NSPS, 2015 

Source/Emissions Point Emissions Control 

Nationwide Annualized Costs 

(2008$) 

Nationwide Emissions 

Reductions (tons/year) 

V

Without 

Addl. 

Revenues 

With Addl. 

Revenues VOC Methane HAP 

Well Completions (New Wells) Hydraulically Fractured Gas Wells REC $309,553,517 -$20,235,748 204,134 1,399,139 14,831 Hydraulically Fractured Gas Wells Combustion $1,571,188 $1,571,188 9,801 67,178 712 Conventional Gas Wells Combustion $27,104,761 $27,104,761 857 5,875 62 Oil Wells Combustion $42,954,036 $42,954,036 83 88 0 Well Recompletions (Existing Wells) Hydraulically Fractured Gas Wells (existing wells) REC $400,508,928 -$26,181,572 264,115 1,810,245 19,189 Conventional Gas Wells Combustion $149,164,257 $149,164,257 316 2,165 23 Oil Wells Combustion $138,711,979 $138,711,979 44 47 0 Equipment Leaks Well Pads NSPS Subpart VV $111,773,662 $104,412,154 10,646 38,287 401 Gathering and Boosting Stations NSPS Subpart VV $15,692,325 $14,072,850 2,340 8,415 88 Processing Plants NSPS Subpart VVa $1,309,650 $982,648 392 1,411 15 Transmission Compressor Stations NSPS Subpart VV $2,712,450 $2,712,450 261 9,427 8 Reciprocating Compressors Well Pads 

Annual Monitoring/ Maintenance (AMM) $22,204,209 $21,984,763 263 947 10 

Gathering/Boosting Stations AMM $515,764 $182,597 400 1,437 15 Processing Plants AMM $436,806 -$465,354 1,082 3,892 41 Transmission Compressor Stations AMM $47,892 $47,892 12 423 0 Underground Storage Facilities AMM $13,396 $13,396 2 87 0 
3-17 

Table 3-3 (continued) Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Re

Effectiveness by Emissions Sources and Points, NSPS, 2015 

Source/Emissions Point Emissions Control 

Nationwide Annualized Costs 

(2008$) 

Nationwide Emissions 

Reductions (tons/year) 

V

Without 

Addl. 

Revenues 

With Addl. 

Revenues VOC Methane HAP

Centrifugal Compressors Processing Plants 

Dry Seals/Route to Process or Control $170,853 -$1,979,687 288 3,183 10 

Transmission Compressor Stations 

Dry Seals/Route to Process or Control $149,496 -$1,086,704 43 1,546 1 

Pneumatic Controllers -  Oil and Gas Production 

Low Bleed/Route to Process $320,071 -$20,699,918 25,210 90,685 952 

 Natural Gas Trans. and Storage 

Low Bleed/Route to Process $1,539 $1,539 6 212 0 

Storage Vessels High Throughput 95% control $4,411,587 $4,234,856 29,654 6,490 876 Low Throughput 95% control $248,225,012 $238,280,976 6,838 1,497 202 
3-18 

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

 Option 1 

Option 2 

(Proposed) Option 3 

Capital Costs $337,803,930 $738,530,998 $1,143,984,622 

Annualized Costs 

 Without Revenues from Additional Natural 

 Gas Product Recovery $336,163,858 $737,982,436 $868,160,873 

With Revenues from Additional Natural Gas 

 Product Recovery -$19,496,449 -$44,695,374 $76,502,080 

 

VOC Reductions (tons per year) 270,695 535,201 548,449 

Methane Reduction (tons per year) 1,574,498 3,386,154 3,442,283 

HAP Reductions (tons per year) 17,442 36,645 37,142 

 

VOC Reduction Cost-Effectiveness ($/ton 

without additional product revenues) 

$1,241.86 $1,378.89 $1,582.94 

VOC Reduction Cost-Effectiveness ($/ton 

with additional product revenues) 

-$72.02 -$83.51 $139.49 

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 $180 million in 2008 dollars. The cost 

estimates for each regulatory option also include reporting and recordkeeping costs of $18,805,398. 

 As mentioned earlier, the single difference between Option 1 and the proposed Option 2 

is the inclusion of RECs for recompletions of existing wells in Option 2. The implication of this 

inclusion in Option 2 is clear in Table 3-4, as the estimated engineering compliance costs without 

additional product revenue more than double and VOC emissions reductions also more than 

double. Meanwhile, the addition of equipment leaks standards in Option 3 increases engineering 

costs more than $400 million dollars in 2008 dollars, but only marginally increase estimates of 

emissions reductions of VOCs, methane, and HAPS. 

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 proposed 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 
3-19 

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. 

Figure 3-1 Sensitivity Analysis of Proposed 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 -$45 

million. At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy Outlook, the 

annualized costs are estimated at about -$90 million, which would approximately double the 

estimate of net cost savings of the proposed 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 proposed NSPS 

breaks-even is around $3.77/Mcf. As mentioned earlier, a $1/Mcf change in the wellhead natural 

gas price leads to about a $180 million change in the annualized engineering costs of the 

proposed NSPS. Consequently, annualized engineering costs estimates would increase to about 

$140 million under a $3/Mcf price or decrease to about -$230 million under a $5/Mcf price. 

$(700)

$(600)

$(500)

$(400)

$(300)

$(200)

$(100)

$-

$100 

$200 

$300 

$400 

$- $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 

Function of 

Natural Gas

Price

Assumption
3-20 

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 

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, Options 1, 2, and 3 are 

estimated to capture about 83, 183, and 185 bcf of natural gas and 317,000, 726,000, and 

726,000 barrels of condensate, respectively. For control options that are expected to recover 

natural gas products. 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 all NSPS regulatory options. For natural gas recovery, 

RECs contribute 77 bcf (92 percent) for Option 1, 176 bcf (97 percent) for Option 2, and 176 bcf 

(95 percent) for Option 3. 
3-21 

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

Projected 

No. of 

Affected 

Units 

Unit-level Product Recovery 

Source/ Emissions Points Emissions Control 

NSPS 

Option 

Natural Gas 

Savings 

(Mcf/unit) 

Condensate 

(bbl/unit) 

Well Completions 

Hydraulically Fractured Gas Wells REC 1, 2, 3 9,313 8,258 34 Hydraulically Fractured Gas Wells Combustion 1, 2, 3 446 0 0 

Hydraulically Fractured Gas Wells (existing wells) REC 2, 3 12,050 8,258 34 

Equipment Leaks 

Well Pads NSPS Subpart VV 3 4,774 386 0 Gathering and Boosting Stations NSPS Subpart VV 3 275 1,472 0 Processing Plants NSPS Subpart VVa 2, 3 29 2,819 0 

Reciprocating Compressors 

Gathering/Boosting Stations AMM 1, 2, 3 210 397 0 Processing Plants AMM 1, 2, 3 375 1,079 0 Trans. Compressor Stations AMM 1, 2, 3 199 1,122 0 Underground Storage Facilities AMM 1, 2, 3 9 1,130 0 

Centrifugal Compressors 

Processing Plants Dry Seals/Route to Process or Ctrl 1, 2, 3 16 11,527 0 Trans. Compressor Stations Dry Seals/Route to Process or Ctrl 1, 2, 3 14 5,716 0 

Pneumatic Controllers - 

Oil and Gas Production Low Bleed/Route to Process 1, 2, 3 13,632 386 0 Natural Gas Trans. and Storage Low Bleed/Route to Process 1, 2, 3 67 0 0 

Processing Plants Instrument Air 1, 2, 3 15 871.0 0 

Storage Vessels 

High Throughput 95% control 1, 2, 3 304 146 0 

Option 1 Total (Mcf) Option 2 Total (Mcf) Option 3 Total (Mcf) 
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 by 

consumed by final consumers. 

 After making these adjustments, we estimate that Option 1 will potentially recover 

approximately 66 bcf, proposed Option 2 will potentially recover about 145 bcf, and Option 3 

will potentially recover 146 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, Option 1, proposed Option 2, and Option 3 may recover production 

representing about 0.29 percent, 0.64 percent and 0.65 percent of domestic dry natural gas 

production predicted in 2015, respectively. 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 decisionmaking. 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. 

 

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 

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 

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: 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 rate of return 1 100

estimated costs

 

= − ×     . 

Table 3-6 Simple Rate of Return Estimate for NSPS Control Options 

Emission Point Control Option Rate of Return 

New Completions of Hydraulically Fractured Wells 

Reduced Emissions 

Completions 6.5% 

Re-completions of Existing Hydraulically Fractured Wells 

Reduced Emissions 

Completions 6.5% 

Reciprocating Compressors (Processing Plants) 

Replace Packing Every 3 

Years of Operation 208.3% 

Centrifugal Compressors (Processing Plants) Convert to Dry Seals 1158.7% 

Centrifugal Compressors (Transmission Compressor 

Stations) 

Convert to Dry Seals 

726.9% 

Pneumatic Controllers (Oil and Gas Production ) Low Bleed 6467.3% 

Overall Proposed NSPS Low Bleed 6.1%

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 6.5 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 
3-24 

of, without government intervention. The cost analysis of this draft 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 

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 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 
3-25 

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 

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 proposed NESHAP amendments. Unlike the controls for the proposed NSPS, 

the controls evaluated under the proposed 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 HAPs, VOCs, and methane, as well as a cost-effectiveness estimate for HAP 

reduction, based upon engineering (not social) costs. 

 
3-26 

Table 3-7 Summary of Estimated Capital and Annual Costs, Emissions Reductions, 

and HAP Reduction Cost-Effectiveness for Proposed 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 115 65,793 30,409 3,497,001 548 893 324 6,377 

Transmission - 

Small Glycol 

Dehydrators 19 19,537 19,000 361,000 243 475 172 1,483 

Storage Vessels 674 65,243 14,528 9,791,872 589 7,812 4,364 16,618 

Reporting and 

Recordkeeping --- 196 2,933 2,369,755 --- --- --- --- 

Total 808 16,019,871 1,381 9,243 4,859 10,576 

Note: Totals may not sum due to independent rounding.

Under the Proposed NESHAP Amendments, about 800 controls will be required, costing a 

total of $16.0 million (Table 3-7). We include reporting and recordkeeping costs as a unique line 

item showing these costs for the entire set of proposed amendments. These controls will reduce 

HAP emissions by about 1,400 tons, VOC emissions by about 9,200 tons, and methane by about 

4,859 tons. The cost-per-ton to reduce HAP emissions is estimated at about $11,000 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 proposed 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 HAPs, 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 proposed NSPS, the HAP and climate benefits can be considered “co-benefits”, and for 

the proposed 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 HAPs and methane. 

The proposed NSPS is anticipated to prevent 37,000 tons of HAPs, 540,000 tons of 

VOCs, and 3.4 million tons of methane from new sources, while the proposed NESHAP 

amendments is anticipated reduce 1,400 tons of HAPs, 9,200 tons of VOCs, and 4,900 tons of 

methane from existing sources. The specific control technologies for the proposed NSPS is also 

anticipated to have minor secondary disbenefits, including an increase of 990,000 tons of CO2, 

510 tons of NOx, 2,800 tons of CO, 7.6 tons of PM, and 1,000 tons of THC, and proposed 

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 THC. Both rules would have additional 

emission changes associated with the energy system impacts. The net CO2-equivalent emission 

reductions are 62 million metric tons for the proposed NSPS and 93 thousand metric tons for the 

proposed 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 upon valuation estimates 
4-2 

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 VOCs and HAPs 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 

of other regulations that result in specific costs of control and emission reductions. However, 

 

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 

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 by option. 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 Options for the Oil and Natural 

Gas NSPS and NESHAP amendments in 2015 (short tons per year) 

Pollutant NESHAP 

Amendments 

NSPS 

Option 1 

NSPS 

Option 2 (Proposed) 

NSPS 

Option 3 

HAPs 1,381 17,442 36,645 37,142 

VOCs 9,243 270,695 535,201 548,449 

Methane 4,859 1,574,498 3,386,154 3,442,283 
4-4 

4.3 Secondary Impacts Analysis for Oil and Gas Rules 

The control techniques to avert leaks and vents of VOCs and HAPs 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 VOCs and HAPs, 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 impacts for the selected option for the 

“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 
4-6 

lower. Through the combustion process, methane emissions are 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 

Completions of New Wells (NSPS) 587,991 302 5 1,644 622 

Recompletions of Existing Wells (NSPS) 398,341 205 - 1,114 422 

Pneumatic Controllers (NSPS) 22 1.0 2.6 - - 

Storage Vessels (NSPS) 856 0.5 0.0 2.4 0.9 

Total NSPS 987,210 508 7.6 2,760 1,045 

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 regulatory options 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 7-12Error! Reference source not found. 

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 1.6 million metric tons for the 

proposed NSPS option in 2015. This is in addition to the other secondary impacts and directly 

avoided emissions, for a total 62 million metric tons of CO2-equivalent emissions averted as 

shown in Table 4-4. Due to time limitations under the court-ordered schedule, we did not 

estimate the 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 Proposed Oil and Gas NSPS in 2015 (million metric tons) ("Consumer-Side")1

Fuel Type 

NSPS Option 1 (million 

metric tons change in 

CO2-e) 

NSPS Option 2 (million metric 

tons change in CO2-e) 

(Proposed) 

NSPS Option 3 (million 

metric tons change in 

CO2-e) 

Petroleum -0.51 -0.14 -0.18 

Natural Gas 2.63 1.35 1.03 

Coal -3.04 0.36 0.42 

Other 0.00 0.00 0.00 

Total modeled Change 

in CO2-e Emissions -0.92 1.57 1.27 

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 Proposed Oil and Gas NSPS in 2015 (million metric tons) 

Emissions Source NSPS 

Option 1 

NSPS Option 2 

(Proposed) 

NSPS 

Option 3 

NESHAP 

Amendments 

Averted CO2-e Emissions from New Sources1 -30.00 -64.51 -65.58 -0.09 

Additional CO2-e Emissions from Combustion and 

Supplemental Energy (Producer-side)2 0.90 0.90 0.90 0.01 

Total Modeled Change in Energy-related CO2-e 

Emissions (Consumer-side)3 -0.92 1.57 1.27 -- 

Total Change in CO2-e Emissions after 

Adjustment for Secondary Impacts -30.02 -62.04 -63.41 -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. We use the producer-side secondary impacts associated with the proposed NSPS option as a 

surrogate for the impacts of the other options. 

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 option. 
4-8 

Table 4-5 Summary of Emissions Changes for the Proposed Oil and Gas NSPS and 

NESHAP in 2015 (short tons per year) 

 Pollutant NSPS Option 

1 

NSPS Option 2 

(Proposed) 

NSPS Option 

3 NESHAP 

Change in Direct Emissions 

VOC -270,000 -540,000 -550,000 -9,200 

Methane -1,600,000 -3,400,000 -3,400,000 -4,900 

HAP -17,000 -37,000 -37,000 -1,400 

Change in Secondary 

Emissions (Producer-Side) 1

CO2 990,000 990,000 990,000 5,500 

NOx 510 510 510 2.9 

PM 7.6 7.6 7.6 0.1 

CO 2,800 2,800 2,800 16 

THC 1,000 1,000 1,000 6.0 

Change in Secondary 

Emissions (Consumer-Side) CO2-e -1,000,000 1,700,000 1,400,000 N/A 

Net Change in CO2-equivalent 

Emissions CO2-e -33,000,000 -68,000,000 -70,000,000 -96,000 

1 We use the producer-side secondary impacts associated with the proposed option as a surrogate for the impacts of 

the other options. 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 people 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 HAPs, EPA has quantified the benefits of 

potential reductions in the incidences of cancer and non-cancer 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/m3 of 

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 HAPs. 

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 (HAPs) 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 HAPs. 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 HAPs, 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 HAPs in this analysis. Instead, we provide a qualitative analysis of the health 

effects associated with the HAPs 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 HAPs are emitted from oil and 

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

distribution, or storage tanks. Emissions of eight HAPs make up a large percentage the total 
4-13 

HAP emissions by mass from the oil and gas sector: toluene, hexane, benzene, xylenes (mixed), 

ethylene glycol, methanol, ethyl benzene, and 2,2,4-trimethylpentane (U.S. EPA, 2011a). In the 

subsequent sections, we describe the health effects associated with the main HAPs 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 58,000 tons of 

HAPs 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, 2011c). The 

results for oil and gas production indicate that maximum lifetime individual cancer risks could be 

30 in-a-million for existing sources before and after controls with a cancer incidence of 0.02 

before and after controls. For existing natural gas transmission and storage, the maximum 

individual cancer risk decreases from 90-in-a-million before controls to 20-in-a-million after 

controls with a cancer incidence that decreases from 0.001 before controls to 0.0002 after 

controls. Benzene is the primary cancer risk driver. The results also indicate that significant 

noncancer impacts from existing sources are unlikely, especially after controls. EPA did not 

conduct a risk assessment for new sources affected by the NSPS. However, it is important to 

note that the magnitude of the HAP emissions avoided by new sources with the NSPS are more 

than an order of magnitude 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 VOCs 

4.5.1 VOCs as a PM2.5 precursor 

This rulemaking would reduce emissions of VOCs, which are a precursor to PM2.5. Most 

VOCs 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, 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 

VOCs 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 (2010c)). 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 VOCs, 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 VOCs (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 E

Atlanta $620 $1,500 $1,600 $1,200 $1,200 $860 $2,000 $1,100 $730 $920 $1,200 $

Chicago $1,500 $3,800 $4,000 $3,100 $3,000 $2,200 $4,900 $2,800 $1,800 $2,300 $3,000 $

Dallas $300 $740 $780 $610 $590 $420 $960 $540 $360 $450 $590 $

Denver $720 $1,800 $1,800 $1,400 $1,400 $1,000 $2,300 $1,300 $850 $1,100 $1,400 $

NYC/ 

Philadelphia $2,100 $5,200 $5,500 $4,300 $4,200 $3,000 $6,900 $3,900 $2,500 $3,200 $4,200 $

Phoenix $1,000 $2,500 $2,600 $2,000 $2,000 $1,400 $3,300 $1,800 $1,200 $1,500 $2,000 $

Salt Lake $1,300 $3,100 $3,300 $2,600 $2,500 $1,800 $4,100 $2,300 $1,500 $1,900 $2,500 $

San Joaquin $2,900 $7,000 $7,400 $5,800 $5,600 $4,000 $9,100 $5,200 $3,400 $4,300 $5,600 $

Seattle $280 $680 $720 $530 $550 $390 $890 $500 $330 $420 $550 $

National average $1,200 $3,000 $3,200 $2,400 $2,400 $1,700 $3,900 $2,200 $1,400 $1,800 $2,400 $

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

significant digits. These estimates have been updated from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currency year 

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

emissions would increase the benefit-per-ton estimates by approximately 4 percent to 52 percent. Assuming a 25 percent reduction i

decrease the benefit-per-ton estimates by 5 percent to 52 percent. EPA generally presents a range of benefits estimates derived from 

Laden et al. (2006) and provides the benefits estimates derived from the expert functions from Roman et al. (2008) as a characterizati
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, 2010c; 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 VOCs as an Ozone Precursor 

This rulemaking would reduce emissions of VOCs, 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 

VOCs and CO are important compounds for ozone formation, but biogenic VOCs 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 PMrelated 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 
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emissions is spatially heterogeneous depending on local air chemistry. Urban areas with a high 

population concentration are often VOC-limited, which means that ozone is most effectively 

reduced by lowering VOCs. 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 VOCs. Between these areas, ozone is relatively 

insensitive to marginal changes in both NOx and VOC. 

Due to time limitations under the court-ordered schedule, 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, we are unable to estimate the effect that reducing 

VOCs 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 VOCs 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 VOCs 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 

consistent with emissions modeled in the boiler analysis. Therefore, we do not believe that those 

 

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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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. This study provides the most comprehensive 

analysis to date of the benefits of measures to reduce SLCF gases including methane, ozone, and 

black carbon assessing the health, climate, and agricultural benefits of a suite of mitigation 

technologies. The report concludes that the climate is changing now, and these changes have the 

potential to “trigger abrupt transitions such as the release of carbon from thawing permafrost and 

biodiversity loss” (UNEP 2011). While reducing long-lived GHGs such as CO2 is necessary to 
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protect against long-term climate change, reducing SLCF gases including ozone is beneficial and 

will slow the rate of climate change within the first half of this century (UNEP 2011). 

4.7 Methane (CH4) 

4.7.1 Methane as an ozone precursor 

This rulemaking would reduce emissions of methane, a long-lived GHG and also a 

precursor to ozone. In remote areas, methane is a dominant precursor to tropospheric ozone 

formation (U.S. EPA, 2006a). Unlike NOx and VOCs, which affect ozone concentrations 

regionally and at hourly time scales, methane emission reductions require several decades for the 

ozone response to be fully realized, given methane’s relatively long atmospheric lifetime (HTAP, 

2010). Studies have shown that reducing methane can reduce global background ozone 

concentrations over several decades, which would benefit both urban and rural areas (West et al., 

2006). Therefore, reducing these emissions would reduce ozone formation, human exposure to 

ozone, and the incidence of ozone-related health effects. 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. 

4.7.2 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. According to the 

Intergovernmental Panel on Climate Change (IPCC) Fourth Assessment Report (2007), in 2004 

the cumulative changes in methane concentrations since preindustrial times contributed about 14 

percent to global warming due to anthropogenic GHG sources, making methane the second 

leading long-lived climate forcer after CO2 globally. 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. 
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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 proposal 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. 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 proposes emission control technologies and regulatory alternatives that 

will significantly decrease methane emissions from the oil and natural gas sector in the United 

States. The regulatory alternative proposed for this rule is expected to reduce methane emissions 

annually by about 3.4 million short tons or approximately 65 million metric tons CO2-e. These 

reductions represent about 26 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 

62 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 sectorlevel emissions to 2015 for this rulemaking. The climate co-benefit from these reductions are 
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equivalent of taking approximately 11 million typical passenger cars off the road or eliminating 

electricity use from about 7 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 

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. 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. 

 

48 US Environmental Protection Agency. Greenhouse Gas Equivalency Calculator available at: 

http://www.epa.gov/cleanenergy/energy-resources/calculator.html accessed 07/19/11. 
4-30 

Although there are relatively few region- or country-specific estimates of SCC in the 

literature, the results from one model suggest the ratio of domestic to global benefits of emission 

reductions varies with key parameter assumptions. For example, with a 2.5 or 3 percent discount 

rate, the U.S. benefit is about 7-10 percent of the global benefit, on average, across the scenarios 

analyzed. Alternatively, if the fraction of GDP lost due to climate change is assumed to be 

similar across countries, the domestic benefit would be proportional to the U.S. share of global 

GDP, which is currently about 23 percent. On the basis of this evidence, values from 7 to 23 

percent should be used to adjust the global SCC to calculate domestic effects. It is recognized 

that these values are approximate, provisional, and highly speculative. There is no a priori reason 

why domestic benefits should be a constant fraction of net global damages over time. 

(Interagency Working Group on Social Cost of Carbon, 2010). 

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. 

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 
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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 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 the longer-lived gases, 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. 

 In light of these limitations, and the significant contributions of non-CO2 emissions to 

climate change, further analysis is required to link non-CO2 emissions to economic impacts and 

to develop social cost estimates for methane specifically. Such work would feed into efforts to 

develop a monetized value of reductions in methane greenhouse gas emissions in assessing the 

co-benefits of this rulemaking. As part of ongoing work to further improve the SCC estimates, 

the interagency group hopes to develop methods to value greenhouse gases other than CO2, such 

as methane, by the time SCC estimates for CO2 emissions are revised. 

 The EPA recognizes that the methane reductions proposed in this rule will provide 

significant economic climate co-benefits to society. However, EPA finds itself in the position of 
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having no interagency accepted monetary values to place on these co-benefits. The ‘GWP 

approach’ of converting methane to CO2-e using the GWP of methane, as previously described, 

is one approximation method for estimating the monetized value of the methane reductions 

anticipated from this rule. This calculation uses the GWP of the non-CO2 gas to estimate CO2

equivalents and then multiplies these CO2 equivalent emission reductions by the SCC to generate 

monetized estimates of the co-benefits. If one makes these calculations for the proposed Option 

2 (including expected methane emission reductions from the NESHAP amendments and NSPS 

and considers secondary impacts) of the oil and gas rule, the 2015 co-benefits vary by discount 

rate and range from about $373 million to over $4.7 billion; the SCC at the 3 percent discount 

rate ($25 per metric ton) results in an estimate of $1.6 billion in 2015. These co-benefits equate 

to a range of approximately $110 to $1,400 per short ton of methane reduced depending upon the 

discount rate assumed with a per ton estimate of $480 at the 3 percent discount rate 

 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 as previously discussed. 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 proposal. The use of the SAR GWP values allows comparability 
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of data collected in this proposed 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 proposed in this rulemaking. 

 Due to the uncertainties involved with ‘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 proposal. Rather, the EPA presents the ‘GWP approach’ climate cobenefit estimates as an interim method to produce lower-bound estimates until the interagency 

group develops values for non-CO2 GHGs. EPA requests comments from interested parties and 

the public about this interim approach specifically and more broadly about appropriate methods 

to monetize the climate co-benefits of methane reductions. In particular, EPA seeks public 

comments to this proposed rulemaking regarding social cost of methane estimates that may be 
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used to value the co-benefits of methane emission reductions anticipated for the oil and gas 

industry from this rule. Comments specific to whether GWP is an acceptable method for 

generating a placeholder value for the social cost of methane until interagency modeled estimates 

become available are welcome. Public comments may be provided in the official docket for this 

proposed rulemaking in accordance with the process outlined in the preamble for the rule. These 

comments will be considered in developing the final rule for this rulemaking. 

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Particulate Matter (Final Report). EPA-600-R-08-139F. National Center for 

Environmental Assessment—RTP Division. 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. Accessed March 30, 

2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2009b. Technical Support Document for 

Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under 

Section 202(a) of the Clean Air Act. 

<http://www.epa.gov/climatechange/endangerment/downloads/Endangerment%20TSD.p

d>. Accessed March 30, 2011. 
4-37 

U.S. Environmental Protection Agency (U.S. EPA). 2010a. Regulatory Impact Analysis, 

National Ambient Air Quality Standards for Ozone. Office of Air Quality Planning and 

Standards, Research Triangle Park, NC. <http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-

supplemental_analysis_full.pdf>. Accessed March 30, 2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2011b. Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2009. EPA 430-R-11-005. Office of Atmospheric Programs, 

Washington, DC. <http://epa.gov/climatechange/emissions/usinventory.html >. 

Accessed July 21, 2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2010c. Regulatory Impact Analysis for the 

Proposed Federal Transport Rule. Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. 

<http://www.epa.gov/ttn/ecas/regdata/RIAs/proposaltrria_final.pdf>. Accessed March 

30, 2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2010d. Regulatory Impact Analysis for the 

SO2 NAAQS. Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

< http://www.epa.gov/ttn/ecas/regdata/RIAs/fso2ria100602full.pdf>. Accessed March 30, 

2011. 

U.S Environmental Protection Agency (U.S. EPA). 2011a. Draft Residual Risk Assessment for 

the Oil and Natural Gas Source Category. Office of Air Quality Planning and Standards. 

Office of Air and Radiation. 

U.S. Environmental Protection Agency (U.S. EPA). 2010e. 40 CFR Part 98 Mandatory 

Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems; Final Rule. Federal 

Register Vol. 75, No. 229, November 30, 2010. 74458-74515. r<

<http://edocket.access.gpo.gov/2010/pdf/2010-28655.pdf> Accessed March 30, 2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2010f. Prevention of Significant 

Deterioration and Title V Greenhouse Gas Tailoring Rule. Federal Register Vol. 75, No. 

106, June 3, 2010. 31514-31608 <http://www.gpo.gov/fdsys/pkg/FR-2010-06-

03/pdf/2010-11974.pdf#page=1> Accessed March 30, 2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2011a. The Benefits and Costs of the Clean 

Air Act from 1990 to 2020. Office of Air and Radiation, Washington, DC. March. 

<http://www.epa.gov/air/sect812/feb11/fullreport.pdf>. Accessed March 30, 2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2011b. Regulatory Impact Analysis: 

National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, 

and Institutional Boilers and Process Heaters. Office of Air Quality Planning and 

Standards, Research Triangle Park, NC. February. 

<http://www.epa.gov/ttn/ecas/regdata/RIAs/boilersriafinal110221_psg.pdf>. Accessed 

March 30, 2011. 
4-38 

U.S. Environmental Protection Agency (U.S. EPA). 2011c. Draft Residual Risk Assessment for 

the Oil and Gas Production and Natural Gas Transmission and Storage Source 

Categories. Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

April. 

U.S. Environmental Protection Agency (U.S. EPA). 2011d. 2005 National-Scale Air Toxics 

Assessment. Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

March. < http://www.epa.gov/ttn/atw/nata2005/> Accessed March 30, 2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2011e. Draft Inventory of the U.S. 

Greenhouse Gas Emissions and Sinks 1990. Report No. 430-R-11-005. February. 

<http://www.epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-

Complete_Report.pdf>. Accessed March 30, 2011. 

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

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

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

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

<http://yosemite.epa.gov/sab%5CSABPRODUCT.NSF/34355712EC011A358525719A0

05BF6F6/$File/ecwkshp02001%2Bappa-g.pdf>. Accessed March 30, 2011. 

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

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

001. July. 

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

3/$File/EPA-COUNCIL-08-001-unsigned.pdf>. Accessed March 30, 2011. 

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

controls.” PNAS 103:11:3988-3993. 
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 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 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 a RIA 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 proposed rules. 

 
5-2 

Table 5-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the 

Proposed Oil and Natural Gas NSPS and NESHAP Amendments in 2015 (millions of 

2008$)1 

 Proposed NSPS Proposed NESHAP 

Amendments 

Proposed NSPS and 

NESHAP Amendments 

Combined 

Total Monetized Benefits2 N/A N/A N/A 

Total Costs3 -$45 million $16 million -$29 million 

Net Benefits N/A N/A N/A 

Non-monetized Benefits 37,000 tons of HAPs 1,400 tons of HAPs 38,000 tons of HAPs 

 540,000 tons of VOCs 9,200 tons of VOCs 540,000 tons of VOCs 

 3.4 million tons of methane 4,900 tons of methane 3.4 million tons of methane 

Health effects of HAP 

exposure5

Health effects of HAP 

exposure5

Health effects of HAP 

exposure5

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 HAPs, 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 proposed NSPS are anticipated to have minor 

secondary disbenefits, including an increase of 990,000 tons of CO2, 510 tons of NOx, 7.6 tons of PM, 2,800 tons of 

CO, and 1,000 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system 

impacts. The net CO2-equivalent emission reductions are 62 million metric tons. 

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

4 The negative cost for the NSPS Options 1 and 2 reflects the inclusion of revenues from additional natural gas and 

hydrocarbon condensate recovery that are estimated as a result of the proposed 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 HAPs and climate effects are co-benefits. 
5-3 

5.2 Paperwork Reduction Act 

The information collection requirements in this proposed action have been submitted for 

approval to OMB under the PRA, 44 U.S.C. 3501, et seq. The ICR document prepared by the 

EPA has been assigned EPA ICR Numbers 1716.07 (40 CFR part 60, subpart OOOO), 1788.10 

(40 CFR part 63, subpart HH), 1789.07 (40 CFR part 63, subpart HHH), and 1086.10 (40 CFR 

part 60, subparts KKK and subpart LLL). 

The information to be collected for the proposed NSPS and the proposed NESHAP 

amendments are based on notification, recordkeeping, and reporting requirements in the 

NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators 

subject to national emission standards. These recordkeeping and reporting requirements are 

specifically authorized by section 114 of the CAA (42 U.S.C. 7414). All information submitted 

to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of 

confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, 

subpart B. 

These proposed rules would require maintenance inspections of the control devices, but 

would not require any notifications or reports beyond those required by the General Provisions. 

The recordkeeping requirements require only the specific information needed to determine 

compliance. 

For sources subject to the proposed NSPS, the burden represents labor hours and costs 

associated from annual reporting and recordkeeping for each affected facility. The estimated 

burden is based on the annual expected number of affected operators for the first three years 

following the effective date of the standards. The burden is estimated to be 560,000 labor hours 

at a cost of around$18 million per year. This includes the labor and cost estimates previously 

estimated for sources subject to 40 CFR part 60, subpart KKK and subpart LLL (which is being 

incorporated into 40 CFR part 60, subpart OOOO). The average hours and cost per regulated 

entity, which is assumed to be on a per operator basis except for natural gas processing plants 

(which are estimated on a per facility basis) subject to the NSPS for oil and natural gas 

production and natural gas transmissions and distribution facilities would be 110 hours per 

response and $3,693 per response based on an average of 1,459 operators responding per year 
5-4 

and 16 responses per year. The majority of responses are expected to be notifications of 

construction. One annual report is required that may include all affected facilities owned per 

each operator. Burden by for the proposed NSPS was based on EPA ICR Number 1716.07. 

The estimated recordkeeping and reporting burden after the effective date of the proposed 

amendments is estimated for all affected major and area sources subject to the oil and natural gas 

production NESHAP (40 CFR 63, subpart HH) to be approximately 63,000 labor hours per year 

at a cost of $2.1 million per year. For the natural gas transmission and storage NESHAP, the 

recordkeeping and reporting burden is estimated to be 2,500 labor hours per year at a cost of 

$86,800 per year. This estimate includes the cost of reporting, including reading instructions, and 

information gathering. Recordkeeping cost estimates include reading instructions, planning 

activities, and conducting compliance monitoring. The average hours and cost per regulated 

entity subject to the oil and natural gas production NESHAP would be 72 hours per year and 

$2,500 per year based on an average of 846 facilities per year and three responses per facility. 

For the natural gas transmission and storage NESHAP, the average hours and cost per regulated 

entity would be 50 hours per year and $1,600 per year based on an average of 53 facilities per 

year and three responses per facility. Burden is defined at 5 CFR 1320.3(b). Burden for the oil 

and natural gas production NESHAP is estimated under EPA ICR Number 1788.10. Burden for 

the natural gas transmission and storage NESHAP is estimated under EPA ICR Number 1789.07. 

5.3 Regulatory Flexibility Act 

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

include small businesses, small governmental jurisdictions, and small not-for-profit enterprises. 

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
5-5 

population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise 

which is independently owned and operated and is not dominant in its field. 

5.3.1 Proposed NSPS 

After considering the economic impact of the Proposed NSPS on small entities, I certify 

that this action will not have a significant economic impact on a substantial number of small 

entities (SISNOSE). EPA performed a screening analysis for impacts on a sample of expected 

affected small entities by comparing compliance costs to entity revenues. Based upon the 

analysis in Section 7.4 in this RIA, EPA recognizes that a subset of small firms is likely to be 

significantly impacted by the proposed NSPS. However, 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 the firm-level compliance cost estimates used in the 

small business impacts analysis are likely over-estimates of the compliance costs faced by firms 

under the Proposed NSPS; these estimates do not include the revenues that producers are 

expected receive from the additional natural gas 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 well completion-related activities, we expect the impact on well-related compliance 

costs to be significantly mitigated, if not fully offset. Although this final rule will not have a 

significant economic impact on a substantial number of small entities, EPA nonetheless has tried 

to reduce the impact of this rule on small entities by the selection of highly cost-effective 

controls and specifying monitoring requirements that are the minimum to insure compliance. 

5.3.2 Proposed NESHAP Amendments 

After considering the economic impact of the Proposed NESHAP Amendments on small 

entities, I certify that this action will not have a significant economic impact on a substantial 

number of small entities. Based upon the analysis in Section 7.4 in this RIA, we estimate that 62 

of the 118 firms (53 percent) that own potentially affected facilities are small entities. EPA 

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

compliance costs to entity revenues. Among the small firms, 52 of the 62 (84 percent) are likely 

to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to 
5-6 

revenues. Meanwhile 10 firms (16 percent) are likely to have impacts greater than 1 percent. 

Four of these 10 firms are likely to have impacts greater than 3 percent. While these 10 firms 

might receive significant impacts from the proposed 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. Although this final rule will not impact a substantial number 

of small entities, 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 proposed rule does not contain a federal mandate that may result in expenditures of 

$100 million or more for state, local, and tribal governments, in the aggregate, or to the private 

sector in any one year. Thus, this proposed rule is not subject to the requirements of sections 202 

or 205 of UMRA. 

This proposed 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 proposed rule 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. Thus, Executive Order 13132 does not apply to this 

proposed rule. 

5.6 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments 

Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) the EPA may 

not issue a regulation that has tribal implications, that imposes substantial direct compliance 
5-7 

costs, and that is not required by statute, unless the federal government provides the funds 

necessary to pay the direct compliance costs incurred by tribal governments, or the EPA consults 

with tribal officials early in the process of developing the proposed regulation and develops a 

tribal summary impact statement. The EPA has concluded that this proposed rule will not have 

tribal implications, as specified in Executive Order 13175. It will not have substantial direct 

effect on tribal governments, on the relationship between the federal government and Indian 

tribes, or on the distribution of power and responsibilities between the federal government and 

Indian tribes, as specified in Executive Order 13175. Thus, Executive Order 13175 does not 

apply to this action. 

5.7 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks 

This proposed rule is subject to Executive Order 13045 (62 FR 19885, April 23, 1997) 

because it is economically significant as defined in Executive Order 12866. However, 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. EPA’s risk assessments (included in the docket for this proposed rule) 

demonstrate 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 

 Executive Order 13211, (66 FR 28,355, May 22, 2001), provides that agencies shall 

prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, 

OMB, a Statement of Energy Effects for certain actions identified as significant energy actions. 

Section 4(b) of Executive Order 13211 defines “significant energy actions” as “any action by an 

agency (normally published in the Federal Register) that promulgates or is expected to lead to 

the promulgation of a final rule or regulation, including notices of inquiry, advance notices of 

proposed rulemaking, and notices of proposed rulemaking: 1)(i) that is a significant regulatory 

action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant 
5-8 

adverse effect on the supply, distribution, or use of energy; or 2) that is designated by the 

Administrator of the Office of Information and Regulatory Affairs as a significant energy 

action.” 

 The proposed 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 proposed 

NESHAP amendments are unlikely to have a significant adverse effect on the supply, 

distribution, or use of energy. As such, the proposed NESHAP amendments are not “significant 

energy actions” as defined in Executive Order 13211, (66 FR 28355, May 22, 2001). 

 The proposed NSPS is also unlikely to have a significant adverse effect on the supply, 

distribution, or use of energy. As such, the proposed 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 proposed 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. 

 Proposed 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 proposed NSPS also captures saleable condensates. The 

revenues from additional natural gas and condensate recovery are expected to offset the costs of 

implementing the proposed NSPS. 

 The analysis of energy impacts for the proposed NSPS that includes the additional 

product recovery shows that domestic natural gas production is estimated to increase (20 billion 

cubic feet or 0.1 percent) and natural gas prices to decrease ($0.04/Mcf or 0.9 percent at the 

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 

($0.02/barrel or less than 0.1 percent at the wellhead for producers in the lower 48 states) in 

2015, the year of analysis. All prices are in 2008 dollars. 
5-9 

 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 National Technology Transfer and Advancement Act of 1995 

(“NTTAA”), Public Law No. 104-113 (15 U.S.C. 272 note) directs the EPA to use 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. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the 

Agency decides not to use available and applicable VCS. 

 The proposed rule involves technical standards. Therefore, the requirements of the 

NTTAA apply to this action. We are proposing to revise 40 CFR part 63, subparts HH and HHH 

to allow ANSI/ASME PTC 19.10–1981, Flue and Exhaust Gas Analyses (Part 10, Instruments 

and Apparatus) to be used in lieu of EPA Methods 3B, 6 and 16A. This standard is available 

from the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, 

NY 10016-5990. Also, we are proposing to revise 40 CFR part 63, subpart HHH, to allow 

ASTM D6420-99(2004), “Test Method for Determination of Gaseous Organic Compounds by 

Direct Interface Gas Chromatography/Mass Spectrometry” to be used in lieu of EPA Method 18. 

For a detailed discussion of this VCS, and its appropriateness as a substitute for Method 18, see 

the final oil and natural gas production NESHAP (Area Sources) (72 FR 36, January 3, 2007). 

 As a result, the EPA is proposing ASTM D6420-99 for use in 40 CFR part 63, subpart 

HHH. The EPA also proposes to allow Method 18 as an option in addition to ASTM D6420-

99(2004). This would allow the continued use of GC configurations other than GC/MS. 

 The EPA welcomes comments on this aspect of the proposed rulemaking and, 

specifically, invites the public to identify potentially-applicable VCS and to explain why such 

standards should be used in this regulation. 
5-10 

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 Environmental Justice (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. 

To examine the potential for any EJ issues that might be associated with each source 

category, we evaluated the distributions of HAP-related cancer and noncancer risks across 

different social, demographic, and economic groups within the populations living near the 

facilities where these source categories are located. The methods used to conduct demographic 

analyses for this rule are described in section VII.D of the preamble for this rule. The 

development of demographic analyses to inform the consideration of EJ issues in EPA 

rulemakings is an evolving science. The EPA offers the demographic analyses in this proposed 

rulemaking as examples of how such analyses might be developed to inform such consideration, 

and invites public comment on the approaches used and the interpretations made from the 

results, with the hope that this will support the refinement and improve utility of such analyses 

for future rulemakings. 

For the demographic analyses, we focused on the populations within 50 km of any 

facility estimated to have exposures to HAP which result in cancer risks of 1-in-1 million or 

greater, or noncancer HI of 1 or greater (based on the emissions of the source category or the 

facility, respectively). We examined the distributions of those risks across various demographic 

groups, comparing the percentages of particular demographic groups to the total number of 

people in those demographic groups nationwide. The results, including other risk metrics, such 

as average risks for the exposed populations, are documented in source category-specific 

technical reports in the docket for both source categories covered in this proposal. 

 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 
5-11 

associated with an acceptable level of risk and that the proposed 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 multi-pathway 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.
6-1 

6 COMPARISON OF BENEFITS AND COSTS 

Because we are unable to estimate the monetary value of the emissions reductions from 

the proposed 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 cost of the proposed NSPS in the analysis year of 2015 when the additional 

natural gas and condensate recovery is included in the analysis is estimated at -$45 million for 

domestic producers and consumers. EPA anticipates that this rule would prevent 540,000 tons of 

VOC, 3.4 million tons of methane, and 37,000 tons of HAPs in 2015 from new sources. In 2015, 

EPA estimates the costs for the NESHAP amendments floor option to be $16 million.49 EPA 

anticipates that this rule would reduce 9,200 tons of VOC, 4,900 tons of methane, and 1,400 tons 

of HAPs in 2015 from existing sources. For the NESHAP amendments, a break-even analysis 

suggests that HAP emissions would need to be valued at $12,000 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 $1,700 per ton 

or the methane emissions would need to be valued at $3,300 per ton for the benefits to exceed 

the costs. All estimates are in 2008 dollars. 

For the proposed 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 

 

49 See Section 3 of this RIA for more information regarding the cost estimates for the NESHAP. 
6-2 

of natural gas would need to be at least $3.77 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 

$4.26 per Mcf in 2015. In addition to the revenue from product recovery, the NSPS would avert 

emissions of VOCs, HAPs, 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, VOCs would need to be valued at $260 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 

$(1,200)

$(1,100)

$(1,000)

$(900)

$(800)

$(700)

$(600)

$(500)

$(400)

$(300)

$(200)

$(100)

$-

$100 

$200 

$300 

$400 

$500 

$600 

$700 

$- $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 

Natural Gas

Price

Assumption
6-3 

of VOC emissions are valued at $280 to $7,000 per ton across a range of eight urban areas.50 In 

addition, ozone benefits have been previously valued at $240 to $1,000 per ton of VOC reduced. 

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., VOCs 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, HAPs, and methane. 

Table 6-1 and Table 6-2 present the summary of the benefits, costs, and net benefits for 

the NSPS and NESHAP amendment options, respectively. Table 6-3 provides a summary of the 

direct and secondary emissions changes for each option. 

 

 

50 See Section 4.5 of this RIA for more information regarding PM2.5 benefits and Section 4.6 for more information 

regarding ozone benefits. 
6-4 

Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the 

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

 Option 1: Alternative Option 2: Proposed4

 Option 3: Alternative 

Total Monetized Benefits2 N/A N/A N/A 

Total Costs3 -$19 million -$45 million $77 million 

Net Benefits N/A N/A N/A 

Non-monetized Benefits 17,000 tons of HAPs5

 37,000 tons of HAPs5 37,000 tons of HAPs5

 270,000 tons of VOCs 540,000 tons of VOCs 550,000 tons of VOCs 

 1.6 million tons of methane 3.4 million tons of methane 3.4 million tons of methane 

Health effects of HAP 

exposure5

Health effects of HAP 

exposure5

Health effects of HAP 

exposure5

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 HAPs, 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 proposed NSPS are anticipated to have minor 

secondary disbenefits, including an increase of 990,000 tons of CO2, 510 tons of NOx, 7.6 tons of PM, 2,800 tons of 

CO, and 1,000 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system 

impacts. The net CO2-equivalent emission reductions are 62 million metric tons. 

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

4 The negative cost for the NSPS Options 1 and 2 reflects the inclusion of revenues from additional natural gas and 

hydrocarbon condensate recovery that are estimated as a result of the proposed 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 HAPs and climate effects are co-benefits. 

 
6-5 

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

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

 Option 1: Proposed (Floor) 

Total Monetized Benefits2 N/A 

Total Costs3 $16 million 

Net Benefits N/A 

Non-monetized Benefits 1,400 tons of HAPs 

9,200 tons of VOCs4

4,900 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 HAPs, 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 proposed NESHAP are 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 THC as well as emission reductions associated with the energy system impacts. The net CO2-equivalent 

emission reductions are 93 thousand 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 Proposed Oil and Gas NSPS and 

NESHAP in 2015 (short tons per year) 

 Pollutant NSPS 

Option 1 

NSPS Option 2 

(Proposed) 

NSPS Option 

3 NESHAP 

Change in Direct Emissions 

VOC -270,000 -540,000 -550,000 -9,200 

Methane -1,600,000 -3,400,000 -3,400,000 -4,900 

HAP -17,000 -37,000 -37,000 -1,400 

Change in Secondary 

Emissions (Producer-Side) 1

CO2 990,000 990,000 990,000 5,500 

NOx 510 510 510 2.9 

PM 7.6 7.6 7.6 0.1 

CO 2,800 2,800 2,800 16 

THC 1,000 1,000 1,000 6.0 

Change in Secondary 

Emissions (Consumer-Side) CO2-e -1,000,000 1,700,000 1,400,000 N/A 

Net Change in CO2-equivalent 

Emissions CO2-e -33,000,000 -68,000,000 -70,000,000 -96,000 

1 We use the producer-side secondary impacts associated with the proposed NSPS option as a surrogate for the 

impacts of the other options. 
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 Proposed NSPS 

We use the National Energy Modeling System (NEMS) to estimate the impacts of the 

proposed NSPS on the U.S. energy system. The impacts we estimate include changes in drilling 

activity, price and quantity changes in the production and consumption of crude oil and natural 

gas, and changes in international trade of crude oil and natural gas. We evaluate whether and to 

what extent the increased production costs imposed by the 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 

proposed NSPS shows that about 97 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 
7-2 

completed after 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 2011.51 The RIA baseline is consistent with that of the Annual 

Energy Outlook 2011 which is used extensively in Section 2 in the Industry Profile. 

 

51 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 

expected to be 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 regulatory 

options. 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 

proposed 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 relevant NSPS option. We estimate those costs as 

a function of new wells expected to be drilled in a representative year. To arrive at estimates of 
7-7 

the per well 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 ten 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 

Option 1 NEMS 

Option 2 

(Proposed) Option 3 

Equipment Leaks 

 Well Pads Subpart VV Not in Option Not in Option $3,552 Oil and 

Gas 

 Gathering and Boosting 

Stations 

Subpart VV Not in Option Not in Option $806 Gas 

 Processing Plants Subpart VVa Not in Option $56 $56 None 

 Transmission 

Compressor Stations 

Subpart VV Not in Option Not in Option $320 Gas 

Reciprocating 

Compressors 

 Well Pads Annual 

Monitoring/ 

Maintenance 

Not in Option Not in Option Not in Option None 

 Gathering/Boosting 

Stations 

AMM $17 $17 $17 Gas 

 Processing Plants AMM $12 $12 $12 Gas 

 Transmission 

Compressor Stations 

AMM $19 $19 $19 Gas 

 Underground Storage 

Facilities 

AMM $1 $1 $1 Gas 

Centrifugal Compressors 

 Processing Plants Dry Seals/Route 

to Process or 

Control 

-$113 -$113 -$113 Gas 

 Transmission 

Compressor Stations 

Dry Seals/Route 

to Process or 

Control 

-$62 -$62 -$62 Gas 

Pneumatic Controllers - 

 Oil and Gas Production Low 

Bleed/Route to 

Process 

-$698 -$698 -$698 Oil and 

Gas 

 Natural Gas 

Transmission and 

Storage 

Low 

Bleed/Route to 

Process 

$0.10 $0.10 $0.10 Gas 

Storage Vessels 

 High Throughput 95% control $143 $143 $143 Oil and 

Gas 

 Low Throughput 95% control Not in Option Not in Option Not in Option 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/Recompletion Costs (2008$) 

Wells Applied To 

Option 1 in NEMS 

Option 2 

(proposed) Option 3 

Well Completions 

 Hydraulically Fractured 

Gas Wells REC -$1,275 -$1,275 -$1,275 New Tight Sand/ 

Shale Gas/CBM 

 Conventional Gas Wells Combustion Not in Option Not in Option Not in Option None 

 Oil Wells Combustion Not in Option Not in Option Not in Option None 

Well Recompletions 

 Hydraulically Fractured 

Gas Wells (post-NSPS 

wells) 

REC -$1,535 -$1,535 -$1,535 

Existing Tight 

Sand/ Shale Gas 

/Coalbed Methane 

 Hydraulically Fractured 

Gas Wells (existing 

wells) 

REC Not in Option -$1,535 -$1,535 

Existing Tight 

Sand/ Shale Gas 

/Coalbed Methane 

 Conventional Gas Wells Combustion Not in Option Not in Option Not in Option None 

 Oil Wells Combustion Not in Option Not in Option Not in Option 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 

proposed NSPS. 

 For all control options, 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 
7-10 

estimation procedure similar to that of entering compliance costs into NEMS on a per well basis 

for new wells. Because each NSPS Option is composed of a different suite of emissions 

controls, the per-well natural gas recovery value for new wells is different across wells. For 

Option 1, we estimate that natural gas recovery is 5,739 Mcf per well. For Option 2 and Option 

3, we estimate that natural gas recovery is 5,743 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 (in proposed Option 2 and Option 3) differently in that we estimated the natural gas 

recovery by natural gas resource type and NSPS Option 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 in proposed 

Option 2 and Option 3 to be 78.7 bcf, with 38.4 bcf accruing to shale gas, 31.4 bcf accruing to 

tight sands, and 8.9 bcf accruing to CBM, respectively. 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 three NSPS options. 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 options 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, for the three NSPS options and in the baseline. 

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

 Future NSPS Scenario, 2015 

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

 

Successful Wells Drilled 

 Natural Gas 16,373 19,097 19,191 18,935 18,872 

 Crude Oil 10,352 11,025 11,025 11,025 11,028 

Total 26,725 30,122 30,216 29,960 29,900 

 

% Change in Successful Wells Drilled from Baseline 

 Natural Gas 0.49% -0.85% -1.18% 

 Crude Oil 0.00% 0.00% 0.03% 

 Total 0.31% -0.54% -0.74%

We estimate that the number of successful natural gas wells drilled increases slightly for Option 

1, while the number of successful crude oil wells drilled does not change. In Options 2, where 

costs of the natural gas processing plants equipment leaks standard and REC requirements for 

existing wells apply, natural gas wells drilling is forecast to decrease less than 1 percent, while 

crude oil drilling does not change. For Option 3, where the addition of an additional equipment 
7-12 

leak standards add to the incremental costs, natural gas well drilling is estimated to decrease 

about 1.2%. The number of successful crude oil wells drilled under Option 3 increases very 

slightly. While it may seem counter-intuitive that the number of successful crude wells 

increased as costs increase, it is important to note that crude oil and natural gas drilling compete 

with each other for factors of production, such as labor and material. The environmental 

compliance costs of the NSPS options predominantly affect natural gas drilling. As natural gas 

drilling declines, for example, as a result of increased compliance costs, crude oil drilling may 

increase because of the increased availability of labor and material, as well as the likelihood that 

crude oil can substitute for natural gas to some extent. 

 Table 7-4 presents the forecast of successful wells by well type, for onshore drilling in 

the lower 48 states. The results show that conventional well drilling is unaffected by the 

regulatory options, 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 impacts on drilling tight sands, 

shale gas, and coalbed methane vary by option. 

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

Options 

 Future NSPS Scenario, 2015

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

 

Successful Wells Drilled 

 Conventional Gas Wells 7,267 7,607 7,607 7,607 7,607 

 Tight Sands 2,441 2,772 2,791 2,816 2,780 

 Shale Gas 5,007 7,022 7,074 6,763 6,771 

 Coalbed Methane 1,593 1,609 1,632 1,662 1,627 

 Total 16,308 19,010 19,104 18,849 18,785 

 

% Change in Successful Wells Drilled from Baseline 

 Conventional Gas Wells 0.00% 0.00% 0.00% 

 Tight Sands 0.70% 1.60% 0.29% 

 Shale Gas 0.74% -3.68% -3.57% 

 Coalbed Methane 1.44% 3.28% 1.09% 

 Total 0.50% -0.85% -1.18%
7-13 

Well drilling in tight sands is estimated to increase slightly from the baseline under all three 

options, 0.70 percent, 1.60 percent, and 0.29% for Options 1, 2, and 3, respectively. Wells in 

CBM reserves are also estimated to increase from the baseline under all three options, or 1.44 

percent, 3.28 percent, and 1.09 percent for Options 1, 2, and 3, respectively. However, drilling 

in shale gas is forecast to decline from the baseline under Options 2 and 3, by 3.68 percent and 

3.57 percent, respectively. 

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 options, as of 2015. Domestic crude oil production is not forecast to 

change under any of the three regulatory options, again because impacts on crude oil drilling of 

the NSPS are expected to be negligible. 

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

 Future NSPS Scenario, 2015 

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

Domestic Production 

 Natural Gas (trillion cubic feet) 21.05 22.43 22.47 22.45 22.44 

 Crude Oil (million barrels/day) 5.46 5.81 5.81 5.81 5.81 

 

% Change in Domestic Production from Baseline 

 Natural Gas 0.18% 0.09% 0.04% 

 Crude Oil 0.00% 0.00% 0.00% 

Natural gas production, on the other hand, increases under all three regulatory options for the 

NSPS from the baseline. A main driver for these increases is the additional natural gas recovery 

engendered by the control requirements. Another driver for the increases under Option 1 is the 

increase in natural gas well drilling. While we showed earlier that natural gas drilling is 

estimated to decline under Options 2 and 3, the increased natural gas recovery is sufficient to 

offset the production loss from relatively fewer producing wells. 

 For the proposed option, the NEMS analysis shown in Table 7-5 estimates a 20 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 
7-14 

proposed NSPS (approximately 180 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 20 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 180 bcf of natural gas. For example, as shown in Table 7-4, about 11,200 

new unconventional natural gas wells are completed under the proposed NSPS; using 

assumptions from the engineering cost analysis about RECs required under State regulations and 

exploratory wells exempted from REC requirements, about 9,000 NSPS-required RECs would 

be performed on new natural gas well completions, according to the NEMS analysis. This 

recovered natural gas substitutes for natural gas that would be produced from the ground absent 

the rule. In effect, then, about 160 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. 

Production from conventional natural gas wells and CBM wells are estimated to increase under 

all NSPS regulatory options. Production from shale gas reserves is estimated to decrease under 

Options 2 and 3, however, from the baseline projection. Production from tight sands is forecast 

to decline slightly under Option 1. 

 
7-15 

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

Options 

 Future NSPS Scenario, 2015 

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

Natural Gas Production by Well Type (trillion cubic feet) 

 Conventional Gas Wells 4.06 3.74 3.75 3.76 3.76 

 Tight Sands 5.96 5.89 5.87 6.00 6.00 

 Shale Gas 5.21 7.20 7.26 7.06 7.06 

 Coalbed Methane 1.72 1.67 1.69 1.72 1.71 

 Total 16.95 18.51 18.57 18.54 18.53 

 

% Change in Natural Gas Production by Well Type from Baseline 

 Conventional Gas Wells 0.32% 0.42% 0.48% 

 Tight Sands -0.43% 1.82% 1.72% 

 Shale Gas 0.73% -1.97% -1.93% 

 Coalbed Methane 1.07% 2.86% 2.60% 

 Total 0.31% 0.16% 0.13% 

Note: Totals may not sum due to independent rounding. 

Overall, of the regulatory options, the proposed Option 2 is estimated to have the highest natural 

gas production from onshore wells in the lower 48 states, showing a 1.2% increase over the 

baseline projection. 

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. All NSPS 

options show a decrease in wellhead natural gas and crude oil prices. 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 emissions (in Options 1, 2, and 3) and 

in capturing recompletion emissions (in Options 2 and 3).

 
7-16 

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

Options 

 Future NSPS Scenario, 2015 

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

Lower 48 Average Wellhead Price 

 Natural Gas (2008$ per Mcf) 4.07 4.22 4.18 4.18 4.19

 Crude Oil (2008$ per barrel) 83.65 94.60 94.59 94.58 94.58

 

% Change in Lower 48 Average Wellhead Price from Baseline 

 Natural Gas -0.94% -0.94% -0.71%

 Crude Oil -0.01% -0.02% -0.02%

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 across 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 

Options 

 Future NSPS Scenario, 2015 

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

Delivered Prices (2008$ per million BTU) 

 Residential 10.52 10.35 10.32 10.32 10.33 

 Commercial 9.26 8.56 8.52 8.53 8.54 

 Industrial 4.97 5.08 5.05 5.05 5.06 

 Electric Power 4.81 4.77 4.73 4.74 4.75 

 Transportation 12.30 12.24 12.20 12.22 12.22 

 Average 6.76 6.59 6.55 6.57 6.57 

 

% Change in Delivered Prices from Baseline 

 Residential -0.29% -0.29% -0.19%

 Commercial -0.47% -0.35% -0.23%

 Industrial -0.59% -0.59% -0.39%

 Electric Power -0.84% -0.63% -0.42%

 Transportation -0.33% -0.16% -0.16%

 Average -0.60% -0.41% -0.30%
7-17 

Final consumption of natural gas is also estimated to increase in 2015 from the baseline 

under all NSPS options, 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 Options 

 Future NSPS Scenario, 2015 

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

Consumption (trillion cubic feet) 

 Residential 4.76 4.81 4.81 4.81 4.81 

 Commercial 3.22 3.38 3.38 3.38 3.38 

 Industrial 6.95 8.05 8.06 8.06 8.06 

 Electric Power 7.00 6.98 7.00 6.98 6.97 

 Transportation 0.03 0.04 0.04 0.04 0.04 

 Pipeline Fuel 0.64 0.65 0.65 0.66 0.66 

 Lease and Plant Fuel 1.27 1.20 1.21 1.21 1.21 

 Total 23.86 25.11 25.15 25.14 25.13 

 

% Change in Consumption from Baseline 

 Residential 0.00% 0.00% 0.00% 

 Commercial 0.00% 0.00% 0.00% 

 Industrial 0.12% 0.12% 0.12% 

 Electric Power 0.29% 0.00% -0.14% 

 Transportation 0.00% 0.00% 0.00% 

 Pipeline Fuel 0.00% 1.54% 1.54% 

 Lease and Plant Fuel 0.83% 0.83% 0.83% 

 Total 0.16% 0.12% 0.08%

Note: Totals may not sum due to independent rounding. 

7.2.3.3 Impacts on Imports and National Fuel Mix 

The NEMS modeling shows that impacts from all NSPS options are not sufficiently large 

to affect the trade balance of natural gas. As shown in Table 7-10, estimates of crude oil and 

natural gas imports do not vary from the baseline in 2015 for each regulatory option. 

 
7-18 

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

 Future NSPS Scenario, 2015 

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

Net Imports 

 Natural Gas (trillion cubic feet) 2.75 2.69 2.69 2.69 2.69 

 Crude Oil (million barrels/day) 9.13 8.70 8.70 8.70 8.70 

 

% Change in Net Imports 

 Natural Gas 0.00% 0.00% 0.00% 

 Crude Oil 0.00% 0.00% 0.00% 

Table 7-11 evaluates estimates of energy consumption by energy type at the national 

level for 2015, the year of analysis. All three NSPS options are estimated to have small effects at 

the national level. For Option 1, we estimate an increase in 0.02 quadrillion BTU in 2015, a 0.02 

percent increase. The percent contribution of natural gas and biomass is projected to increase, 

while the percent contribution of liquid fuels and coal is expected to decrease under Option 1. 

Meanwhile, under the proposed Options 2, total energy consumption is also forecast to rise 0.02 

quadrillion BTU, with increase coming from natural gas primarily, with an additional small 

increase in coal consumption. Under Option 3, total energy consumption is forecast to rise 0.01 

quadrillion BTU, or 0.01%, with a slight decrease in liquid fuel consumption from the baseline, 

but increases in natural gas and coal consumption. 

 
7-19 

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

Options 

 Future NSPS Scenario, 2015 

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

Consumption (quadrillion BTU) 

 Liquid Fuels 37.41 39.10 39.09 39.10 39.09 

 Natural gas 24.49 25.77 25.82 25.79 25.79 

 Coal 20.42 19.73 19.71 19.74 19.74 

 Nuclear Power 8.40 8.77 8.77 8.77 8.77 

 Hydropower 2.58 2.92 2.92 2.92 2.92 

 Biomass 2.98 3.27 3.28 3.27 3.27 

 Other Renewable Energy 1.72 2.14 2.14 2.14 2.14 

 Other 0.30 0.31 0.31 0.31 0.31 

 Total 98.29 102.02 102.04 102.04 102.03 

 

% Change in Consumption from Baseline 

 Liquid Fuels -0.03% 0.00% -0.03% 

 Natural Gas 0.19% 0.08% 0.08% 

 Coal -0.10% 0.05% 0.05% 

 Nuclear Power 0.00% 0.00% 0.00% 

 Hydropower 0.00% 0.00% 0.00% 

 Biomass 0.31% 0.00% 0.00% 

 Other Renewable Energy 0.00% 0.00% 0.00% 

 Other 0.00% 0.00% 0.00% 

 Total 0.02% 0.02% 0.01%

Note: Totals may not sum due to independent rounding. 

 With the national profile of energy consumption estimated to change slightly under the 

regulatory options 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. 
7-20 

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

Emissions 

 Future NSPS Scenario, 2015

 2011 Baseline Option 1 

Option 2 

(Proposed) Option 3 

Energy-related CO2-equivalent GHG Emissions (million metric tons CO2-equivalent) 

 Petroleum 2,359.59 2,433.60 2,433.12 2,433.49 2,433.45 

 Natural Gas 1,283.78 1,352.20 1,354.47 1,353.19 1,352.87 

 Coal 1,946.02 1,882.08 1,879.84 1,883.24 1,883.30 

 Other 11.99 11.99 11.99 11.99 11.99 

 Total 5,601.39 5,679.87 5,679.42 5,681.91 5,681.61

 

% Change in Energy-related CO2-equivalent GHG Emissions from Baseline 

 Petroleum -0.02% 0.00% -0.01% 

 Natural Gas 0.17% 0.07% 0.05% 

 Coal -0.12% 0.06% 0.06% 

 Other 0.00% 0.00% 0.00% 

 Total -0.01% 0.04% 0.03%

 

Note: Excludes “producer-side” emissions and emissions reductions estimated to result from NSPS alternatives. 

Totals may not sum due to independent rounding. 

As is shown in Table 7-12, NSPS Option 1 is predicted to slightly decrease aggregate 

consumer-side energy-related CO2-equivalent GHG emissions, by about 0.01 percent, while the 

mix of emissions shifts slightly away from coal and petroleum toward natural gas. Proposed 

Options 2 and 3 are estimated to increase consumer-side aggregate energy-related CO2-

equivalent GHG emissions by about 0.04 and 0.03 percent, respectively, mainly because 

consumer-side emissions from natural gas and coal combustion increase slightly. 

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 proposed regulations using labor requirements for the installation, operation, and 
7-21 

maintenance of control requirements, as well as reporting and recordkeeping requirements. 

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 2008.52 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. 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. 

 

52 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
7-22 

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 proposed 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. 

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 proposed 

regulations. Each of these labor changes may either be required as part of an initial effort to 

comply with the new regulation or required as a continuous or annual effort to maintain 

compliance. We estimate up-front and continual, annual labor requirements by estimating hours 

of labor required and converting this number to full-time equivalents (FTEs) by dividing by 

2,080 (40 hours per week multiplied by 52 weeks). We note that this type of FTE estimate 
7-23 

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 proposed 

NSPS and in Table 7-14 for the proposed 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 proposed 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 230 FTEs for the proposed NSPS and 

about 120 FTEs for the proposed 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 2,400 FTEs for 

the proposed NSPS and about 102 FTEs for the proposed NESHAP amendments. These 

ongoing FTE labor requirements can 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 proposed 

rules: implementing reduced emissions completions (RECs) and reporting and recordkeeping 
7-24 

requirements for the proposed 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 2,230 FTE, over 90 percent of the 

total continuing labor requirements for the proposed NSPS.53 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 recently finalized Industrial Boilers and CISWI rulemakings, promulgated on 

February 21, 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. 

Morgenstern et al. concluded that increased abatement expenditures in these industries 

generally do not cause a significant change in employment. Using plant-level Census 

 

53 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. 
7-25 

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 do not 

necessarily cause economically significant employment changes. 

For this version of RIA for the proposed 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 proposed rules. We believe the transfer of 

parameter estimates from the Morgenstern et al. study to the proposed NSPS and NESHAP 

amendments is beyond the range of the study for two reasons. 
7-26 

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

Maintaining Control Equipment Requirements, Proposed NSPS Option in 2015 

Source/Emissions Point Emissions Control 

Projected 

No. of 

Affected 

Units 

Per Unit 

Up- Front 

Labor 

Estimate 

(hours) 

Per Unit 

Annual 

Labor 

Estimate 

(hours) 

Total 

Up- Front 

Labor 

Estimate 

(hours) 

To

Ann

Lab

Estim

(hou

Well Completions 

Hydraulically Fractured Gas Wells Reduced Emissions Completion (REC) 9,313 0 218 0 2,025Hydraulically Fractured Gas Wells Combustion 446 0 22 0 9

Well Recompletions 

Hydraulically Fractured Gas Wells (preNSPS wells) REC 12,050 0 218 0 2,621

Equipment Leaks 

Processing Plants NSPS Subpart VVA 29 587 887 17,023 25

Reciprocating Compressors 

Gathering/Boosting Stations AMM 210 1 1 210 Processing Plants AMM 375 1 1 375 Transmission Compressor Stations AMM 199 1 1 199 Underground Storage Facilities AMM 9 1 1 9 

Centrifugal Compressors 

Processing Plants Dry Seals/Route to Process or Control 16 355 0 5,680 Transmission Compressor Stations Dry Seals/Route to Process or Control 14 355 0 4,970 

Pneumatic Controllers 

Oil and Gas Production Low Bleed/Route to Process 13,632 0 0 0 Natural Gas Trans. and Storage Low Bleed/Route to Process 67 0 0 0 

Storage Vessels 

High Throughput 95% control 304 271 190 82,279 57

Reporting and Recordkeeping for Complete NSPS --- --- --- 360,443 201TOTAL --- --- --- 471,187 4,942

Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by threquirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to indep
7-27 

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

Maintaining Control Equipment Requirements, Proposed NESHAP Amendments in 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) 

To

Ann

Lab

Estim

(hou

Small Glycol Dehydrators 

Production 

Combustion devices, recovery devices, process modifications 115 27 285 3,108 32

Transmission 

Combustion devices, recovery devices, process modifications 19 27 285 513 5

Storage Vessels 

Production Combustion devices, recovery devices 674 311 198 209,753 133

Reporting and Recordkeeping for Complete NESHAP Amendments --- --- --- 36,462 39TOTAL --- -- --- 249,836 211

Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by threquirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to indep
7-28 

First, the possibility that the revenues producers are estimated to receive from additional natural 

gas recovery as a result of the proposed 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 proposed 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 proposed NSPS and the segments of the oil and natural gas 

industry affected by the proposals 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 proposed 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 proposed 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 
7-29 

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 proposed rules on small entities for both the 

NESHAP and NSPS, the screening analysis indicates that these proposed 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 proposed 

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 Proposed NSPS. 

Because the total costs of the rule are likely to be more than offset by the revenues producers 

gain from increased natural gas recovery, we expect there will be no SISNOSE arising from the 

proposed NSPS. However, not all components of the proposed 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. We feel taking this approach strengthens the 

determination that there will be no SISNOSE. Unlike the controls for the proposed NSPS, the 

controls evaluated under the proposed 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.54 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). 

 

54See http://www.census.gov/csd/susb/ and http://www.sba.gov/advocacy/ for additional details. 
7-30 

The Census Bureau’s definitions used in the SUSB are as follows: 

 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 screening analyses, 

and the terms are used interchangeably. 
7-31 

Table 7-15 Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 200

 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 

Em

Number of Firms by Firm Size 

211111 Crude Petroleum and Natural Gas Extraction 500 5,759 455 115 6,329 211112 Natural Gas Liquid Extraction 500 77 9 12 98 213111 Drilling Oil and Gas Wells 500 1,580 333 97 2,010 486210 Pipeline Transportation of Natural Gas $7.0 million 63 12 9 84 

Total Employment by Firm Size 

211111 Crude Petroleum and Natural Gas Extraction 500 21,170 16,583 17,869 55,622 211112 Natural Gas Liquid Extraction 500 372 305 1,198 1,875 213111 Drilling Oil and Gas Wells 500 5,972 13,787 16,893 36,652 486210 Pipeline Transportation of Natural Gas $7.0 million 241 382 1,479 2,102 

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 14211112 Natural Gas Liquid Extraction 500 209,640 217,982 1,736,706 2,164,328 37213111 Drilling Oil and Gas Wells 500 1,101,481 2,460,301 3,735,652 7,297,434 1486210 Pipeline Transportation of Natural Gas $7.0 million 332,177 518,341 1,448,020 2,298,538 1

Source: U.S. Census Bureau. 2010. “Number of Firms, Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterp

United States, All Industries: 2007.” <http://www.census.gov/econ/susb/> 
7-32 

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 proposed 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 proposed rules. 
7-33 

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. (HIS 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). 

 
7-34 

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 proposed 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 proposed rule has the potential to impact all firms 

owning affected facilities, both large and small. 
7-35 

The analysis provides EPA with an estimate of the magnitude of impacts the proposed 

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 

screening 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 proposed 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 SBREFA55 and is consistent with 

guidance published by the U.S. SBA’s Office of Advocacy that suggests that cost as a percentage 

 

55 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> 
7-36 

of total revenues is a metric for evaluating cost increases on small entities in relation to increases

on large entities (U.S. SBA, 2010).568

7.4.3 Small Entity Economic Impact Analysis, Proposed NSPS 

7.4.3.1 Overview of Sample Data and Methods 

The proposed 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. 

 

56U.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. 
7-37 

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 facilities57 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.58 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 

proposed NSPS in 2015 assuming their 2015 production activities were similar to those in 2008 

and 2009. We estimate that 129 (47 percent) of these firms are small according to SBA criteria. 

We estimate 121 firms (44 percent) are not small firms according to SBA criteria. We are unable 

to classify the remaining 24 firms (9 percent) because of a lack of required information on 

employee counts or revenue estimates. 

Table 7-18 shows the estimated revenues for 250 firms for which we have sufficient data 

that would be potentially affected by the proposed 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. 

 

 

57 Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing 

Capacity Ahead in 2009.” June 7, 2010.

58 Oil and Gas Journal. “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow.”

November 1, 2010. 
7-38 

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 79 18,554.5 234.9 76.3 0.1 1,116.9 

Large 49 1,347,463.0 27,499.2 1,788.3 12.9 310,586.0 

Subtotal 128 1,366,017.4 10,672.0 344.6 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 129 24,221.1 187.8 34.9 0.1 1,459.1 

Large 121 1,866,513.7 15,817.9 1,672.1 7.1 310,586.0 

 Total 250 1,890,734.8 7,654.8 163.9 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). 

 
7-39 

 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 (121 of the 128 

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 76 13,478.8 177.4 67.1 0.1 2,401.9

Large 45 126,749.3 2,816.7 918.1 10.3 22,518.7

Total 121 140,228.2 1,158.9 192.8 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 121 

firms were $140 billion in 2008 dollars). About 10 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 7 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 
7-40 

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 76 2,288.3 30.1 6.0 0.2 259.3

Large 45 9,445.1 209.9 149.1 0.6 868.3

Subtotal 121 11,733.4 97.0 28.3 0.2 868.3

Crude Oil 

Small 76 1,317.1 17.3 3.5 0.1 149.2

Large 45 5,436.3 120.8 85.8 0.4 499.7

Subtotal 121 6,753.4 55.8 16.3 0.1 499.7

Total 

Small 76 3,605.4 47.4 9.5 0.0 408.5

Large 45 14,881.4 330.7 234.9 0.0 1,368.0

 Total 121 18,486.8 152.8 44.6 0.0 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 6 natural gas wells compared to 149 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 
7-41 

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 proposed 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 proposed controls. 

This estimation procedure yielded an estimate of crude well compliance costs of $162 per 

drilled well and natural gas well compliance costs of $38,719 without considering estimated 

revenues from product recovery and -$2,455 per drilled well 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 proposed 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 

$6.9 million without estimated revenues from product recovery and $2.3 million with estimated 
7-42 

revenues from product recovery, respectively, in 2008 dollars, or about $20/MMcf without 

revenues and $7/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 proposed 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, Proposed 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 

$480 million in 2008 dollars, about 65 percent of the estimated annualized costs of the Proposed 

NSPS without including revenues from additional product recovery ($740 million). When 

including revenues from additional product recovery, the estimated compliance costs for the 

firms in the sample is about -$23 million, compared to engineering cost estimate of -$45 million. 

Table 7-21 presents the distribution of estimated proposed NSPS compliance costs across 

firm size for the firms within our sample. Evident from this table, about 98 percent of the 

estimated engineering compliance costs accrue to the integrated and production segment of the 

industry, again explain by the fact that completion-related requirements contribute the bulk of the 

estimated engineering compliance costs (as well as estimated emissions reductions). About 17 

percent of the total estimated engineering compliance costs (and about 18 percent of the costs 

accruing the integrated and production segment) are focused on small firms. 

 
7-43 

Table 7-21 Distribution of Estimated Proposed 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 Mean Median Minimum Maximum 

Production and Integrated 

Small 79 82,293,903 1,041,695 221,467 3,210 10,054,401

Large 49 387,489,928 7,907,958 5,730,634 15,238 33,677,388

Subtotal 128 469,783,831 3,670,186 969,519 3,210 33,677,388

Pipeline 

Small 11 3,386 308 111 18 1,144

Large 36 1,486,929 41,304 3,821 37 900,696

Subtotal 47 1,490,314 31,709 2,263 18 900,696

Processing 

Small 39 476,165 12,209 1,882 188 276,343

Large 23 859,507 37,370 8,132 38 423,645

Subtotal 62 1,335,672 21,543 2,730 38 423,645

Pipelines/Processing 

Small 0 N/A N/A N/A N/A N/A

Large 13 5,431,510 417,808 147,925 2,003 2,630,236

Subtotal 13 5,431,510 417,808 147,925 2,003 2,630,236

Total

Small 129 82,773,454 641,655 49,386 18 10,054,401

Large 121 395,267,874 3,266,677 57,220 37 33,677,388

 Total 250 478,041,328 1,912,165 55,888 18 33,677,388

These distributions are similar when the revenues from expected natural gas recovery are 

included (Table 7-22). About 21 percent of the total savings from the proposed NSPS is 

expected to accrue to small firms (about 19 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 proposed NSPS. 

 
7-44 

Table 7-22 Distribution of Estimated Proposed 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 Mean Median Minimum Maximum 

Production and Integrated 

Small 79 -5,065,551 -64,121 -13,729 -620,880 8,699

Large 49 -22,197,126 -453,003 -318,551 -2,072,384 423,760

Subtotal 128 -27,262,676 -212,990 -43,479 -2,072,384 423,760

Pipeline 

Small 11 2,303 209 76 12 779

Large 36 1,011,572 28,099 2,599 25 612,753

Subtotal 47 1,013,876 21,572 1,539 12 612,753

Processing 

Small 39 160,248 4,109 634 63 93,000

Large 23 289,258 12,576 2,737 13 142,573

Subtotal 62 449,506 7,250 919 13 142,573

Pipelines/Processing 

Small 0 --- --- --- --- ---

Large 13 3,060,373 235,413 86,301 716 1,746,730

Subtotal 13 3,060,373 235,413 86,301 716 1,746,730

Total

Small 129 -4,902,999 -38,008 -2,520 -620,880 93,000

Large 121 -17,835,922 -147,404 634 -2,072,384 1,746,730

 Total 250 -22,738,922 -90,956 22 -2,072,384 1,746,730

 
7-45 

Table 7-23 Summary of Sales Test Ratios, Without Revenues from Additional Natural 

Gas Product Recovery for Firms Affected by Proposed NSPS 

 

Number of Firms

Descriptive Statistics for Sales Test Ratio Without Estimated Revenues 

from Natural Gas Product Recovery (%) 

Firm Type/Size Mean Median Minimum Maximum 

Production and Integrated 

Small 79 2.18% 0.49% 0.01% 50.83% 

Large 49 0.41% 0.28% <0.01% 2.83% 

Subtotal 128 1.50% 0.39% <0.01% 50.83% 

Pipeline 

Small 11 <0.01% <0.01% <0.01% 0.01% 

Large 36 0.01% <0.01% <0.01% 0.06% 

Subtotal 47 0.01% <0.01% <0.01% 0.06% 

Processing 

Small 39 0.05% 0.01% <0.01% 0.33% 

Large 23 0.02% 0.01% <0.01% 0.15% 

Subtotal 62 0.04% 0.01% <0.01% 0.33% 

Pipelines/Processing 

Small 0 --- --- --- --- 

Large 13 <0.01% <0.01% <0.01% 0.01% 

Subtotal 13 <0.01% <0.01% <0.01% 0.01% 

Total

Small 129 1.34% 0.15% <0.01% 50.83%

Large 121 0.17% 0.01% <0.01% 2.83%

 Total 250 0.78% 0.03% <0.01% 50.83%

 The mean cost-sales ratio for all businesses when estimated product recovery is excluded 

from the analysis of the sample data is 0.78 percent, with a median ratio of 0.03 percent, a 

minimum of less than 0.01 percent, and a maximum of over 50 percent (Table 7-23). For small 

firms in the sample, the mean and median cost-sales ratios are 1.34 percent and 0.15 percent, 

respectively, with a minimum of less than 0.01 percent and a maximum of over 50 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. 

 
7-46 

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

Product Recovery for Firms Affected by Proposed NSPS 

 

Number of Firms

Descriptive Statistics for Sales Test Ratio With Estimated Revenues 

from Natural Gas Product Recovery (%) 

Firm Type/Size Mean Median Minimum Maximum 

Production and Integrated 

Small 79 -0.13% -0.03% -2.96% <0.00% 

Large 49 -0.02% -0.02% -0.17% 0.06% 

Subtotal 128 -0.09% -0.02% -2.96% 0.06% 

Pipeline 

Small 11 <0.00% <0.01% <0.01% 0.01% 

Large 36 0.01% <0.01% <0.01% 0.04% 

Subtotal 47 0.01% <0.01% <0.01% 0.04% 

Processing 

Small 39 0.01% <0.01% <0.01% 0.05% 

Large 23 <0.00% <0.01% <0.01% 0.05% 

Subtotal 62 0.01% <0.01% <0.01% 0.05% 

Pipelines/Processing 

Small 0 --- --- --- --- 

Large 13 <0.01% <0.01% <0.01% 0.01% 

Subtotal 13 <0.01% <0.01% <0.01% 0.01% 

Total

Small 129 -0.08% -0.01% -2.96% 0.05%

Large 121 -0.01% <0.01% -0.17% 0.06%

 Total 250 -0.04% <0.01% -2.96% 0.06%

 The mean cost-sales ratio for all businesses when estimated product recovery is included 

is in the sample is -0.04 percent, with a median ratio of less than 0.01 percent, a minimum of 

-2.96 percent, and a maximum of 0.06 percent (Table 7-24). For small firms in the sample, the 

mean and median cost-sales ratios are -0.08 percent and -0.01 percent, respectively, with a 

minimum of -2.96 percent and a maximum of 0.05 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 129 
7-47 

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 Proposed 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% 109 84.5% 129 100.00% 

C/S Ratio 1-3% 11 8.5% 0 0.00% 

CS Ratio greater than 3% 9 7.0% 0 0.00% 

When the estimated revenues from product recovery are not included in the analysis, 11 firms 

(about 9 percent) are estimated to have sales test ratios between 1 and 3 percent. Nine firms 

(about 7 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 proposed NSPS. 

 
7-48 

7.4.3.3 Small Entity Impact Analysis, Proposed NSPS, Additional Qualitative Discussion 

3.5.3.3.1 Small Entities and Reduced Emissions Completions 

Because REC requirements of the proposed 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. 
7-49 

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. 
7-50 

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 proposed NSPS. 

3.5.3.3.2 Age of Equipment and Proposed 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 proposed 

requirements 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 $27 

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 older 
7-51 

equipment. Meanwhile, the REC and emissions combustion requirements in the proposed 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 $710 million in annualized 

costs) and expected revenues from natural gas product recovery (about $760 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. 

7.4.3.4 Small Entity Impact Analysis, Proposed NSPS, Screening Analysis Conclusion 

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. 
7-52 

7.4.4 Small Entity Economic Impact Analysis, Proposed NESHAP Amendments 

The proposed 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 

447 facilities to be affected, and these facilities are owned by an estimated 160 firms. We were 

unable to obtain financial information on 42 (26 percent) of these firms due to inadequate data. 

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 118 firms for which we have financial information, we identified 62 small firms 

and 56 large firms that would be affected by the NESHAP amendments. Annual compliance 

costs for small firms are estimated at $3.0 million (18 percent of the total compliance costs), and 

annual compliance costs for large firms are estimated at $10.7 million (67 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 $2.3 million 

(15 percent of the total). All figures are in 2008 dollars. 

The average estimated annualized compliance cost for the 62 small firms identified in the 

dataset is $48,000, while the mean annual revenue figure for the same firms is over $120 million, 

or less than 1 percent for a average sales-test ratio for all 62 firms (Table 7-26). The median 
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sale-test ratio for these firms is smaller at 0.14 percent. Large firms are likely to see an average 

of $190,000 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 Proposed 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 62 53% 0.62% 0.14% < 0.01% 6.2% 

Large 56 47% 0.01% < 0.01% < 0.01% 0.4% 

All 118 100% 0.34% 0.02% < 0.01% 6.2% 

Among the small firms, 52 of the 62 (84 percent) are likely to have impacts of less than 1 

percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile 10 firms 

(16 percent) are likely to have impacts greater than 1 percent (Table 7-27). Four of these 10 

firms are likely to have impacts greater than 3 percent (Table 7-27) While these 10 firms might 

receive significant impacts from the proposed 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, Proposed 

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% 52 83.9% 0.81% 

C/S Ratio 1-3% 6 9.7% 0.09% 

CS Ratio greater than 3% 4 6.5% 0.06% 

Screening Analysis Conclusion: While there are significant impacts on small business, the 

analysis shows that a substantial number of small firms are not impacted. Based upon the 

analysis in this section, we presume there is no SISNOSE arising from the proposed NESHAP 

amendments. 
7-54 

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