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# 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 DOCKET NUMBER

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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, Offi ce 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 Atmos pheric 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 Internati onal made contributions also include the sections describing emissions opti ons, pollution control options, engineering cost analysis , and employment impacts

.

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iii TABLE OF CONTENTS

T ABLE OF 

### C ONTENTS



### ................................ ................................ ................................ ................ III


### L IST OF 

### T ABLES



### ................................ ................................ ................................ ........................ VI


### L IST OF 

### F IGURES



### ................................ ................................ ................................ .................... VIII


### 1 E XECUTIVE 

### S UMMARY



### ................................ ................................ ................................ .... 1

- 1

1.1 B ACKGROUND

................................ ................................ ................................ ................................ ........ 1

- 1 1.2 NSPS R

ESULTS

................................ ................................ ................................ ................................ ...... 1

- 2 1.3 NESHAP A MENDMENTS R ESULTS

................................ ................................ ................................ .......... 1

- 5 1.4 O RGANIZATION OF THIS R EPORT

................................ ................................ ................................ ............. 1

- 7


### 2 I NDUSTRY 

### P ROFILE



### ................................ ................................ ................................ ......... 2

- 1

2.1 I NTRODUCTION

................................ ................................ ................................ ................................ ...... 2

- 1 2.2 P RODUCTS O F THE C RUDE O IL AND N ATURAL G AS I NDUSTRY

................................ ................................ . 2

- 2 2.2.1 Crude Oil

................................ ................................ ................................ ................................ ...... 2

- 2 2.2.2 Natural Gas

................................ ................................ ................................ ................................ .. 2

- 2 2.2.3 Condensa tes

................................ ................................ ................................ ................................ . 2

- 3 2.2.4 Other Recovered Hydrocarbons

................................ ................................ ................................ .... 2

- 3 2.2.5 Produced Water

................................ ................................ ................................ ............................ 2

- 4 2.3 O IL AN D N ATURAL G AS P RODUCTION P ROCESSES

................................ ................................ ................... 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 R ESERVES AND M ARKETS

................................ ................................ ................................ ....................... 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 I NDUSTRY C OSTS

................................ ................................ ................................ ................................ . 2

- 31 2.5.1 Finding Costs

................................ ................................ ................................ ............................. 2

- 31 2.5.2 Lift ing Costs

................................ ................................ ................................ ............................... 2

- 33 2.5.3 Operating and Equipment Costs

................................ ................................ ................................ .. 2

- 34 2.6 F IRM C HARACTERISTICS

................................ ................................ ................................ ....................... 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 R EFERENCES

................................ ................................ ................................ ................................ ........ 2

- 53


### 3 E CONOMIC 

### I MPACT 

### A NALYSIS



### ................................ ................................ ........................ 3

- 1

3.1 I NTRODUCTION

................................ ................................ ................................ ................................ ...... 3

- 1 3.2 E MISSIONS P OINTS , C ONTROLS , AND E NGINEERING C OSTS A NALYSIS

................................ ...................... 3

- 1 3.2.1 Emission Points and Pollution Controls assessed in the RIA

................................ .......................... 3

- 1 3.2.1.1 NSPS Emission Points and Pollution Controls

................................ ................................ ...... 3

- 1 3.2.1.2 NESHAP Emission Points and Pollution Controls

................................ ................................ 3

- 5 3.2.2 Engineering Cost Analysis

................................ ................................ ................................ ............ 3

- 7

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iv 3.2.2.1 NSPS Sources

................................ ................................ ................................ ..................... 3

- 7 3.2.2.2 NESHAP Sources

................................ ................................ ................................ .............. 3

- 23 3.3 E NERGY S YSTEM I MPACTS A NALYSIS OF P ROPOSED NSPS

................................ ................................ .... 3

- 25 3.3.1 Description of the Department of Energy National Energy Modeling System

............................... 3

- 27 3.3.2 Inputs to National Energy Modeling System

................................ ................................ ................ 3

- 29 3.3.2.1 Compliance Costs for Oil and Gas Exploration and Production

................................ ........... 3

- 30 3.3.2.2 Adding Averted Methane Emissions into Natural Gas Production

................................ ....... 3

- 33 3.3.2.3 Fixing Canad ian Drilling Costs to Baseline Path

................................ ................................ 3

- 34 3.3.3 Energy System Impacts

................................ ................................ ................................ ............... 3

- 35 3.3.3.1 Impacts on Drilling Activities

................................ ................................ ............................ 3

- 35 3.3.3.2 Impacts on Production, Prices, and Consumption

................................ ............................... 3

- 37 3.3.3.3 Impacts on Imports and National Fuel Mix

................................ ................................ ......... 3

- 40 3.4 E MPLOYMENT I MPACT A NALYSIS

................................ ................................ ................................ ......... 3

- 43 3.4.1 Employment Impacts from Pollution Control Requirements

................................ ........................ 3

- 44 3.4.2 Employment Impacts Primarily on the Regulated Industry

................................ ........................... 3

- 47 3.5 S MALL B USINESS I MPACTS A NALYSIS

................................ ................................ ................................ ... 3

- 51 3.5.1 Small Business National Overview

................................ ................................ ............................. 3

- 52 3.5.2 Small Entity Economic Impact Measures

................................ ................................ .................... 3

- 55 3.5.2.1 Small Entity Impacts for the NSPS

................................ ................................ ..................... 3

- 57 3.5.2.2 Small Entity Impacts for the NESHAP Amendments

................................ .......................... 3

- 70 3.6 R EFERENCES

................................ ................................ ................................ ................................ ........ 3

- 72


### 4 B ENEFITS OF 

### E MISSIONS 

### R EDUCTIONS



### ................................ ................................ ........... 4

- 1

4.1 I NTRODUCTION

................................ ................................ ................................ ................................ ...... 4

- 1 4.2 D IRECT E MISSION R EDUCTIONS FROM THE O IL AND N ATURAL G AS R ULES

................................ ............... 4

- 2 4.3 S ECONDARY I MPACTS A NALYSIS FOR O IL AND G AS R ULES

................................ ................................ ...... 4

- 4 4.4 H AZARDOUS A IR P OLLUTANT (HAP) B ENEFITS

................................ ................................ ....................... 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

- He xane

................................ ................................ ................................ ................................ .... 4

- 17 4.4.7 Other Air Toxics

................................ ................................ ................................ ......................... 4

- 18 4.5 VOC S

................................ ................................ ................................ ................................ .................. 4

- 18 4.5.1 VOCs as a PM2.5 precursor

................................ ................................ ................................ ........ 4

- 18 4.5.2 PM 2.5 health effects and valuation

................................ ................................ ................................ 4

- 19 4.5.3 Organic PM welfare effects

................................ ................................ ................................ ......... 4

- 23 4.5.4 Visibility Effects

................................ ................................ ................................ ......................... 4

- 24 4.6 VOC S AS AN O ZONE P RECURSOR

................................ ................................ ................................ .......... 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 M ETHANE (CH 4 )

................................ ................................ ................................ ................................ .. 4

- 27 4.7.1 Methane as an ozone precursor

................................ ................................ ................................ ... 4

- 2 7 4.7.2 Methane climate effects and valuation

................................ ................................ ......................... 4

- 27 4.8 R EFERENCES

................................ ................................ ................................ ................................ ........ 4

- 35


### 5 S TATUTORY AND 

### E XECUTIVE 

### O RDER 

### R EVIEWS



### ................................ .............................. 5

- 1

5.1 E XECUTIVE O RDER 12866, R EGULATORY P LANNING AND R EVIEW AND E XECUTIVE O RDER 13563, I MPROVING R

EGULATION AND R

EGULATORY R

EVIEW

................................ ................................ ...................... 5

- 1 5.2 P APERWORK R EDUCTION A CT

................................ ................................ ................................ ................ 5

- 3 5.3 R EGULATORY F LEXIBILITY A CT

................................ ................................ ................................ .............. 5

- 4 5.3.1 Proposed NSPS

................................ ................................ ................................ ............................ 5

- 5 5.3.2 Proposed NESHAP Amendments

................................ ................................ ............................... 5

- 5

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v 5.4 U NFUNDED M ANDATES R EFORM A CT

................................ ................................ ................................ ..... 5

- 6 5.5 E XECUTIVE O RDER 13132: F EDERALISM

................................ ................................ ................................ 5

- 6 5.6 E XECUTIVE O RDER 13175: C ONSULTATION AND C OORDINATION WITH I NDIAN T RIBAL G OVERNMENTS

... 5

- 7 5.7 E XECUTIVE O RDER 13045: P ROTECTION OF C HILDREN FROM E NVIRONMENTAL H EALTH R ISKS AND S AFETY R ISKS

................................ ................................ ................................ ................................ .............................. 5

- 7 5.8 E XECUTIVE O RDER 13211: A CTIONS C ONCERNING R EGULATIONS T HAT S IGNIFICANTLY A FFECT E NERGY S UPPLY , D ISTRIBUTION , OR U SE

................................ ................................ ................................ ....................... 5

- 7 5.9 N ATIONAL T ECHNOLOGY T RANSFER AND A DVANCEMENT A CT

................................ ............................... 5

- 9 5.10 E XECUTIVE O RDER 12898: F EDERAL A CTIONS TO A DDRESS E NVIRONMENTAL J USTICE IN M INORITY P OPULATIONS AND L OW

- I NCOME P OPULATIONS

................................ ................................ ............................. 5

- 10


### 6 C OMPARISON OF 

### B ENEFITS AND 

### C OSTS



### ................................ ................................ .......... 6

- 1

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vi LIST OF TABLES

Table 1

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

Regulatory Opti ons 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

- 7 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 Tabl e 2

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

.......................... 2

- 49 Table 2

- 22 Selected Financial Items from Incom e 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

- 8 Table 3

- 2 Summary of Capital and Ann ualized Costs per Unit for NSPS Emissions Points

......................... 3

- 14 Table 3

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

Effectiveness by Emissions Sources and Points, NSPS, 2015

................................ ...................... 3

- 15 Table 3

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

................................ .......................... 3

- 17 Table 3

- 5 Estimates of Control Unit

- level and National Level Natural Gas and Condensate Recovery, NSPS

Options, 2015

................................ ................................ ................................ ............................ 3

- 20 Table 3

- 6 Simple Rate of Return Estimate for NSPS Control Options Where Estimated Revenues from Natural

gas Product Recovery Exceeds Estimated Annualized Engineering Costs

................................ ... 3

- 22 Table 3

- 7 Summary of Estimated Capital and Annual Costs, Emissions Reductions, and HAP Reduction Cost

Effectiveness for Proposed NESHAP Amendments

................................ ................................ .... 3

- 25 Table 3

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

Controls Entered into NEMS

................................ ................................ ................................ ..... 3

- 32 Table 3

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

Entered into NEMS

................................ ................................ ................................ ................... 3

- 33 Table 3

- 10 Successful Oil and Gas Wells Drilled, NSPS Options

................................ ................................ . 3

- 35 Table 3

- 11 Successful Wells Drilled by Well Type (Onshore, Lower 48 States), NSPS Options

................... 3

- 36 Table 3

- 12 Annual Domestic Natural Gas and Crude Oil Production, NSPS Options

................................ .... 3

- 37 Table 3

- 13 Natural Gas Production by Well Type (Onshore, Lower 48 States), NSPS Options

..................... 3

- 38 Table 3

- 14 Lower 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS Options

........................... 3

- 39 Table 3

- 15 Delivered Natural Gas Prices by Sector (2008$ per million BTU), 2015, NSPS Options

............. 3

- 39 Table 3

- 16 Natural Gas Consumption by Sector, NSPS Options

................................ ................................ ... 3

- 40 Tabl e 3

- 17 Net Imports of Natural Gas and Crude Oil, NSPS Options

................................ .......................... 3

- 41

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vii Table 3

- 18 Total Energy Consumption by Energy Type (Quadrillion BTU), NSPS Options

......................... 3

- 42 Table 3

- 19 Modeled Change in Energy

- related "Consumer

- Side" CO 2 - equivalent GHG Emissions

.............. 3

- 43 Table 3

- 20 Labor

- based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and

Maintaining Control Equipment Requirements, Proposed NSPS Option in 2015

......................... 3

- 49 Table 3

- 21 Labor

- based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and

Maintaining Control Equipment Require ments, Proposed NESHAP Amendments in 2015

.......... 3

- 50 Table 3

- 22 Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007

... 3

- 54 Table 3

- 23 Distribution of Small and Large Firms by Number of Firms, Total Employment, and Estimated

Receipts by Firm Size and NAICS, 2007

................................ ................................ .................... 3

- 55 Table 3

- 24 Estimated Revenues for Firms in Sample, by Firm Type and Size

................................ ............... 3

- 61 Table 3

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

(million 2008 dollars)

................................ ................................ ................................ ................ 3

- 62 Table 3

- 26 Descriptive Statistics of Capital and Exploration Expenditures, Small and Large Firms in Sample,

2008 and 2009 (million 2008 dollars)

................................ ................................ ......................... 3

- 6 2 Table 3

- 27 Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009

............................ 3

- 63 Table 3

- 28 Distribution of Estimated Proposed NSPS Compliance Costs Without Revenues from Additional

Natural Gas Product Recovery across Firm Size in Sample of Firms

................................ ........... 3

- 64 Table 3

- 29 Distribution of Estimated Proposed NSPS Compliance Costs With Revenues from Additional

Natural Gas Product Recovery across Firm Size in Sample of Firms

................................ ........... 3

- 65 Table 3

- 30 Summary of Sales Test Ratios, Without Revenues from Additional Natural Gas Product Recovery

for Firms Affected by Proposed NSPS

................................ ................................ ....................... 3

- 66 Table 3

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

Firms Affected by Proposed NSPS

................................ ................................ ............................. 3

- 67 Table 3

- 32 Summary of Sales Test Ratios, With and Without Revenues from Additional Natural Gas Product

Recovery for Firms Affected by Prop osed NSPS

................................ ................................ ........ 3

- 67 Table 3

- 33 Affected Small Firms as a Percent of Small Firms Nationwide, Proposed NSPS, With and Without

Revenues from Additional Natural Gas Product Recovery

................................ .......................... 3

- 68 Table 3

- 34 Summary of Sales Test Ratios for Firms Affected by Proposed NESHAP Amen dments

.............. 3

- 71 Table 3

- 35 Affected Small Firms as a Percent of Small Firms Nationwide, Proposed NESHAP amendments 3

- 72 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 CO 2 - equivalent Emissions by Fuel Type for the Proposed Oil

and Gas NSPS in 201 5 (million metric tons) ("Consumer

- Side") 1

................................ ................. 4

- 7 Table 4

- 4 Total Change in CO 2 - equivalent Emissions including Secondary Impacts for t he 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 4

- 7 Climate Methane Co

- benefits Using  ̳GWP‘ Approach

................................ ............................... 4

- 32 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 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 200 8$) 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

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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 Consump tion), 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 P rice (in 1976

dollars), 1976

- 2009

................................ ................................ ................................ ..................... 2

- 35 Figure 2

- 12 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas P rice, 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), Employ ment 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 Cost s after Revenues from Additional Product

Recovery are Included

................................ ................................ ................................ ................. 3

- 18 Figure 3

- 2 Organization of NEMS Modules (source: U.S. Energy Information Administration)

..................... 3

- 28 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

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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 d ioxide emissions from Natural Gas Processing Plants. As a resul t 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

stationar y sources in the source categories that are not covered by the existing NSPS . In
addition, this p roposal address es the residual risk and technology r eview conducted for two source categories in the Oil and Natural Ga s sector regulated by separate National Emission

Standards for Hazardous Air P ollutants (NESHAP) . It also proposes standards for emission sources not currently addressed, as well as amendm ents to improve aspects of these NESHAP related to applicability and implementation. Finally, it address es provisions in these NESHAP related to emissions during periods of start up, shutdown, and malfunction.

As part of the regulatory process, EPA is requ ired 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

P reamble), 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 a n economic impact analysis and a n 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 Ene rgy Modeling System (NEMS)

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

. This analysis assumes an analysis year of 2015.

Several p roposed 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

### *** E.O. 12866 Review

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1

- 2 of the averted methane emissions can be directed into natural gas producti on streams a nd sold. One emissions control option, reduced emissions well completions, also recover s saleable hydrocarbon condensates which would otherwise be lost to the environment. T he revenues

derived from additional natural gas and condensate recovery are expec ted to offset the engineering costs of implementing the NSPS in the proposed option. In the economic i mpact and energy economy analyse s for the NSPS, we present results for three regulatory options that

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

.

1.2 NSPS Results

For the proposed NSPS, t he 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 quanti fication 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 th is 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 t he 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 (CO 2 

### ), 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 CO 2 

### - equivalent emission reductions are 6 2 million metric tons.

 

### Engineeri ng Cost Analysis: EPA estimates the total capital cost o f the proposed NSPS will be $ 740 million. T he total annualized engineering costs of the proposed NSPS will be $ 740 million. When estimated revenues from additional natural gas and condensate recover y are included, the annualized engineering costs of the proposed NSPS are estimated at $

- 45 million , assuming a well head 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. As product prices can increase or decrease rapidly, the estimated engineering compliance costs can vary when revenue from additional product recovery i s included. 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 , g iven EPA estimates that 180 billion

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- 3 cubic feet of natural gas 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, t he ana lysis 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 )

an d average natural gas prices to dec rease 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 p rices are estimated to decrease slightly (about $0. 0 2 /barrel or less than 0.1 percent at the wellhead for ons hore 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 wil l 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 rep orting 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 mu ltiplied 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.

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- 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: Proposed 4 Option 3: Alternative

Total Monetized Benefits 2 N/A N/A N/A

Total Costs 3

- $19 million

- $45 million $77 million

Net Benefits N/A N/A N/A

Non

- monetized Benefits 17,000 tons of HAPs 5 37,000 tons of HAPs 5 37,000 tons of HAPs 5
270,000 tons of VOCs 540,000 tons of VOCs 550,000 tons of VOCs
1.6 million tons of methane 5 3.4 million tons of methane 5 3.4 million tons of methane 5

Health effects of HAP exposure 5 Health effects of HAP exposure 5 Health effects of HAP exposure 5
Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Visibility impairment Visibility impairment Visibility impairment Vegetation effects Vegetation effects Vegetation effects
Climate effects 5 Climate effects 5 Climate effects 5

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 qu antification 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 techn ologies for the proposed NSPS are anticipated to have minor secondary disbenefits, including an increase of 990,000 to ns of CO 2 , 510 tons of NOx, 7.6 tons of PM, 2,8 00 t ons of CO, and 1,000 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO 2 - equivalent emission reductions are 6 2 million metric tons.

3 T he engineering compliance costs are annualized using a 7 percent discount ra t e.

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.

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- 5 1.3 NESHAP Amendments Results
For the proposed NESHAP amendments , t h e 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 e xisting emissions, including 1,4 00 tons of HAPs , 9,200 tons of VOCs, and 4,900 tons of me thane. Results from the residual risk assessment indicate that f or 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 prima ry 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 benefit s 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 NESH AP is anticipated to have minor secondary disbenefits, including an increase of 5,500 tons of CO 2 

### , 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 C O 2 

### - 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. T otal annualized engineering costs of the proposed NESH AP amendments are estimated to be $1 6 m i llion . 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 n ational energy economy.

 

### Small Entity Analyses: EPA performed a screening analysis for impacts on small entities by comparing c ompliance costs to revenues

. For the proposed NESHAP amendments , we found that there wil l not be a significant impact on a substa ntial 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 la bor 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 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.

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- 6  

### Break

- E ven Analysis: A break

- even analysis suggests that HAP emissions would need to be valued at $ 1 2 ,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
, 7 00 per ton or the methane emissions would need to be valued at $ 3
, 3 00 per ton for the benefits to exceed the costs. Previous assessments have shown that the PM 2.5 

### benefits associated with reducing VOC emiss ions were valued at $280 to $7,000 per ton of VOC emissions reduced in specific urban areas. Previous assessments have shown that the PM 2.5 

### benefits associated with reducing VOC emissions were valued at $280 to $7,000 per ton of VOC emissions reduced in s pecific 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.

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- 7 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 Benefits 2 N/A

Total Costs 3 $16 million

Net Benefits N/A

Non

- monetized Benefits 1,400 tons of HAPs 9,200 tons of VOCs 4

4,900 tons of methane 4

Health effects of HAP exposure

Health effects of PM 2.5 and ozone exposure 4

Visibility impairment 4 Vegetation effects 4

Climate effects 4

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 h ave 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 m odeling 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 CO 2 , 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 CO 2 - equivalent emission reductions are 9 3 thousand metric tons.

3 The engineering compliance costs are annualized using a 7 percent discount ra t e.

4 Reduced exposure to VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects, and climate effects are co

- benefits.



### 1.4 Organization of this Report

The remainder of this report details the methodo logy and the results of the RIA. S ection 2 presents the industry profile of the oil and natural gas industry. Section 3 describe s the engineering cost, energy system impact, economic i mpact, and small business impact analyses. Section 4 presents the benefits analysis

. Section 5 presents statutory and executive order analyses. Section 6 presents a comparison of benefits and costs.

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- 1 2 INDUSTRY PROFILE

2.1 Introduction

The oil and natural gas industry i ncludes the f ollowing 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 natur al 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 A ctivities 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 deta il 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 ind ustry are inputs for larger production processes of gas, energy, and petroleum products. As of 2009, th e 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 p roduction 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 gen era l 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 A ir

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- 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 ga s 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 cr udes 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 clas sified 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 cru de oil is typically one with API gravity of 20 o 

### or less, while a light or naphthenic crude oil, which typically flows freely at atmosph eric 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 . D ead 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

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- 3 underground reservoirs. Natural gas may contain contaminants, such as hydrogen sulfide (H 2 

### S),

CO 2 

### , 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 e ither natural gas whose water content has been re duced through dehydration or natural gas that contains little or no recoverable liquid hydrocarbons.

Natural gas streams that contain threshold concentrations of H 2 

### S are classified as sour gases. Those with threshold concentrations of CO 2 

### 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 H 2 

### S concent ration of greater than 0.25 grain per 100 standard cubic feet, along with the presence of CO 2 

### . Concentrations of H 2 

### S and CO 2 

### , 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,

t ypically have an API gra vity of 40 o 

### 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 Recove red Hydrocarbons

Various hydrocarbons may be recovered through the processing of the extracted hydrocarbon streams. These hydrocarbons include mixed natural gas liquids (NGL), natural gasoline, propane, butane, and liquefied petroleum gas (LPG).

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- 4 2.2.5 Produce d Water

Produced water is the water recovered from a production well. Produced water is separated from the extra cted hydrocarbon streams in various production processes and

oper ations

.

2.3 Oil and Natural Gas Production Processes

2.3.1 Ex

ploration and Drilling

Exp loration involves the search for rock formations associated w ith 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 invol ves 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 we ll bor e, which removes drill cuttings by taking them to the surface. The weight of the mud prevents high

- pressure reservoir fluid s from pushing their way out (― blow ing 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 drillin g technology has been available since the 1950s. Horizontal drilling facilitates the construction of horizontal wells by allowing for the well bore to run horizontally underground, increasing the surface area of contact between the reservoir and the well bore so

that more oil or natural gas can move into the well. Horizontal wells are particularly useful in unconventional gas extraction where the gas is not concentrated in a reservoir

. Recent advances have made it possible to steer the drill in different directions (directional drilling) from the

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- 5 s urface 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 op en 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 o f rock s and sand (Hyne, 2001) . I n a conventional source, the oil and natural gas have been pus hed 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

dri lled to reach the reservoir, the oil and gas can be extracted in different ways d epending on the well pressure (Hyne, 2001)

.
Frequently, oil and natural gas are produced from the same reservoir. As wells deplete the reservoirs into which they are drilled, the gas to oil ratio increases (as does the ratio of water to hydrocarbons). This increase of gas over oil occurs because natural gas usually is in the top of the oil formation, while the well usually is drilled into the bottom portion to recover most of the liquid. Production sites often handle crude oil and natural gas from more than one well (Hyne, 2001)

.

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- 6 Well pressure is required to move the resource up f rom the well to the surface. During primary e xtraction , p ressure from the well itself drives th e 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

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

the resource out ( s econdary or improved oil recovery ). Finally, in tertiary e xtr action or
enhanced recovery, g as, chemicals or steam are injected into the well. This ca n result in recovering up to 60 percent of the original amount of oi l in the reservoir (Hyne, 2001)

.
In contrast to conventional sources, unconventional oil and gas a re 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) . Ther e fore, the resource does not

move into a reservoir a s in the case with a co nve ntional source. M ining, induced pressure, or heat is required t o 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 t his proposal inclu de:

Shale Natural Gas: Shale natural gas comes from sediments of clay mixed with organic

matter. These sediments f orm low permeability shale rock formations that do not allow the gas to move. To release the gas, the rock must be fragme nted, making the extraction

pro cess 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 hydrau lic fracturing (U.S. DOE, 2009).

Tight Sands Natural G as: Reservoirs are composed of low

- porosity sandstones and carbonate into which natural gas has migrated f rom 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

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- 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 f rom 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 d irectly 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 H 2 

### S, which may or may not be contained in natural gas.

H 2 

### S is t oxic (and potentially fatal at certain concentrations) to humans and is corrosive for pipes.

It is therefore desirable to remove H 2 

### S 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 subs urface. 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 regener ated simply by heating them above the boiling point of water. Finally, particularly for gas extracted from deep, hot wells, simply cooling the gas to a temperature below the condensation point of water can remove enough water to transport the gas. Of the three approaches mentioned above, glycol dehydration is the most

common when processing at or near the well.

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- 8 Sweetening is the procedure in which H 2 

### S and sometimes CO 2 

### are removed from the gas stream. The most common method is amine treatment. In this p rocess, the gas stream is exposed
to an amine solution, which will react with the H 2 

### S 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 disp osed 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 Trans mission and Distribution

After processing, natural gas enters a network of compressor s tations, 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, com pressor 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

horse power 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 equalizin g 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 disti nct mar kets. Oil

is an international co mmodity, transported and consumed throughout the world. Natural gas, on the other hand, has historically been c onsumed close to where it is produced. However, as pipeline infrastructure and LNG trade expand, natura l gas is increasingly a national and

interna tional commodity

. The following subsections provide historical and forecast data on the U.S. reserves, production, consumption, and foreign trade of crude oil and natural gas

.

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- 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 EIA 1 

### , these concepts are defined as:

Proved reserves : e stimated 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 know n crude oil or

natural gas reservoir s or aggregation of such reservoirs is expected to increase during the time between discovery and permanent abandonment.

Technic ally 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 t he totally technically

recoverable crude oil resources.

1 U.S. Department of Energy, Energy Information Administration, Glossary of Terms <h ttp://www.eia.doe.gov/glossary/index.cfm?id=P > Accessed 12/21/2010.

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- 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 associated

dissolved 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 t he 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 reser ves
from 1990 to 2008. In Table 2

- 2 , proved ultimate recovery equals the sum of cumulative production and proved reserves. While crude oil and natur al gas are nonrenewable resources, the table shows that proved ultimate recovery rises over time as new discoveries become economically accessible. R eser ves growth and decline is also partly a function of exploration
activities, which are correlated with oil and natural gas prices. For example, w hen oil prices are high there is more of an incentive to use secondary and tertiary recovery, as well as to develop

unconventional sources.

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- 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.

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- 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 o f 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 o f natural gas.

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- 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 d omestic production of crude oil has dropped by almost 750 million bbl since

1990

.

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- 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



### Averag e 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 price s have shown a generally increasing tr end . The exceptio n 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 well s has increased nearl y 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 significan t component of overall gas withdrawals in recent years.

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- 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 overal l, average well productivity has declined , despite improvements in exploration and gas well stimulation technologies.

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- 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 Produc tivity, 1990

- 2009.

Domestic e xploration 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 t his 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 increa sed 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

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- 17 well drilling and completion. Similarly, w ell 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 fro m hydraulic fracturing activities ( ANL 2009 )

.

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- 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 Wate r

(1000 bbl) Total O il 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 ind ependent rounding

.


### 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

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- 19 Wyoming were the three largest pr oducers 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

- injecte d 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 exh ibiting some variation, pipeline mileage transporting refined products remained relatively constant.

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- 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.ht m 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 l ow

- 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 decr easing from 1990 from above 30,000 miles from 1990 to 1995 to around 20,000 miles in 2007 and 2008. Transmission pipelines added

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- 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 expandi ng 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 decline d during this period, while the share of total consumption by the tra nsportation 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.

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- 22 Figure 2

- 4 Crud e 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

F igure 2

- 5 ). Over the same period, industrial consumption of natural gas declined
, whereas electric power generation increased its consumption quite dramat ically , an important trend in the industry as many utilities increasingly use natural gas for peak generation or switch from coal

based to natural gas

- based electricity generation . The residential, commercial
, and transportation

sectors maintained their c onsumption levels at more or less constant levels during this time period.

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- 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

.

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- 24 F igure 2

- 5 Natu ral Gas Consumption by Sector (Percent of Total Consumption), 1990

- 2009

2.4.4 International Trade Imports of crude o il 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.

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- 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 Me xico 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

Trini dad 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.

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- 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 201 1 Annual Energy

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

discussed in det ail in Section 3, to analyze the impacts of the proposed NSPS on the national energy economy, we use the National Energy Modeling System ( NEMS ) t hat 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

201 9 , which is followed by a gradual decline until the terminal ye ar in the forecast, totaling a 2 8

p ercent decline for the forecast period. The forecast of successful offshore crude oil wells shows a variable but generally increasing trend.

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- 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 G as 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 st ates. 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 13 8 percent, respectively. Despite the growt h in drilling in unconventional reservoirs, EIA forecasts successful conventional natura l gas wells to

increase about 7 8 percent during this period. Offshore natural gas wells are also expected to increase during the next 25 year s , but not to th e degree of onshore drilling.

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- 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 t o decline slightly during the forecast period

. Figure 2

- 7 depicts these trends graphically. All told, EIA forecasts

total crude oil to decrease abou t 3 percent from 2010 to 2035.

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- 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 T otal

Crude Supply (million bb ls) Lower 48

Average Wellhead Price (2009 dollar s per bb l)
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 2 8 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

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- 30 shows average wellhead prices increasing a total of 5 2 percent from 2010 to 2035, from $ 78. 6 per barrel to $ 1 19

. 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 fo recast to increase about 2 4 percent
fr om 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 decl ining trend. Meanwhile, imports of natural gas via pipeline are expected to decline dur ing the forecast period almost completely , from 2.3 3 tcf in 2010 to 0. 04 in 2035 tcf. Imported LNG also decreases from

0.41 tcf in 2010 to 0.14 tcf in 20 35 . Total sup pl y, then, increases about 10 percent, from 24. 08

tcf in 2010 to 2 6

. 57 tcf in 2035.

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- 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 (200 9 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 increas ed 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 ).

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- 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 oi l 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.

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- 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 c osts of operating and maintaining wells and associated production equipment. Direct lifting costs exclude production taxes or royalties, while total lif

t ing costs includes taxes and royalties. Like finding costs, EIA reports average lifting costs for FRS fir m s 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.

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- 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 r ose a little more than $2 per barrels of oil equivalent from 1981 to 1985, t hen declined almost $5 per barrel of oil equivalent from 1985 until 2000. From 2000 to 2008, domestic lifting costs inc reased 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 cos ts 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 tota l 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 Equi pment and Operating Costs 1994 t hrough
2009 ‖ 2 

### , contains indices and estimated costs for domestic oil and natural gas equipment and production operations. The indic es and cost trends track costs for representative operations in

2 U.S. Energy Information Administration. ― Oil and Gas Lease Equi pment and Operating Costs 1994 t hrough 2009 .‖ September 28, 2010.

< http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_prod uction/current/ coststudy.html > Accessed February 2, 2011.

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- 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 c ru de oil operating costs and equipment costs i ndices for 1976 to 2009, as well as the crud e 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 19 9 0s.

Figure 2

- 11 Cru de 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.

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- 36 Figure 2

- 12 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natu ral 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, n atural 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 1990 s. The 2009 index values for natural gas operating and equipment costs ar e 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 equ ipment
extract, process , and transport extracted streams recovered from the raw crude oil and natural gas

resources . Companies that own these facilities are legal business entitie s that have the capacity to
conduct business transactions and make business decisions that affect the facility.

2.6.1 Ownership
Enterprises in t he oil and natural gas industry may be divided into different groups that
include p roducers, transporters, and distrib utors. The producer segment may be further divided between major and independent producers. Major producers include large oil and gas companies

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- 37 that are involved in each of th e 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 primar y importance to many producers. IPAA reports tha t about 50 percent of its members‘ spending in 2007 was directed toward natural gas produ ction, largely toward production of unconventional gas ( IPAA, 20 09 ). Meanwhile, t ransporters are compr ised 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 211 111 and 211112 NAICS codes , of which 6427 (98 percent ) were considered small businesses ( Table 2

- 16 ). Within NAICS 2111 11
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 list ed under the NAICS.

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- 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 Establi shments, 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 fir ms 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.

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- 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 employ s a significant number of people. Table 2

- 17 shows em ployment 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 Operatio ns ( NAICS 213112) employ the majority of workers in the industry.

Table 2

- 17 Oil and Natural Gas In dustry 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 3 0,469 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/>

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- 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 an d 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 bet ween employment in the sector with drilling activity. This correlation also holds through out the period covered by the data.

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- 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 ba rrels 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 ea rly 1990s.

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- 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
Pr oduction, 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 20 09 for the NAICS codes associated with the oil and natural gas industry.

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- 43 Table 2

- 18 Oil and Natural Gas Industry Average Wages by NAICS, 1990

- 20 09 (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) T otal 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 213 111 code have relatively lower wages. Average wages in natural

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

m ore than doubling in real terms. However, since 2000 wages have declined in the pipeline transportation sector, while wages have risen in the other NAICS.

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- 44 Figure 2

- 16 Oil and Natural Gas Industry Average W age s 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 t o 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 potenti ally 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 produ cts.

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

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- 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 arra y 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. Severa l 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 integ ration.

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 reser ves and headquarters in the U.S . In the past, the survey re ported information on the top 300 companies, now the top 150. In 2010, only 137 companies are listed 3



### . Table 2

- 19 lists selected statistics for

3 Oil and Gas Journal. ― OGJ150 Financial Results Down in '09; Production, Reserves U p .‖ September 6, 2010.

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- 46 the t op 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 tot al 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 produ ction represents about 57 percent of total domestic production (1.9 billion bbl, according to EIA). The OGJ 150 natural gas production represents about 54 percent of total domestic production (18.8 tcf, according to EIA).

The OGJ also releases a period rep ort 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 Amer ican 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 larg er facilities is indicated by these top 20 firms owning 86 percent of the total capacity and 88 percent of actual throughput.

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- 47 Table 2

- 19 Top 20 Oil and Natural Gas Companies (Based on Total A ssets) , 2010
Worldwide Production U.S. Production Rank by Total Assets Company Employees Total Assets ($ millions ) Total

Rev. ($ millions ) Net Inc.

($ millions ) Liquids

(Million bbl) Natural

Gas (Bcf) Liquids (Million bbl) Natural

Gas (Bcf) Net

Wells Drilled 1 ExxonMobil Corp. 102,700 233,323 310,586 19,280 725 2,383 112 566 466 2 Chevron Corp. 64,000 164,621 171,636 10,563 674 1,821 177 511 594 3 ConocoPhillips 30,000 152,588 152,840 4,858 341 1,906 153 850 692 4 Anadarko Petroleum Corp. 4,300 50,123 9,000

- 103 88 817 63 817 630 5 Marathon Oil Corp. 28,855 47,052 54,139 1,463 90 351 23 146 115 6 Occidental Petroleum Corp. 10,100 44,229 15,531 2,915 179 338 99 232 260 7 XTO Energy Inc. 3,129 36,255 9,064 2,019 32 855 32 855 1,059 8 Chesapeake Energy Corp. 8,200 29,914 7,702

- 5,805 12 835 12 835 1,003 9 Devon Energy Corp. 5,400 29,686 8,015

- 2,479 72 966 43 743 521 10 Hess Corp. 13,300 29,465 29,569 740 107 270 26 39 48 11 Apache Corp. 3,452 28,186 8,615

- 284 106 642 35 243 124 12 El Paso Corp. 4,991 22,505 4,631

- 539 6 219 6 215 134 13 EOG Resources Inc. 2,100 18,119 14,787 547 29 617 26 422 652 14 Murphy Oil Corp. 8,369 12,756 18,918 838 48 68 6 20 3 15 Noble Energy Inc. 1,630 11,807 2,313

- 131 29 285 17 145 540 16 Williams Cos. Inc. 4,801 9,682 2,219 400 0 3,435 0 3,435 488 17 Questar Corp. 2,468 8,898 3,054 393 4 169 4 169 194 18 Pioneer Nat. Resources Co. 1,888 8,867 1,712

- 52 19 157 17 148 67 19 Plains Expl. & Prod. Co. 808 7,735 1,187 136 18 78 18 78 53 20 Petrohawk Energy Corp. 469 6,662 41,084

- 1,025 2 174 2 174 162 Source: Oil and Gas Journal. ―OGJ150 Financial Results Down in '09; Production, Reserves Up.‖ September 6, 2010. Notes: The source for employment figures is the American Business Directory.

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- 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

c om panies, which amounts to 136 companies in 2010 (Oil and Gas Journal, November 1, 2010)

. Table 2

- 21 presents the pipeline mileage, volumes of natural g as 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 abou t 54 percent of the volume of the industry ( Table 2

- 21 )

. Operating revenues of t he

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- 49 top 2 0 companies equaled $ 11.5 billion, representing 60 percent of the total operating revenues

f or 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 Syste m (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 relea sed to the public in aggregate form. While the companies that report information to FRS each year changes, EIA makes an effort to r etain sufficient consistency such that trends can be evaluated.

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- 50 For 2008, there are 27 companies in the FRS 4 

### that accounte d 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

statement s

. 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. Meanwh ile, 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 dur ing 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 Corp oration, 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, a nd XTO Energy, Inc.

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- 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 pro duction 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 a ccrued includes deductions for the U.S. Federal Investment Tax Credit ($198 million in 2008) and the

effect of the Alter n ative Minimum Tax ($34 million in 2008). Income taxes paid to state and

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- 52 local authorizes were $3,060 million in 2008, about 13 percent of the total paid to U.S.

authorities.

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 Non

Income 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 excee ds domestic taxes paid. Other non

- income production taxes p aid , which have

risen almost three

- fold between 1990 and 2008, include windfall profit and severance taxes, as well as other production

- related taxes.

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- 53 2.7 References

Andrews, et al. 2009. Unconvent ional Gas Shales: Development, Technology, and Policy Issues

. Congressional Research Servic e

. 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. Department of Energy. 2009. Modern Shale Gas Development in the Unit ed States: A Primer. < http://www.netl.doe.gov/technologies/oil

gas/publications/EPreports/Shale_Gas_Primer_2009.pdf > Accessed March 30, 2011.

U.S. Energy Informa tion Administration (U.S. EIA)

. 201 1

. Annual Energy Outlook 2011

. < h ttp://www.eia.gov/forecasts/aeo > June 2 , 2011.

U.S. Energy Information Administration (U.S. EIA)

. 2010. A nnual Energy Review (AER).

< http://www.eia.doe.gov/emeu/aer/contents.html >

U.S. En ergy Information Administration (U.S. EIA). 2010. Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Pro ved 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. Environmental Protection Agency (U.S. EPA)
, Office of Air Quality Planning and Standards. 1996. Economic Analysis of Air Pollution Regulations: Oil and Natural Gas

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- 54 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 E xtraction Industry . EPA/310

- R

- 99

- 006.

< http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/oil. html > Accesse d March 30, 2011.

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- 1 3 ECONOMIC IMPACT ANAL YSIS

3.1 Introduction

This section include s five sets of analyses for both the NSPS and NESHAP amendments :

Emission Points, Control Options, and Engineering Cost Analysis

Energy System Impacts

Employment Impacts

Small Business Impacts 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 cont rol 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 reade r 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.

3.2.1 Emission Points and Pollution Controls assessed in th e 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 t he 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.

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- 2 Centrifugal and r ec iprocating compressors (TSD Chapter 6 ) : There are many locations throughout the oil and gas sector where compression of natural gas is required to move the ga s 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 tur bine. The turbine operates a centrifugal compressor , which compresses and pumps the natural gas through the pi peline.

Some times an electric motor is used to turn a centrifugal compressor. This type of compression does not require the use of any of the n atural gas from the pipe line
, but it does require a source of electricity

. Reciprocating spark ignition engines are also used to power many compressor s , referred to as reciprocating compressors, since they compress gas using pistons that are driven by

the engine

. Like combustion turbines, t hese 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 compre ssor 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) a nd 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 me chanically 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 d ry gas seals substantially reduce s 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

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- 3 move freely. Monitoring and replacing compressor rod packing systems on a regular basis can

grea tly 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 open

ended lines, an d 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 wit hin an oil and gas production, processing, and transmission facility, equipment leak 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 processin g plants, collectively there are many components that can r esult 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 ―n on

- gas driven ‖ pneumatic controllers use sources of power other than pressurized natural gas. Examples include solar, electric, and instrument air. At oil and gas locations with electrical service, non gas

- driven controllers are typically used. Gas

-

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- 4 driven pneumatic controllers are typically characterized as ―high

- bleed‖ or ―low

- bleed‖, where a high

- bleed device release s at least 6 cubic feet of gas per hour. EPA evaluated the impact of requiring low

- bleed controllers.

Storage vessels (TSD Chap ter 7 ): Crude oil, condensate , and produced water are typically

stored in fixed

- roof storage vessels. Some vessels used for storing produced water may be open

top tanks. These vessels, which are operated at or near atmospheric pressure conditions, are

t ypically 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 batte ry through the production header, which may collect product from many wells. Emissions from storage vessels are a result of working, breathing, and flash losses. Working losses occur due to the emptying and filling of storage tanks. Breathing losses are the release of gas 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

entrai ned 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 activ ities 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 wel l. 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 rese rvoir to stimulate production.

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- 5 Hydraulic fracturing is o ne 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 h igh velocity necessary to l ift 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 fo rmation. Thus, we estimate

c ompletions involving hydraulic fracturing vent substantially more natural gas , approximately

23 0 times more, than completions not involving hydraulic fracturing. Specifically, we estimate

that uncontrolled well completion emis sions for a hydraulically fractu red well are about 23 tons of VOC, where emissions for a conventional ga s well completion are around 0.1 tons VOC. Our data indicate that hydraulically fractured wells have higher emissions but we believe some wells

that ar e 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. 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

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- 6 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 dehydrators 5 

### : 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 i ce

- like structures, and can cause corrosion in or plug equipment lines. The most widely used natural gas dehydration processes are glycol dehydration and solid desiccant dehydration. Solid desiccant dehydration , which is typically only used for lower thr oughputs, 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 to wer 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 rebo iler 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 reboil er 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 a tmosphere 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 f rom 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

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.

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- 7 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.

Sto rage vessels : Please see the discussion of storage vessels in the NSPS section above.

3.2.2 Engineering Cost Analysis

In this section, w e 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
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 pr oposed 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 recomplet ed, 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 facilitie s. 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 prod uction facilities and natural gas transmission and storage and reductions from high throughput storage vessels.

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- 8 Table 3

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

Emissions Sources and Point s 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 (post

NSPS wells) REC X X X
Hydraulically Fractured Gas Wells (pre

NSPS 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

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- 9 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 ex isting 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 e xisting 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 Sec tion 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 the additional natural gas and hydrocarbon condensate recovery from several control options evaluated in the NSPS

review.

FIRST, APPROACH TO ANNUALIZING COSTS.

o Interest rate of 7 percent used for each emissions control.

o Different time

- periods (lifetimes) were used, depending on control technology:

 Reduced emissions completions and combustion devices = 1 year

 Reciprocating compressors = 3 years

 Centrifugal compressors and pneumatic controllers = 10 years

 Storage vessels and glycol dehydrators = 15 years

 Control options for equipment leaks range from 5 to 10 years

o Mention two approach to annualizing costs equivalent

 Adding annualized costs of each item without accounting for different expected lifetimes

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- 10  Set representative project h orizon. For example, a 15 year project would require replacing reciprocating compressor

- related controls 5 times, so add up costs over the projects horizon for each item then annualize.

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 o f 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 ti ght 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 o f 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. T hese 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 TSD 6 

### and applied to well c ount data found in the proprietary HPDI ® 

### database. The underlying assumption is that wells found in coal bed methane, shale, and tight sand formations require re

- fracture, on average, every 10 years. In
other words, 10 percent of the total wells classifi ed as being performed with hydraulic fracturing would perform a recompletion in any given year. Natural g as w ell recompletion s performed without hydraulic fracturing were based only on 2008 well data from HPDI ®



### .

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 Divisio n. Washington, DC

.

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- 11 The num ber of completions and recompletio ns already controlling emissions in absence of a Federal regulation was estimated based on e xisting S tate regulations that require applicable control measures for completions and workovers in specific geographic locations. Based on th is
criterion, 1 5 perce nt of natural gas completions with hydraulic fracturing and 1 5 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 witho ut hydraulic fracturing were assumed as having no controls in ab sence 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 ga s 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 requ irements (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 cos t, 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

that oth erwise 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 c ost 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

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- 12 environment. The engineering analysis assumes a REC will ca pture 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 co mpliance 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 alrea dy be doing so.

Table 3

- 3 present s the estimated nationwide compliance costs, emissions r eductions, and

VOC r eduction 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

an d 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 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

reducti ons 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.

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- 13 Several evaluated emissions sources and points are estimated to have net fi nancial 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.

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- 14 Table 3

- 2 Summary of Capital and Annual ized Costs per Unit for NSPS Emissions Points

Sources/Emissions Point Projected No. of Affected Units Per Unit Annualized Cost (2008$)

Capital Costs (2008$) Withou t

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

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- 15 Table 3

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

- Effectiveness by Emissions Sources and Points, NSPS , 2015

Source/Emissions Point Emissions Control Nationwide Annualized Costs (2008$) Nationwide Emissions

Reductions (tons/year) VOC Emissions Reduction Cost

- Effectiveness (2008$/ton) Without Addl. Revenues With Addl.

Revenues VOC Methane HAP Without Addl. Revenues With Addl.

Revenues Well Completions (New Wells) Hydraulically Fractured Gas Wells REC $309,553,517

- $20,235,748 204,134 1,399,139 14,831 $1,516

- $99 Hydraulically Fractured Gas Wells Combustion $1,571,188 $1,571,188 9,801 67,178 712 $160 $160 Conventional Gas Wells Combustion $27,104,761 $27,104,761 857 5,875 62 $31,619 $31,619 Oil Wells Combustion $42,954,036 $42,954,036 83 88 0 $520,580 $520,580 Well Recompletions (Existing Wells) Hydraulically Fractured Gas Wells (existing wells) REC $400,508,928

- $26,181,572 264,115 1,810,245 19,189 $1,516

- $99 Conventional Gas Wells Combustion $149,164,257 $149,164,257 316 2,165 23 $472,227 $472,227 Oil Wells Combustion $138,711,979 $138,711,979 44 47 0 $3,134,431 $3,134,431 Equipment Leaks Well Pads NSPS Subpart VV $111,773,662 $104,412,154 10,646 38,287 401 $10,499 $9,808 Gathering and Boosting Stations NSPS Subpart VV $15,692,325 $14,072,850 2,340 8,415 88 $6,705 $6,013 Processing Plants NSPS Subpart VVa $1,309,650 $982,648 392 1,411 15 $3,343 $2,508 Transmission Compressor Stations NSPS Subpart VV $2,712,450 $2,712,450 261 9,427 8 $10,389 $10,389 Reciprocating Compressors

Well Pads Annual Monitoring/ Maintenance (AMM) $22,204,209 $21,984,763 263 947 10 $84,379 $83,545 Gathering/Boosting Stations AMM $515,764 $182,597 400 1,437 15 $1,291 $457 Processing Plants AMM $436,806

- $465,354 1,082 3,892 41 $404

- $430 Transmission Compressor Stations AMM $47,892 $47,892 12 423 0 $4,093 $4,093 Underground Storage Facilities AMM $13,396 $13,396 2 87 0 $5,542 $5,542

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- 16 Table 3

- 3 (continued) Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost

Effectiveness by Emissions Sources and Points, NSPS , 2015

Source/Emissions Point Emissions Control Nationwide Annualized Costs (2008$) Nationwide Emissions

Reductions (tons/year) VOC Emissions Reduction Cost

- Effectiveness (2008$/ton) Without Addl. Revenues With Addl.

Revenues VOC Methane HAP Without Addl. Revenues With Addl.

Revenues

Centrifugal Compressors

Processing Plants Dry Seals/Route to Process or Control $170,853

- $1,979,687 288 3,183 10 $593

- $6,874

Transmission Compressor Stations Dry Seals/Route to Process or Control $149,496

- $1,086,704 43 1,546 1 $3,495

- $25,405 Pneumatic Controllers

-

Oil and Gas Production Low Bleed/Route to Process $320,071

- $20,699,918 25,210 90,685 952 $13

- $821

Natural Gas Trans. and Storage Low Bleed/Route to Process $1,539 $1,539 6 212 0 $262 $262 Storage Vessels High Throughput 95% control $4,411,587 $4,234,856 29,654 6,490 876 $149 $143 Low Throughput 95% control $248,225,012 $238,280,976 6,838 1,497 202 $36,298 $34,844

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- 17 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 bene fit 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 rapidl y, 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 wellhe ad 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 diffe rence 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 engi neering 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 ana lysis 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

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- 18 for the recovered natural gas (rep resented 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 2 011 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 esti mated at

- $45
million. At $4.22 /Mcf, the price forecast reported in the 2011 Annual Energy Outlook, the

annual ized costs are estimated at about

- $90 million , which would approximately double the estimate of net cost savings of the proposed NSPS . As this indicated by this difference, EPA has chosen a conservative assumption (leading to an estimate of few savings and higher net costs) for

th e 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 is the wellhead natural gas price leads to about a $180 million change in the annualized engineering cos ts of the proposed NSPS. Consequent l y, annualized engineering costs estimates would increase to about $140 million under a $3/Mcf price or decrease to about

- $23 0 million under a $5/Mcf price.

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- 19 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, 182, and 183 bcf of natural gas and 316,000, 726,000, and
726,000 barrels of condens ate, respectively. For control options that are expected to recover natural gas products. E stimates of unit

- level and nation

- level product recovery are presented in

Table 3

- 5 . 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 and 176 bcf (97 percent) for Options 2 and 3.

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- 20 Table 3

- 5 Estimates of Control Unit

- level and National Level Natural Gas and Condensate Recovery, NSPS Options, 2015

Sourc e/Emissions Point Projected No. of Affected Units Unit

- level Product Recovery Total Product Recovery

Emissions Control NSPS Option Natural Gas Savings (Mcf/unit /year ) Condensate (bbl/unit /year ) Natural Gas

Savings (Mcf /year ) Condensate

(bbl /year ) Well Completions Hydraulically Fractured Gas Wells REC 1, 2, 3 9,313 8,258 34 76,905,813 316,657 Hydraulically Fractured Gas Wells Combustion 1, 2, 3 446 0 0 0 0 Hydraulically Fractured Gas Wells (existing wells) REC 2, 3 12,050 8,258 34 99,502,875 409,700
Equipment Leaks Processing Plants NSPS Subpart VVa 2, 3 29 2,819 0 81,750 0 Reciprocating Compressors
Gathering/Boosting Stations Annual Monitoring/ Maintenance (AMM) 1, 2, 3 210 397 0 83,370 0
Processing Plants AMM 1, 2, 3 375 1,079 0 404,677 0 Trans. Compressor Stations AMM 1, 2, 3 199 1,122 0 223,374 0 Underground Storage Facilities AMM 1, 2, 3 9 1,130 0 9,609 0 Centrifugal Compressors
Processing Plants Dry Seals/Route to Process or Ctrl 1, 2, 3 16 11,527 0 184,435 0

Trans. Compressor Stations Dry Seals/Route to Process or Ctrl 1, 2, 3 14 5,716 0 80,018 0

Pneumatic Controllers

-
Oil and Gas Production Low Bleed/Route to Process 1, 2, 3 13,632 386 0 5,254,997 0

Natural Gas Trans. and Storage Low Bleed/Route to Process 1, 2, 3 67 0 0 0 0
Processing Plants Instrument Air 1, 2, 3 15 871.0 0 13,064 0 Storage Vessels High Throughput 95% control 1, 2, 3 304 146 0 44,189 0 Option 1 Total (Mcf) 83,203,546 316,657 Option 2 Total (Mcf) 182,788,172 726,357 Option 3 Total (Mcf) 182,788,172 726,357

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- 21 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 o r 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 pl ants. 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. Ac cording 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 1 44 bcf, and Option 3 will potentially recover 1 44 bcf of natural gas that will ultimately be consumed by natural gas

consumers. 7 

### EIA forecasts that the domestic dry nat ural gas production in 2015 will be 20,080 bcf. Consequently, Option 1, proposed Option 2, and Option 3 may recover production representing about 0. 3 percent , 0. 6 percent and 0. 6 percent of domestic dry natural gas production predicted in 2015, respective ly. These estimates, however, do not account for adjustments producers might make, once compliance costs and potential revenues from

additio nal natural gas recovery factor into economic decisionmaking

. Also, as discussed in the previous paragraph, these estimates do not include the nonhydr ocarbon 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

cont rols.

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.

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- 22 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. DISCUSS RATE OF RETURN TABLE

Table 3

- 6 Simple Rate of Return Estimate for NSPS Control Options Where Estimated Revenues from Natural gas Product Recovery Exceeds Estimated Annualized Engineering Costs

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% Centrifu gal Compressors (Processing Plants) Convert to Dry Seals 1158.7%
Centrifu gal 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%



### MENTION 6.5 PERCENT RATE OF RETURN FOR REDUCED EMISSIONS

CO MPLETIONS COMPARED TO OVERALL H I S TORICAL (HIGHER) RATE OF RETURN
FROM OIL AND NATURAL GAS PRODUCTION ACTIVITIES, REFERRING TO TABLE

IN INDUSTRY PROFILE.

Assuming financially rational producers, standard economic theory suggests that all oil and natural gas firms would incorporate all cost

- effective improvements, which they are aware of, without government intervention. In this case, the benefits of the ru le would be due to external benefits associated with the achieved emission reductions only. 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 gen erally adopted.

One 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 p otential financial returns to capturing emissions. Quantifying emissions is difficult and has been done in relatively few studies.

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- 23 Recently, however, advances in infrared imagery have made it possible to affordably visualize, if not quantify, methane emi ssions 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 na tural gas production activities. Since, as discussed in the TSD chapter referenced above, 1 5 percent of

new natural gas well completions with hydraulic fracturing and 1 5 percent o f existing natural gas well recompletions with hydraulic fracturing are esti mated 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 p oints, 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 scenario is that the full o pportunity costs 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 f irms 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 ord er to pursue alternative investments today, and the option to suspend use of the technology if it becomes unprofitable in the future. Therefore, the full cost of the regulation to the firm is the engineering cost and the lost option value minus the revenu es 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 face d 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 a nd 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,

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- 24 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 control s 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 en gineering (not social) costs.

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- 25 Table 3

- 7 Summary of Estimated Capital and Annual Co sts, 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 Cost

Effectiveness (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 1 6,019,871 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 amen dments. These controls will r educe HAP emissions by about 1,4 00 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 Ene rgy 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

consum ed at a national level. With this information we estimate how the changed fuel mix

affects national level CO 2 

### - equivalent greenhouse gas emissions from energy sources. We additionally combine these estimates of changes in CO 2 

### - equivalent greenhouse gas emi ssions from energy sources and emissions co

- reductions of methane from the engineering analysis with NEMS analysis to estimate the net change in CO 2 

### - equivalent greenhouse gas emissions from

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- 26 energy

- related sources, but this analysis is reserved for the seco ndary environmental impacts analysis within Section 4.

A brief conceptual discussion about our ene rgy 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, t he analysis for the

p r oposed NSPS shows that about 97 percent of the natural gas captured by emissions contro ls suggested by the rule is captured by performing RECs on new and existing wells that are 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, th e gas captured by RECs is sent through a temporary or permanent meter. Payments for the gas are typically ma de 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 prod uction) 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 e ngineering 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 rev enues 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 a ccordingly. 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 s upply 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 aver ted production through efficiency

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- 27 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.

3.3.1 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 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 th e modeling system extensively to produce issue reports, legislative analyses, and respond to Congressional inquiries.

EIA is legally required to make the NEMS system s ource code available and fully documented for the public. The source code and accompan ying 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, t echnological 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/o iaf/aeo/overview/index.html >.

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- 28 Figure 3

- 2 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 establis hing 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 e stimated 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. 8 

### The RIA baseline is consistent with that of the Annual Energy Outlook 2011 which is used extensively in Section 2 in the Industry Profile.

8 Assumptions for the 201 1 Annual Energy Outlook can be found at

< h ttp://www.eia.gov/forecasts/aeo/assumptions/index.cfm >.

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- 29 3.3.2 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 o nshore, offshore,

Alaska n 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 e xploration and development i s pursued in the OGSM if the expected net present value of extracted resources exceeds expected costs , including costs associated with capital, exploration, development, product ion, and taxes. Detailed technology and reservoir

- level production economics g overn 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 mod el 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 e xpected revenues from the condensate recovery in the economic evaluation of new drilling projects.

While the o il production simulated by the OGSM is sent to the refining module ( the Petroleum Market Module) , simulated natural gas production is sent to a tr ansmission 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

.

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- 30 3.3.2.1 Compliance Costs for Oil and Gas Exploration and Production

As the NSPS affects new emissions sources, we chose to est imate 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 recomple tions 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 re quired 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 t he 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, i n 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 a re 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 ex ample

— may not incorporate potential additional transitional costs as the supply of control equipment adjusts to new demand.

Table 3

- 8 shows the incre mental 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 o f

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- 31 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 19,0 97 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 pr oducer when evaluating a prospective drilling project.

Like the engineering analysis, we assume that hydraulically fractured well completions

and recompletions will be required of wel ls 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 hydraul ic 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 per formed in absence of the regulation, using the same assumptions as the engineering costs analysis.

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- 32 Table 3

- 8 Summary of Additional Annualized O&M Costs (on a Per New Well Basis) for Environmental Controls Entered into NEMS

Emissions Sources/Points Emissions Control Per Well Costs (2008$) Wells Applied To in NEMS Option 1 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 Tran s mission 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 $1 2 $1 2 $1 2 Gas Transmission Compressor Stations AMM $1 9 $1 9 $1 9 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

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- 33 Table 3

- 9 Summa ry 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 in NEMS Option 1 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



### 3.3.2.2 Adding Averted Methane Emissions into Natural Gas Production

A sign ificant 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 mode l, 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 effec t 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 o n existing wells, we enter the increased natural gas recovery into NEMS on a per

- well basis for new wells, following an

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- 34 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 th at 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 ar e 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 estim ate 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 produ ction patterns from the AEO2011 Early Tables. 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.

3.3.2.3 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 accu rate 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.

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- 35 3.3.3 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 cons umed 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.

3.3.3.1 Impacts on Drilling Activities

Because th e 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 3

- 10 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 3

- 10 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 sta ndard 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

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- 36 leak standards add to the in cremental 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

increas ed 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 dr illing. 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 natu ral gas to some extent.

Table 3

- 11 presents the forecast of successful wells by well type, for onshore drilling in

the lower 48 states. The results s how 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 3

- 11 Successful Wells Drilled by Well Type (Onshore, Lower 48 States ) , NS PS 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%

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- 37 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 u nder 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.

3.3.3.2 Impacts on Production, Prices, and Consumption

Table 3

- 12 shows estimates of the changes in the domestic production of natural gas and

crude oil unde r 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 3

- 12 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 decline under Options 2 and 3, the increased natural gas recovery is sufficient to offset the production loss from relat ively fewer producing wells.

As we showed for natural gas drilling, Table 3

- 13 shows natural gas production from

onshore wells in the lower 48 state s by type of well, predicted for 2015, the analysis year. Production from conventional natural gas wells and CBM wells are estimated to increase under

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- 38 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.

Table 3

- 13 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 3

- 14 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 sho w 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).

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- 39 Table 3

- 14 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%



### T able 3

- 15 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.

T able 3

- 15 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%

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- 40 Final consumption of natural gas is also estimated to increase in 2015 from the baseline under all NSPS options, as is shown on Table 3

- 16 . Like delivered price, the consumption shifts are distributed differently across sectors.

Table 3

- 16 Natural Gas Consumption by Sector, NSP S 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

.


### 3.3.3.3 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 3

- 17
, estimates of crude oil and natural gas imports do not vary from the baseline in 2015 for each regulatory option.

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- 41 Table 3

- 17 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 3

- 18 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 leve l. 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 decrea se 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, to tal 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.

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- 42 Table 3

- 18 T otal 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 g as 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 CO 2 

### - equivalent greenhouse gas (GHG) e missions also shift. A more detailed discussion of changes in CO 2 

### - equivalent GHG e missions 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 emissi ons. 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 i n this RIA. We term the emissions associated with extraction, processing, and transportation of fuels ―producer

- side‖ emissions.

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- 43 Table 3

- 19 Modeled Change in Energy

- related "Consumer

- Side" CO 2 

### - equivalent GHG Emissions
Future NSPS Scenario, 2015

2011 Baseline Option 1 Option 2 (Proposed) Option 3 Energy

- related CO 2 - equivalent GHG Emissions (million metric tons CO 2 - 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 CO 2 - 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‖ emissio ns and emissions reductions estimated to result from NSPS alternatives. Totals may not sum due to independent rounding

.



### As is shown in Table 3

- 17, NSPS Option 1 is predicted to slightly decrease aggregate

consumer

- side energy

- related CO 2 

### - equivalent GHG e m issions , 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 CO 2 

### - equivalent GHG e missions by about 0.0 4 and 0.03 percent, respectively, mainly because

consumer

- side emissions from natural gas and coal combustion increase slightly.

3.4 Employment Impact Analysis

While a standalone analysis of employment impacts is not included in a standard cost

benefit analysi s, 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 gro wth, 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 re quirements for t he installation, operation, and

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- 44 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 re quirements associated with reporting and recordkeeping and the installation, operation, and maintenance of control requirements

.

3.4.1 Employment Impacts from Pollution Control Requirements

Regul ations 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, reachin g an industry total of approximately $300 billion in revenues and 1.7 million employees in 2008. 9 

### 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 in stalled, 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 industr ies 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 r eassign existing employees to perform these activities.

9 In 2008, the indus try 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

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- 45 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 industr y. 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 displa ce jobs, but the net effect on employment is positive

.

T he 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. Many of the emission controls options, particularly for the proposed NSPS, reduce emissions via capturing saleable products, such as natural gas and hydrocarbon condensates. Therefore, these emissions controls jointly produce environmental improvements and inc rease 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 directly increasing productive outputs.

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 methodolog y to estimate employm ent 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 compl y 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) b y dividing by 2,080 (40 hours per week multiplied by 52 weeks). We note that this type of FTE estimate cannot be used to make assumptions about the specific number of people involved or whether new jobs are created for new employees.

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- 46 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 tran smission 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 change s within and outside of the regulated sector.

The results of this employment estimate are presented in Table 3

- 20 for the proposed

NSPS and in Table 3

- 21 for the proposed NESHAP amendments. The tables breaks down t he 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 a nd 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

com ply 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 amendment s . These ongoing FTE labor requirements can be viewed as sustained labor requirements required f or 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 requirements f

or 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,

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- 47 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. 10 

### W e 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, whi ch 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.

3.4.2 Employmen t 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 final ized 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) t o 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, inc luding 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 ch ange in employment. Using plant

- level Census information between the years 1979 and 1991, Morgenstern et al. estimate the size of each effect for four polluting and regulated industries (petroleum refining , plastic material, pulp and paper,

10 As shown on Table 3

- 10 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 drilling

- related employment that partly offset gains in employment from compliance

- related activities.

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- 48 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 1.5 5 (+/

- 2.24) jobs . As a result, the authors conclude that increases in pollution abatement expenditures do not necessarily cause economically s ignificant 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 believ e 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.

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- 49 Table 3

- 20 Labor

- based Employment Estimate s for Reporting and Recordkeeping and Installing, Operating, and 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) Total

Annual Labor Estimate (hours) Up

- Front

Full

- Time Equivalent Annual

Full

- Time Equivalent Well Completions Hydraulically Fractured Gas Wells Reduced Emissions Completion (REC) 9,313 0 218 0 2,025,869 0.0 974.0 Hydraulically Fractured Gas Wells Combustion 446 0 22 0 9,626 0.0 4.6 Well Recompletions Hydraulically Fractured Gas Wells (pre

NSPS wells) REC 12,050 0 218 0 2,621,126 0.0 1,260.2 Equipment Leaks Processing Plants NSPS Subpart VVA 29 587 887 17,023 25,723 8.2 12.4 Reciprocating Compressors
Gathering/Boosting Stations Annual Monitoring/ Maintenance (AMM) 210 1 1 210 210 0.1 0.1 Processing Plants AMM 375 1 1 375 375 0.2 0.2 Transmission Compressor Stations AMM 199 1 1 199 199 0.1 0.1 Underground Storage Facilities AMM 9 1 1 9 9 0.0 0.0 Centrifugal Compressors Processing Plants Dry Seals/Route to Process or Control 16 355 0 5,680 0 2.7 0.0
Transmission Compressor Stations Dry Seals/Route to Process or Control 14 355 0 4,970 0 2.4 0.0
Pneumatic Controllers
Oil and Gas Production Low Bleed/Route to Process 13,632 0 0 0 0 0.0 0.0 Natural Gas Trans. and Storage Low Bleed/Route to Process 67 0 0 0 0 0.0 0.0 Storage Vessels High Throughput 95% control 304 271 190 82,279 57,582 39.6 27.7 Reporting and Recordkeeping for Complete NSPS

--- --- --- 360,443 201,342 173.3 96.8 TOTAL

--- --- --- 471,187 4,942,060 226.5 2,376.0



### Note: Full

- time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to i ndependent rounding.

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- 50 Table 3

- 21 Labor

- based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and 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 One

Time Labor Estimate (hours) Total

Annual Labor Estimate (hours) One

- time

Full

- Time Equivalent Annual

Full

- Time Equivalent Small Glycol Dehydrators

Production Combustion devices, recovery devices, process modifications 115 27 285 3,108 32,821 1.5 15.8

Transmission Combustion devices, recovery devices, process modifications 19 27 285 513 5,423 0.2 2.6 Storage Vessels
Production Combustion devices, recovery devices 674 311 198 209,753 133,231 100.8 64.1 Reporting and Recordkeeping for Complete NESHAP Amendments

--- --- --- 36,462 39,923 17.5 19.2
TOTAL

--- -- --- 249,836 211,398 120.1 101.6



### Note: Full

- time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding.

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3

- 51 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 dem and and net effect s 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 o il and natural gas industry is similar to petroleum refining, which is examined in Morgenstern et
al., t he production side of the oil and natural gas (drilling and extraction, primarily ) and natural gas pipeline transmission are not similar to petroleum re fining. 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 es timated by M orgenstern 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 , a s 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

s lightly 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.

3.5 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

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- 52 significant economic impact on a substantial number of small entities. Small entities include small businesses, small governmental jurisdictions, and small not

- for

- profit ente rprises.

After considering the economic impact of the proposed rule s 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 ent ities (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 r ecover natural gas that would otherwise be vented to the atmosphere. EPA estimates that the revenues from this additional natural gas 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 estimate d to have cost savings. Therefore, we analyze potential impacts to better understand the potentially distribution of impacts across industry segments and firms. We feel taking this approach strengthens the determination that there will be no SISNOSE. Un like 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.

3.5.1 Small Business National Overview

T he industry sectors covered by the final rule were identified during the de velopment of the cost analysis. The U.S. Census Bureau‘s Statistics of U.S. Businesses (SUSB) provide s national information on the distribution of economic variables by industry an d ente rprise 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

. 11 

### Statistics

include the total number of establishments
, and recei pts 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 3

- 22 )

.

11 See http://www.census.gov/csd/susb/ and http://www.sba.gov/advocacy/ for additional details.

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- 53 The Census Bureau ‘ s definitions used in the SUSB are as follows:

 

### E stablishmen t: A s ingle 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 single

establishment 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.

 

### R eceipts : 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.

 

### E nterprise : An enterpr ise 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 busin ess size definitions (SBA, 2008 ) apply to an establishment ‘ s ― ultimate
parent company, ‖ we assume d 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 ar e used int erchangeably.

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- 54 Table 3

- 22 Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007 Owned by Firms with:

NAICS NAICS Description SBA Size Standard (effective Nov. 5, 2010) < 20

Employees 20

- 99

Employees 100

- 499

Employees Total <

500 Employees > 500

Employees Total Firms Number of Firms by Firm Size 211111 Crude Petroleum and Natural Gas Extraction 500 5,759 455 115 6,329 95 6,424 211112 Natural Gas Liquid Extraction 500 77 9 12 98 41 139 213111 Drilling Oil and Gas Wells 500 1,580 333 97 2,010 49 2,059 486210 Pipeline Transportation of Natural Gas $7.0 million 63 12 9 84 42 126

Total Employment by Firm Size 211111 Crude Petroleum and Natural Gas Extraction 500 21,170 16,583 17,869 55,622 77,664 133,286 211112 Natural Gas Liquid Extraction 500 372 305 1,198 1,875 6,648 8,523 213111 Drilling Oil and Gas Wells 500 5,972 13,787 16,893 36,652 69,774 106,426 486210 Pipeline Transportation of Natural Gas $7.0 million 241 382 1,479 2,102 22,581 24,683

Estimated Receipts by Firm Size ($1000) 211111 Crude Petroleum and Natural Gas Extraction 500 12,488,688 15,025,443 17,451,805 44,965,936 149,141,316 194,107,252 211112 Natural Gas Liquid Extraction 500 209,640 217,982 1,736,706 2,164,328 37,813,413 39,977,741 213111 Drilling Oil and Gas Wells 500 1,101,481 2,460,301 3,735,652 7,297,434 16,550,804 23,848,238 486210 Pipeline Transportation of Natural Gas $7.0 million 332,177 518,341 1,448,020 2,298,538 18,498,143 20,796,681

Source: U.S. Census Bureau. 2010

. ― Number of Firms, Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterprise Receipt Size for the

United States, All Industries: 2007

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

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- 55 Table 3

- 23 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 non

disclosure requirements. Source: SBA



### 3.5.2 Small Entity Economic Impact Measures

The proposed Oil and N atural Gas NSPS and NESHAP amendments will affect the owners of the facilities that will incur compliance costs to control their VOC (for the NSPS) and HAP (for the NESHAP amendments ) 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.

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 to 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

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- 56 with meeting the new stand ard. This section present s the data sources used in the screening analysis, the methodology we applied to develop estimates of impacts, the results of the analysis,

and conclusions about 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 3

- 22 . 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

- a vailable 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

ame ndments 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 o f 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 SBREFA 12 

### and is consistent with guidance published by the U.S. SBA‘s Office of Advocacy that suggests that cost as a percentage of total revenues is a metric for evaluating cost increases on small entities in relation to increases on large entities (U. S. SBA, 2010)

. 13 8

12 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/r faguidance11

- 00

- 06.pdf>
13 U.S. SBA, Office of Advocacy. A Guide for Government A gencies, How to Comply with the Regulatory Flexibility Act, Implementing the President‘s Small Business Agenda and Executive Order 13272, June 2010

.

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- 57 3.5.2.1 Small Entity Impacts for the NSPS

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 use publically avail able production and investment statistics to 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 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 3

- 22 . 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 f irms 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 opera te 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 operat ing 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 w ithin 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.

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- 58 To identif y 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 process ing facilities 14 

### 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

c ompanies

. 15 

### For these firms, we also used the American Business Directory and corporate

websites to best iden tify 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 appro ach yielded a sample of 274 firms that are expected to be affected by the proposed NSPS. We estimate that 122 (44 percent) of these firms are small according to SBA criteria. We estimate 118 firms (43 percent) are not small firms according to SBA criteri a. We are unable to classify the remaining 34 firms (12 percent) because of a lack of required information on employee counts or revenue estimates.

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 sources, for which data are not fully available in advance, particularly in the case of new sources such as well completions which are spatially diffuse and 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 model unit

- level costs to estimate national impacts. To estim ate 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.

14 Oil and Gas Journal. ―Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processi ng Capacity Ahead in 2009.‖ June 7, 2010.
15 Oil and Gas Journal. ―Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow .‖ November 1, 2010.

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- 59 We first use the OGJ150

- based list to estimate compliance costs for integrated companies that may ope rate facilities in more than one segment of the oil and natural gas industry. 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 apportion the wells drilled to natur al gas and crude oil wells using the distribution of well drilling in 2009 (63 percent natural gas and 37 percent oil). 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

- $2,455 per drilled well. Note that the divergence of e stimated 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 larger than the estimated c ost 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 w ell 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 fr om 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 est imated at $6.9 million in 2008 dollars, or about $20/MMcf.

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

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- 60 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 in 2008 dollars. Summ ing estimated compliance costs across industry segment and individual firms in our sample, we estimate firms

in the OGJ

- based sample will face about $470 million in 2008 dollars, about 63 percent of the estimated annualized costs of the Proposed NSPS witho ut 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

- $16 million, compared to engineering cost estimate of

- $4 5 million.

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- 61 Table 3

- 24 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 72 18,272.8 253.8 86.5 0.1 1,116.9 Large 46 1,344,213.8 29,222.0 1,792.4 12.9 310,586.0
Subtotal 118 1,362,486.6 11,546.5 431.2 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 0.0 0.0 0.0 0.0 0.0 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 122 23,939.4 196.2 35.1 0.1 1,459.1 Large 118 1,863,264.5 16,202.3 1,773.7 7.1 310,586.0
Total 240 1,887,203.9 7,962.9 204.9 0.1 310,586.0

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- 62 Table 3

- 25 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 86 2,000.1 23.3 4.0 

### 0.0 259.3

Large 44 9,679.9 220.0 153.2 

### 0.0 868.3
Subtotal 130 11,679.9 89.8 15.2 0.0 868.3
Crude Oil
Small 86 1,151.2 13.4 2.3 0.0 149.2

Large 44 5,571.4 126.6 88.1 0.0 499.7
Subtotal 130 6,722.6 51.7 8.8 0.0 499.7
Total Small 86 3,151.2 36.6 6.3 0.0 408.5

Large 44 15,251.3 346.6 241.3 0.0 1,368.0
Subtotal 130 18,402.6 141.6 24.0 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.



### Table 3

- 26 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 69 12,855.2 186.3 64.0 0.1 2,401.9 Large 42 125,381.9 2,985.3 1,019.2 11.9 22,518.7
Unknown 1 0.8 0.8 0.8 0.8 0.8
Total 112 138,237.8 1,234.3 218.9 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.

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- 63 Table 3

- 27 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.

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- 64 Table 3

- 28 presents the d istribution of estimated proposed NSPS compliance costs across

firm s ize for the firms within our sample.

Table 3

- 28 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 (millions, 2008 dollars) Firm Type/Size Total Average Median Minimum Maximum Production and Integrated

Small 72 76,253,977 1,059,083 216,024 3,211 10,057,428 Large 46 382,736,585 8,320,361 5,942,114 15,238 33,687,530
Subtotal 118 458,990,561 3,889,751 1,102,584 3,211 33,687,530 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



### --- --- --- --- --- 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 122 76,733,527 628,963 45,757 18 10,057,428

Large 118 390,514,531 3,309,445 56,830 37 33,687,530
Total 240 467,248,058 1,946,867 48,845 18 33,687,530

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- 65 Table 3

- 29 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 Average Median Minimum Maximum Production and Integrated

Small 72

- 4,726,649

- 65,648

- 13,487

- 626,892 8,677 Large 46

- 22,114,915

- 480,759

- 344,239

- 2,092,519 423,760
Subtotal 118

- 26,841,565

- 227,471

- 60,959

- 2,092,519 423,760 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 122

- 4,564,098

- 37,411

- 2,132

- 626,892 93,000

Large 118

- 17,753,712

- 150,455 833

- 2,092,519 1,746,730
Total 240

- 22,317,810

- 92,991 44

- 2,092,519 1,746,730

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- 66 Table 3

- 30 Summary of Sales Test Ratios, Without Revenues from Additional Natural Gas Product Recovery for Firms Affected by Proposed NSPS

Number of Firms Summary of Sales Test Ratios With out Estimated Revenues from Natural Gas Product Recovery Firm Type/Size Average Median Minimum Maximum Production and Integrated

Small 72 2.17% 0.43% 0.01% 50.85% Large 46 0.42% 0.30% 0.00% 2.83%
Subtotal 118 1.49% 0.38% 0.00% 50.85% Pipeline
Small 11 0.00% 0.00% 0.00% 0.01%

Large 36 0.01% 0.00% 0.00% 0.06%
Subtotal 47 0.01% 0.00% 0.00% 0.06% Processing
Small 39 0.05% 0.01% 0.00% 0.33%

Large 23 0.02% 0.01% 0.00% 0.15%
Subtotal 62 0.04% 0.01% 0.00% 0.33% Pipelines/Processing

Small 0



### --- --- --- --- Large 13 0.00% 0.00% 0.00% 0.01%
Subtotal 13 0.00% 0.00% 0.00% 0.01%
Total Small 122 1.30% 0.16% 0.00% 50.85%

Large 118 0.17% 0.01% 0.00% 2.83%
Total 240 0.75% 0.04% 0.00% 50.85%

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- 67 Table 3

- 31 Summary of Sales Test Ratios, With Revenues from Additional Natural Gas Product Recovery for Firms Affected by Proposed NSPS

Number of Firms Summary of Sales Test Ratios With Estimated Revenues from Natural Gas Product Recovery Firm Type/Size Average Median Minimum Maximum Production and Integrated

Small 72

- 0.13%

- 0.02%

- 2.99% 0.13% Large 46

- 0.02%

- 0.02%

- 0.18% 0.06%
Subtotal 118

- 0.09%

- 0.02%

- 2.99% 0.13% Pipeline
Small 11 0.00% 0.00% 0.00% 0.01%

Large 36 0.01% 0.00% 0.00% 0.04%
Subtotal 47 0.01% 0.00% 0.00% 0.04% Processing
Small 39 0.03% 0.00% 0.00% 0.32%

Large 23 0.01% 0.00% 0.00% 0.06%
Subtotal 62 0.03% 0.00% 0.00% 0.32% Pipelines/Processing

Small 0



### --- --- --- --- Large 13 0.00% 0.00% 0.00% 0.01%
Subtotal 13 0.00% 0.00% 0.00% 0.01%
Total
Small 122

- 0.06% 0.00%

- 2.99% 0.32%

Large 118 0.00% 0.00%

- 0.18% 0.06%
Total 240

- 0.04% 0.00%

- 2.99% 0.32%



### The mean cost

- sales ratio for small businesses in the sample is

- 0.07 percent, with a median ratio of less than 0.01 percent, a minimum of

- 2.99 percent, and a maximum of 0.15 percent (Table 3

- 28). For large firms in the sample, the mean and median cost

- sales ratios are less than 0.01 percent, with a minimum of

- 0.18 percent and a maximum of 0.19 percent (Table

3

- 28). Again, these compliance costs incorporate revenues expected from additional produc t recovery from implementing the proposed NSPS.

Table 3

- 32 Summary of Sales Test Ratios , With and Without Revenues from Additional Natural Gas Product Recovery for Firms Affected by Proposed NSPS

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- 68 Meanwhile, Table 3

- 33 presents the distribution of estimated cost

- sales ratios for the small firms in our sample. All 122 firms (3.3 percent) have est imated cost

- sales ratios less than 1 percent.

Table 3

- 33 Affected Small Firms as a Percent of Small Firms Nationwide, Proposed NSPS, With and Without Revenues from Additional 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
C/S Ratio less than 1% 122 100.0%
C/S Ratio 1

- 3% 0 0.0% CS Ratio greater than 3% 0 0.0%



### 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

a re not estimated to create significant impacts on a cost

- sales ratio basis at the firm

- level.

Additional Discussion

Age of Equipment and Proposed Regulations

NESHAP is a risk and technology based standard and consideration of variables such as equipment age is not legitimate in considering regulatory alternatives.

The NSPS is a standard that applies to new or modified sources. Because of this, NSPS requiremen ts 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 oth er 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 controller s, and storage vessels) are estimated to require $27 million in annualized engineering costs. EPA also estimates that the annualized costs of these

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- 6 9 requirements will be mostly if not fully offset by revenues expected from natural gas recovery.

EPA does n ot expect these requirements to disproportionately affect producers with older equipment.

Meanwhile, the REC and emissions combustion requirements in the proposed NSPS relate to well completion activities at new hydraulically fractured natural gas wells an d 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 produc t 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 unlik ely 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 an d 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 subject to the NSPS requirement.

Screening Analysis Co nclusion: 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

addi tional 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

- relate d 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 ma ny 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.

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- 70 3.5.2.2 Small Entity Impacts for the 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 bes t 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 re venues 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 privat e, 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 c ost 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 wo uld 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

datas et is $48,000, while the mean annual re venue figure for the same firms is ove r $120 million,

or less than 1 percent for a average sales

- test ratio for all 62 firms ( Table 3

- 34 ). The median

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- 71 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 lar ge, integrated energy firms. For large firms, the average sa les

- test ratio is about 0.01 percent , and the median sales

- test ratio is less than 0.01 percent ( Table 3

- 34 ).

Table 3

- 34 Summary of Sales Test Ratios for Firms Affected by P r oposed 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 3

- 35 ). Four of the se 10 firms are likely to have impacts greater than 3 percent ( Table 3

- 35 ). While these 10 firms might receive significant impacts from the proposed NESH AP 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 3

- 35 ).

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- 72 Table 3

- 35 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.

3.6 R eferences

Berck, P. and S. Hoffmann. 2002. ―Assessing the employment impacts of environmental and natural resource p olicy.‖ Environmental and Resource Economics 22(1):133

- 156.
Bezdek, R.H., R.M. Wendling, and P. DiPern a . 2008. ― Environmental protection, the economy, and jobs: national and regional analyses .‖ Journal of Environmental Management 86(1):63

- 79.

Gabriel, S.A., A.S. Kydes, and P. Whitman. 2001. ―The National Energy Modeling System: a large

- scale energy

- economic equilibrium model.‖ Operations Research 49:1: 14

- 25

.
Just, R.E., D.L. Hueth, and A. Schmitz. 2004. The Welfare Economics of Public Policy

. Northampton, MA: Edward Elgar.
Morgenstern, R.D. W.A. Pizer, and J. Shih . 2002. "Jobs versus the e nvi ronment: an industry

level p erspective," Journ al of Environmental Economics and Management 43(3):412

- 436.
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.

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- 73 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. Environmental Protection Agency (U.S. EPA) , Office of Air Quality Planning and Standards. 1999. OAQPS Economic Analysis Resource Document

. < http://www.epa.gov/ttn/ecas/analguid.html > Accessed March 30, 2011.

U.S. E nvironmental Protection Agency (U.S. EPA) . 20 1 0. ―Guidelines for Preparing Economic Analyses‖ (EPA 240

- R

- 1 0

- 00 1 ).

< http://yosemite.epa.gov/ee/epa/eed.nsf/webpages/Guidelines.html >. Accessed March 30, 2011.

U.S. Small Business Administration (U.S. SBA) , Of fice of Advocacy. 2010. A Guide for Government Agencies, How to Comply with the Regulatory Flexibility Act, Implementing the President‘s Small Business Ag enda and Executive Order 13272.

U.S. Energy Information Administration (U.S. EIA)

. 2010. Documentatio n of the Oil and Gas Supply Module (OGSM). May 2010. DOE/EIA

- M06(2010)

. < http://www.eia.gov/FTPROOT/modeldoc/m063(2010).pdf > Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA) . 2010. Model Documentation Natural Gas Transmission and Distribution Module of the National Energy Modeling System. June 2010. DOE/EIA

- M062(2010)

< http://www.eia.gov/FTPROOT/modeldoc/m062(2010).pdf > Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2006. Natural Gas Processing: T he Crucial Link between Natural Gas Production and It s 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. Energy Information Administration (U.S. EIA). 2 010. Oil and Gas Lease Equi pment and Operating Costs 1994 t hrough 2009

< http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_ production/current/coststudy.html > Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2010. Performance Profiles of Major Energy Producers 2008. < http://www.eia.gov/finance/performanceprofiles > Accessed March 30, 2011.

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- 1 4 BENEFITS OF EMISSION S 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 (PM 2.5 

### ), 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 b e considered ―co

- benefits‖, and for the proposed NESHAP amendments , the ozone and PM 2.5 

### 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 1,4 00 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 CO 2 

### , 510 tons o f 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 CO 2 

### , 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 CO 2 

### - 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 section s, 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 e stimates

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- 2 for greenhouse gases other than CO 2 

### 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 C hapter 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, partic ularly 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 H APs 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 with in areas of high population density.

In implementing these rules, emission controls may lead to reductions in ambient PM 2.5 

### 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 PM 2.5 

### formation to VOC emission reductions, we are unable to determine how these rules might affect attainment status without air quality modeling data. 16


### Because the NAAQS RIAs also calculate ozone and PM benefits, t here 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 stand ard 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 d irectly 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,

16 The responsiveness of ozone and PM 2.5 formation is discussed in greater detail in sectio ns 4.4.1 and 4.5.1 of this RIA.

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- 3 some costs a nd 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 well

characterized 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). Emiss ion 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 to wards 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 an d rules such as analyzed here, please see Section 1.2.4 of the SO 2 

### NAAQS RIA (U.S. EPA,

2010d ). Table 4

- 1 shows the direct em ission 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 PM 2.5 

### 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 Nat ural 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

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- 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. 17 

### For example, by combusting VOCs and HAPs, combustion increase s 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 s econdary 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

.

17 In previous RIAs, we have also referred to these impacts as energy disbenefits.

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- 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 thes e 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 PM 2.5 

### disbenefits

a ssociated with the producer

- side secondary impacts. In addition, it is not appropriate to

monetize the disbenefits associated with the increased CO 2 

### emissions without monetizing the

averted methane emissions because the overall global warming potential (GWP) is actually

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- 6 lower . Through the combustion process, methane emissions are converted to CO 2 

### emissions,

which have 21 times less global warming potential compared to methane (IPCC, 2007). 18



### Table 4

- 2 Secondary Air Pollutant Impacts Associated with Control Techniques by Emissions Category (“Producer

- Side”) (tons per year)

Emissions Category CO 2 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 CO 2 

### - equivalent emissions. 19 

### We provide the modeled results of the ―consumer

- side‖ CO 2 

### - equivalent emissions in Table 3

- 19

.

The modeled results indicate that through a slight shift in the national fuel mix, the CO 2 

### - equivalent emissions across the energy sector w ould 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 6 2 million metric tons of CO 2 

### - 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 ad ditional national gas consumption or the change in the national fuel mi x.

18 This issue is discussed in more detail in Section 4.7 of this RIA.
19 A full discussion of the energy modeling is available in Section 3 of this RIA.

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- 7 Table 4

- 3 Modeled Changes in Energy

- related CO 2 

### - 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 CO 2 - e) NSPS Option 2 (million metric

tons change in CO 2 - e) (Proposed) NSPS Option 3 (million metric tons change in CO 2 - 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 CO 2 - e Emissions - 0.92 1.57 1.27

1 These estimates reflect the modeled change in 

### CO 2
- e emissio ns using NEMS shown in Table 3

- 19

. Totals may not sum due to independent rounding.



### Table 4

- 4 Total Change in CO 2 

### - 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 CO 2 - e Emissions from New Sources 1

- 30.00

- 64.51

- 65.58

- 0.09

Additional CO 2 - e Emissions from Combustion and Supplemental Energy (Producer

- side) 2 0.90 0.90 0.90 0.01

Total Modeled Change in Energy

- related CO 2 - e Emissions (Consumer

- side) 3 - 0.92 1.57 1.27

--
Total Change in CO 2 - 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 

### CO 2 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 produce r

- side secondary impacts associated with the proposed NSPS option as a surrogate for the impacts of the other options.

3 This estimate reflects the modeled change in the energy

– related consumer

- side impacts shown in Table 4

- 3. Totals may not sum due to ind ependent 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, re duce 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.

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- 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 CO 2 990,000 990,000 990,000 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) CO 2 - e

- 1,000,000 1,700,000 1,400,000 N/A

Net Change in CO 2 - equivalent Emissions CO 2 - 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 level s that have the potential to cause adverse health effects (U.S. EPA, 2011d). 20 

### 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 pri oritize air toxics, emission source types and locations that are of greatest potential concern, U.S. EPA conducts the NATA. 21 

### The most recent NATA was conducted for calendar year 2005 and was released in March 2011. NATA includes four steps:

20 The 2005 NATA is available on the Internet at http://www.epa.gov/ttn/atw/nata2005/.

21 The NATA modeling framework has a number of limitations that prevent its use as the sole basis for setting regulatory standards. These limitations and uncertainties are discussed on the 2005 NATA website. Even so, this modeling framework is very useful in identifying air toxic pollutants and sources of greatest concern, setting regulatory priorities, and informing the decision making process. U.S. EPA. (2011) 2005 National

- Scale Air Toxics Assessment. http://www.epa.gov/ttn/atw/nata2005/

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- 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 pu blic 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 nati onal cancer risk is about 50 in a million. Nationwide, the key pollutants that contribute most to the overall cancer risks are formaldehyde and benzene. 22
, 23 

### Secondary formation (e.g., formaldehyde forming from other emitted pollutants) was the largest co ntributor 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, 24 

### subchronic, 25 

### or acute 26 

### inhalation exposures to air toxics, and incl ude 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 a ir 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.

22 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

. 23 Details about the overall confidence of certainty ranking of the individ ual 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.
24 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 da ys to 2 years in typically used laboratory animal species).

25 Defined in the IRIS database as r epeated 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 appr oximately 90 days in typically used laboratory animal species)

. 26 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.

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- 10 Figure 4

- 2 and Figure 4

- 3 depict the estimated census tract

- level c arcinogenic risk and noncancer respiratory hazard from the assessment. It is important to note that l arge reductions in HAP emissions may not necessarily translate into significant reductions in health risk because toxicity varies by pollutant, and exposu res 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. 27 

### Thus, it is important to account for the toxicity and exposure, as well as t he mass of the targeted emissions.

Figure 4

- 2 Estimated Chronic Census Tract Carcinogenic Risk from HAP exposure from outdoor sources (2005 NATA)

27 Details on the derivation of IRIS values and available supporting documentation for individual chemicals (as well as chemical values comparisons) can be found at http://cfpub.epa.gov/ncea/iris/compare.cfm

.

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- 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 a ir 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. 28 

### 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

28 The unit risk factor is a quantitative estimate of the carcinogenic potency of a pollutant, often expressed as the probability of co ntracting cancer from a 70

- year lifetime continuous exposure to a concentration of one μg/m 3 of a pollutant.

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- 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 analysi s 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 ).

Wh ile 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 ben efits, 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 storag e tanks. Emissions of eight HAPs make up a large percentage the total

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- 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, eth yl 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 f or 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 s torage, 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 driv er. 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 magnitu de 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. 29
, 30
, 31 

### EPA states in its IRIS data base that data indicate a causal

29 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.

30 International Agency for Research on Cancer, IARC monographs on the evaluation of carcinogenic risk of chemicals t o humans, Volume 29, Some industrial chemicals and dyestuffs, International Agency for Research on Cancer, World Health Organization, Lyon, France, p. 345

- 389, 1982.

31 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, V.A. (1992) Synergistic action of the benzene metabolite hydroquinone on myelopoietic stimulating activity of granulocyte/macrophage colony

- stimulating factor in vitro, Proc. Natl. Acad. Sci. 89:3691

- 3695.

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- 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 R esearch 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. 32 , 33 

### A number of adverse noncancer health effects including bl ood disorders, such as preleukemia and aplastic anemia, have also been associated with long

- term exposure to benzene. 34
, 35 

### The most sensitive noncancer effect observed in humans, based on current data, is the depression of the absolute lymphocyte count in blood. 36
, 37 

### 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. 38
, 39 , 40 , 41 

### EPA‘s IRIS program has n ot yet evaluated these new data.

32 International Agency for Research on Cancer (IARC). 1987. Monographs on the ev aluation of carcinogenic risk of chemicals to humans, Volume 29, Supplement 7, Some industrial chemicals and dyestuffs, World Health Organization, Lyon, France.

33 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carci nogens available at: http://ntp.niehs.nih.gov/go/16183.

34 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193

- 197.

35 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Re views. 3: 541

- 554.

36 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.

37 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, Was hington, DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm.

38 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.; Huif ant, 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.

39 Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohen, et al. (2 002). Hematological changes among Chinese workers with a broad range of benzene exposures. Am. J. Industr. Med. 42: 275

- 285.

40 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels of Benzene. Science 306: 1774

- 1776.

41 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.

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- 15 4.4.2 Toluene 42



### 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 t arget 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: sym ptoms 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 mo vements), 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 d evelopmental 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 o ccupationally 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 sulfid

e
Limited information is available on the health effects of carbonyl sulfide. Acute (short

term) inhalation of high concentrations of carbonyl sulfide may cause narcotic eff ects and irritate

42 All hea lth 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 Crite ria and Assessment Office, Cincinnati, OH. Available on the Internet at < http://www.epa.gov/iris/subst/0118.htm >.

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- 16 the eyes and skin in humans. 43 

### 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 determ ination under U.S. EPA's IRIS program for evidence of human carcinogenic potential. 44



### 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 als o 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 neurologic al 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 i nhalation. 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. 45 , 46 

### 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 Toxi cology Program (NTP). 47 , 48 

### The NTP (1999) carried out a chronic inhalation

43 Hazardous Substances Data Bank (HSDB), online database). US National Library of Medicin e, 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.

44 U.S. Environmental Protection Agency (U.S. EPA). 200 0. 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.

45 Maltoni C, Con ti 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.

46 Maltoni C, Ciliberti A, Pinto C, Soffritti M, Belpoggi F and Menari ni 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.

47 International Agency for Research on Cancer (IARC), 2000. Monographs on the Evaluation of Carcinogenic Risks to Humans. Some Industrial Chemicals. Vol. 77, p. 227

- 266. IARC, Lyon, France.

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- 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 ca rcinoma 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 hepat ocellular 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 xyle nes

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. 49 

### Other reporte d effects include labored breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and kidneys. 50 

### Long

- term inhalation exposure to xylenes in humans has been associated with a number of effects in the nervous system i ncluding headaches, dizziness, fatigue, tremors, and impaired motor coordination. 51 

### 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 th at 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

48 National Toxicology Program (NTP), 1999. Toxicology and Carcinogenesis Studies of Ethylbenzene (CAS No. 100

- 41

- 4) in F344/N Rats and in B 6C3F1 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.

49 U.S. Environmental Protect ion 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/027 0.htm.

50 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.

51 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is available electronically at http://www.atsdr.cdc.gov/ToxProfiles/TP.asp?id=296&tid=53.

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- 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,

blur red vision, headache, and fatigue. Inhalation studies in rodents have reported behavioral effects, neurophysiological changes and neuropathological effects upon inhalation exposure to n

hexane. Under the Guidelines for Carcinogen Risk Assessment (U.S. EP A, 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. 52



### 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 (H 2 

### S). Information regarding the health effects of those compounds can be found in EPA‘s IRIS database. 53



### 4.5 VOCs

4.5.1 VOCs as a PM2.5 precursor

This rulemaking would reduce emissions of VOCs, which are a precursor to PM 2.5. 

### Most VOCs emitted are oxidized to carbon dioxide ( CO 2 

### ) rather than to PM, but a portion of VOC

emission contributes to ambient PM 2.5 

### levels as organic carbon aerosols (U.S. EPA, 2009a).
Therefore, reducing these emissions would reduce PM 2.5 

### formation, human exposure to PM 2.5 

### , and the incidence of PM 2.5 

### - related health effects. However, we have not quantified the PM 2.5 

### - related benefits in this analysis. Analysis of organic carbon measurements sugges t 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 i s 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 inv entory it is unlikely this sector has a large contribution to

52 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>.

53 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris

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- 19 ambient secondary organic carbon aerosols. Photochemical models typically estimate secondary organic carbon from anthropogenic VOC emissions to be less than 0.1 μg/m 3



### .

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

PM 2.5 

### formation to VOC emission reductions, we are unable to estimate the effect that reducing

V OCs will have on ambient PM 2.5 

### levels without air quality modeling.

4.5.2 PM

2.5 

### health effects and valuation

Reducing VOC emissions would reduce PM 2.5 

### formation, human exposure, and the

incidence of PM 2.5 

### - related health effects. Reducing exposure to PM 2.5 

### is associated with significant human health benefits, including avoiding mortality and respiratory morbidity.

Researchers have associated PM 2.5 

### - exposure with adverse health effects in numerous toxicological, clinical and epidemiological studies (U.S. EPA, 2 009a). When adequate data and resources are available, EPA generally quantifies several health effects associated with exposure

to PM 2.5 

### (e.g., U.S. EPA (2010c)). These health effects include premature mortality for adults
and infants, cardiovascular mor bidity 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 PM 2.5 

### 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 par ticle 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 PM 2.5 

### in the underlying epidemiology studies.

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- 20 Previous studies have estimated the monetized benefits

- per

- ton of reducing VOC

emissions associated with effect that those emissions have on ambient PM 2.5 

### levels and the health

effects associated with PM 2.5 

### 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. 54 

### 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 PM 2.5 

### 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, a s shown in Table

4

- 6 . EPA gener ally 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 distr ibution 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

54 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.

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- 21 between VOC emissions and PM 2.5 

### , these factors lead us to conclude that the available VOC benefit per ton estimates are not appropriate to calculate monetized benefits of the se rules, even as a bounding exercise.

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- 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 Expert J Expert K Expert

L

Atlanta $620 $1,500 $1,600 $1,200 $1,200 $860 $2,000 $1,100 $730 $920 $1,200 $980 $250 $940 Chicago $1,500 $3,800 $4,000 $3,100 $3,000 $2,200 $4,900 $2,800 $1,800 $2,300 $3,000 $2,500 $600 $2,400

Dallas $300 $740 $780 $610 $590 $420 $960 $540 $360 $450 $590 $480 $120 $460

Denver $720 $1,800 $1,800 $1,400 $1,400 $1,000 $2,300 $1,300 $850 $1,100 $1,400 $1,100 $280 $850

NYC/ Philadelphia $2,100 $5,200 $5,500 $4,300 $4,200 $3,000 $6,900 $3,900 $2,500 $3,200 $4,200 $3,400 $830 $3,100

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

Salt Lake $1,300 $3,100 $3,300 $2,600 $2,500 $1,800 $4,100 $2,300 $1,500 $1,900 $2,500 $2,100 $530 $2,000 San Joaquin $2,900 $7,000 $7,400 $5,800 $5,600 $4,000 $9,100 $5,200 $3,400 $4,300 $5,600 $4,600 $1,300 $4,400

Seattle $280 $680 $720 $530 $550 $390 $890 $500 $330 $420 $550 $450 $110 $330 National average $1,200 $3,000 $3,200 $2,400 $2,400 $1,700 $3,900 $2,200 $1,400 $1,800 $2,400 $1,900 $490 $1,800

* These estimates assume a 50 percent reduction in VOC emissions, an analysis year of 2015, and a 3 percent discount rate. All estimates are rounded to two significant digits. These estimates have been updated from Fann, Fulcher, and Hubbell (2009) to reflect a more recent curren cy year and EPA‘s current VSL estimate. Using a discount rate of 7 percent , the benefit

- per

- ton estimates would be approximately 9 percent lower. Assuming a 75 percent reduction in VOC emissions would increase the benefit

- per

- ton estimates by approximately 4 percen t to 52 percent . Assuming a 25 percent reduction in VOC emissions would decrease the benefit

- per

- ton estimates by 5 percent to 52 percent . EPA generally presents a range of benefits estimates derived from Pope et al. (2002) to Laden et al. (2006) and pro vides the benefits estimates derived from the expert functions from Roman et al. (2008) as a characterization of uncertainty.

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- 23 4.5.3 Organic PM welfare effects According to the residual risk assessment for this sector (U.S. EPA, 2011a), persisten t 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 h ealth 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 th e 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 contributio n 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 comprehe nsive 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 wer e 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 e cosystems, 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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- 24 counter to the original working hypothesis that most of the contaminants would originate from Eastern Europe and Asia

.

4.5.4 Visibility E

ffects

Reducing secondary formation of PM 2.5 

### 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 part icles, 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, 2006 b ; U.S. EPA, 2010 c; U.S. EPA, 2011a ) show that visibility benefits are a significant welfare benefit category. Without air quality modeling, w e 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 emiss ions of VOCs, which are also precursor s 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,

2006 a ). Therefore, reducing these emissions would reduce ozone formation, human exposure to
ozone, and the incidence of ozone

- related health effects. However, we have not quantified the

ozone

- related benefits in this analysis for several reasons. First, previous rules have shown that the monetized benefits associated with reducing ozone exposure are generally smaller than PM

related benefits, even when ozone is the pollutant targeted for control (U.S. EPA, 2010 a ). Second, the complex non

- linear chemistry of ozone forma tion introduces uncertainty to the development and application of a benefit

- per

- ton estimate. Third, the impact of reducing VOC

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- 25 emissions is spatially heterogeneous depending on local air chemistry. Urban areas with a hig h population concentration are of ten 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 valu ation

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 nu merous 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 ). Thes e 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 $1 5 million of monetized benefits from reduced ozone exposure (U.S. EPA, 2011 b ). 55 

### 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 geo graphic 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

55 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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- 26 estimates to provide useful estimates of the monetized benefits of these rules, eve n 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 p lant 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 forci ng (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, t ropospheric ozone (ozone in the lower atmospher e) 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 t emporal 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 CO 2 

### and methane

. This discernable influence of ground level ozone on climate lead s to increases in global surface temperature and changes in hydrological cycle s

. 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
pote ntial 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 CO 2 

### is necessary to

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- 27 protect against long

- term climate change, reducing SLCF gases includi ng ozone is beneficial and will slow the rate of climate change within the first half of this century (UNEP 2011).

4.7 Methane (CH 4 

### )

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

o zone 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 rura l 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 g as. 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 CO 2 

### globally. Methane, in addition to other GHG emissions, contributes to warming of the atmosphere which over time leads to increased air a nd 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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- 28 P rocesses in the oil and gas category emit significant amounts of methane. The 1990

- 2009 U.S. GHG Inventory estimates 2009 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries) to be 251.55 MMtCO 2 

### - e. The emissions estimated from well completions and recompletions exclude a significant number of wells completed in tight sand plays, such as the Marcellus, due to availability of data when the 2009 Inventory was developed. The estimate in this proposal in cludes an adjustment for tight sand plays (being considered as a planned improvement in development of the 2010 Inventory). This adjustment would increase the 2009 Inventory estimate by 76.74 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, is 328.29 MMtCO2

- e. Total methane emissions from the oil and gas industry represent about 37 percent of the total methane emissions from all sources and account

for about 4 percent of all CO 2 

### - equivalent (CO 2 

### - e) emissions in the U.S., with natural gas systems being the single largest contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2011 b ).

This rulemaking proposes emission control technologies and regu latory 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 64.5 million metric tons CO 2 

### - e. This

annual CO 2 

### - 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

CO 2 

### - e emissions fro m changes in consumer energy usage patterns previously discussed are considered. These reductions represent about 19 percent of the GHG emissions for this sector reported in t he 1990

- 2009 U.S. GHG Inventory . However, it is important to note the emissions reductions are based upon predicted activities in 2015; EPA did not forecast sector

- level emissions to 2015 for this rulemaking. T he climate co

- benefit from these reductions are equivalent of taking approximately 11 million passenger cars off the road or eliminating electricity use from about 7 million homes each year.

EPA estimates the social benefits of regulatory actions that have a small or ―marginal‖ impact on cumulative global CO 2 

### emissions using the ―social cost of carbon‖ (SCC). The SCC

is an e stimate of the net present value of the flow of monetized damages from a one metric ton

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- 29 increase in CO 2 

### emissions in a given year (or from the alternative perspective, the benefit to society of reducing CO 2 

### emissions by one ton). The SCC includes (but is n ot 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 interagen cy process that included EPA and other executive branch entities, and concluded in February 2010. The SCC Technical Support Document (SCC TSD) for the final joint EPA/Department of Transportation Rulemaking to establish Light

- Duty Vehicle Greenhouse Gas Em ission Standards and Corporate Average Fuel Economy Standards provides a complete discussion of the methods used to develop the SCC

estimates.

The interagency group selected four SCC values for use in regulatory analyses: $6, $25, $40, and $76 per metri c ton of CO 2 

### 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 clima te 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 ass umptions 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 r ate. It is included to represent higher

- than

- expected damages from temperature change further out in the tails of the SCC distribution.

The interagency group noted a number of limitations to the SCC analysis, including the incomplete way in which the inte grated assessment models capture catastrophic and non

catastrophic impacts, their incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk

aversion. The li mited 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 estima tes used

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- 30 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 par ticularly relevant to this rulemaking is that the social costs of non

- CO 2 

### GHG emissions were not estimated. Specifically, the interagency group did not directly estimate the social cost of non

- CO 2 

### GHGs using the three models. Moreover, the group determin ed that it would not transform the CO 2 

### estimates into estimates for non

- CO 2 

### 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 particula r timeframe relative to CO 2 

### . One potential method for approximating the value of marginal non

- CO 2 

### GHG emission reductions is to convert the

reductions to CO 2 

### - equivalents which may then be valued using the SCC. Conversion to CO 2 

### - e is typically done using the GWPs for the non

- CO 2 

### 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

- CO 2 

### gas relative to CO 2 

### . 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. Th is 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 t he 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 impac t 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

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- 31 ways that are not captured by GWP. For instance, CO 2 

### emissions, unlike methane will result in

CO 2 

### passive fertilization to plants.

In light o f these limitations, and the significant contributions of non

- CO 2 

### emissions to climate change, further analysis is required to link non

- CO 2 

### emissions to economic impacts and to develop social cost estimates for methane specifically. Such work would feed in to efforts to develop a monetized value of reductions in methane greenhouse gas emissions in assessing the

co

- benefit s of this rulemaking. As part of ongoing work to further improve the SCC estimates, the interagency group hopes to develop methods to valu e greenhouse gases other than CO 2 

### , such as methane, by the time SCC estimates for CO 2 

### emissions are revised.

The EPA recognizes that the methane reductions proposed in this rule will provide significant econo mic climate co

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

- benefit s. The  ̳GWP approach‘ of converting methane to CO 2 

### - e using the GWP of methane, as previously described, is one approximation method for estimat ing the monetized value of the methane reductions anticipated from this rule. This calculation uses the GWP of the non

- CO 2 

### gas to estimate CO 2 

### equivalents and then multiplies these CO 2 

### equivalent emission reductions by the SCC to generate

monetized estimates of the co

- benefit s. If one makes these calculations for the proposed Option 2 (includes expected methane emission reductions from the NESHAP amendments and NSPS

and considers secon dary impacts) of the oil and gas rule, the 2015 co

- benefit s vary by discount rate and range from about $373 million to over $4.7 billion; the mean SCC at the 3 percent
discount rate results in an estimate of $1.6 billion in 2015. These co

- benefit s equate t o 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. (See Table 4

- 7 below for estimates for Options 1 and 3 also.)

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 m 

### ethane r elative to CO 2 

### (about 12 years compared to CO 2 

### whose

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- 32 concentrations in the atmosphere decay on timescales of decades to millennia). The climate impacts also differ

Table 4

- 7 Climate Methane Co

- benefit s Using „GWP‟ Approach

SCC Value for 2015 emission reductions 1

($/ton CO 2 ) (2008$) Total Co

- benefit s based on 100 year GWP adjustment 2 (millions 2008$)

NSPS Option 1 NSPS

Option 2 (Proposed) NSPS

Option 3 RTR

Floor

$6 (mean 5% discount rate) 180.1 372.2 380.5 0.5 $25 (mean 3% discount rate) 750.5 1,551.0 1,585.3 2.3 $40 (mean 2.5% discount rate) 1,200.8 2,481.6 2,536.4 3.6 $76 (95 th percentile at 3% discount rate) 2,281.5 4,715.0 4,819.2 6.8
Methane Emission Reductions 3 (MMT CO 2 - e) 30.02 62.04 63.41 0.09

1 SCC values for 2015 from the SCC TSD in the light duty vehicle rule adjusted to reflect 2008$ using the CPI

- U from the Bureau of Labor Statistics.
2 Represents the CO2

- e estimate of methane reductions multiplied by the SCC estimates.
3 Estimates include methane reductions from the NSPS Options and RTR Floor respectively and consider secondary impacts from Table 4

- 4.


### between the pollutants for reasons other than the radiative forcing profiles and atmospheric lifetimes of these gases. M ethane is a precursor to ozone and ozone is a short

- lived climate forcer as previously discussed. This use of the SAR GWP to approximate benefit s may underestimate the direct radiative forcing benefits of reduced ozone levels, and does not capture

any seco ndary 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 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

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- 33 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 b ut 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.

Th e SAR GWP value for methane is also currently used to establ ish GHG reporting requirements

as mandated by the GHG Reporting Rule (2 010e ) 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 (2010 f ).

EPA also undert ook 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 th e 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 un certainties 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 co

benefit estimates as an interim method to produce lower

- bound estimates until the interagency group develops values for non

- CO 2 

### 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

used to value the co

- benefit s of methane emis sion reductions anticipated for the oil and gas industry from this rule. Comments specific to whether GWP is an acceptable method for
generat ing a placeholder value for the social cost of methane until interagency modeled estimates

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- 34 become available are we lcome. 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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- 35 4.8 Reference s

Fankhauser, S. 199 4. ― The social costs of greenhouse gas emissions: an expected value approach. ‖ Energy Journal 15 (2):157

– 184.

Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. ― The influence of location, source, and emission type in estimates of the human health benefits of reducing a ton of air pollution. ‖ Air Qual Atmos Health 2:169

- 176.

Forster, P. et al. 2007

. Changes in Atmospheric Constituents an d in Radiative Forcing. In: Climate Change 2007. The Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change [Solomon, S., D. Qin, M. Manning, Z. Chen, M. Marquis, K.B. Averyt, M. Tignor and H.L. Miller (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, N Y, USA.

Gwinn, M.R

. , J . Craig
, D.A . Axelrad
, R . Cook
, C . Dockins
, N . Fann
, R . Fegley
, D.E . Guinnup
, G

. Helfand
, B . Hubbell
, S.L . Mazur
, T . Palma
, R.L . Smith
, J . Vandenberg , and B

. Sonawane. 2011. ―Meeting report: Estimating th e benefits of reducing hazardous air pollutants

— summary of 2009 workshop and future considerations.‖ Environ Health Perspect

. 119(1): p. 125

- 30.

Hammitt , J.K. , A.K. Jain
, J.L. Adams, and D.J. Wuebbles. 19 96

. ― A welfare

- based index for assessing environmental effects of greenhouse

- gas emissions. ‖ Nature , 381(6580):301

– 303, 1996.

Hope, C

. 2005. ― The climate change benefits of reducing me thane emissions. ‖ Climatic Change 68(1):21

– 39.

Hope , C. and D. Newbery. 2006. ―Calculating the Social Cost of Carbon‖ Forthcoming in Delivering a Low Carbon Electricity System: Technologies, Economics and Policy Editors: Michael Grubb, Tooraj Jamasb and Michael G. Pollitt (University of Cambridge) Cambridge University Press. Available on the Internet at

< http://www.dspace.cam.ac.uk/handle/1810/194738 > Accessed March 30, 2011.

Industrial Econo mics, Inc (IEc). 2009. Section 812 Prospective Study of the Benefits and Costs of the Clean Air Act: Air Toxics Case Study

— Health Benefits of Benzene Reductions in Houston, 1990

– 2020. Final Report , July 14, 2009.

< http://www.epa.gov/air/sect812/dec09/812CAAA_Benzene_Houston_Final_Report_Jul y_2009.pdf>. Accessed March 30, 2011.

Interagency Working Group on Social Cost of Carbon (IWGSC). 2010. T echnical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA

- HQ

- OAR

- 2009

- 0472

- 114577. Participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture,

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- 36 Department of Commerce, Department of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and Depa r tment of Treasury. < http://www.epa.gov/otaq/climate/regulations.htm > Accessed March 30, 2011.
Intergovernmental Panel on Climate Change ( IPCC ). 2007

. Climate Change 2007: Synthesis Report. Contribution of Working Groups I, II and III to the Fourth Assessme nt Report of the Intergovernmental Panel on Climate Change (AR4) [Core Writing Team, Pachauri, R.K and Reisinger, A. (eds.)]. IPCC, Geneva, Switzerland, 104 pp.

< http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report _synthesis_ report.htm >. Accessed March 30, 2011/
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< http://www.ipcc.ch/publi cations_and_data/ar4/wg2/en/ch20s20

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Kandlikar , M

. 1995. ― The relative role of trace gas emissions in greenhouse abatement policies. ‖ Energy Policy 23(10): 879

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Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. ―Reduction in Fine Particulate Air Pollution and Mortality.‖ American Journal of Respiratory and Critical Care Medicine 173:667

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Landers DH; Simonich SL; Jaffe DA; Geiser LH; Campbell DH; Schwindt AR; Schreck CB; Kent ML; Hafner WD; Taylor HE; H ageman KJ; Usenko S; Ackerman LK; Schrlau JE ; Rose NL; Blett TF; Erway MM. 2008. The Fate, Transport and Ecological Impacts of Airborne Contaminants in Western National Parks (USA) . EPA/600/R

- 07/138. U.S. Environmental Protection Agency, Office of Research and Development, NHEERL, Western Ecology Division. Corvallis, Oregon.

Marten, A. and S. Newbold. 2011. ―Estimating the Social Cost of Non

- CO 2 

### GHG Emissions: Methane and Nitrous Oxide.‖ NCEE Working Paper Series # 11

- 01.

< http://yosemite.epa.gov/ee/epa/ eed.nsf/WPNumber/2011

- 01?opendocument >

. Accessed March 30, 2011.
Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. Krewski, K. Ito, and G.D. Thurston. 2002. ―Lung Cancer, Cardiopulmonary Mortality, and Long

- term Exposure to Fine Particulate Air Pol lution.‖ Journal of the American Medical Association 287:1132

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Roman, H.A., K.D. Walker, T.L. Walsh, L. Conner, H.M. Richmond, .J. Hubbell, and P.L. Kinney. 2008. ―Expert Judgment Assessment of the Mortality Impact of Changes in Ambient Fine Particula te Matter in the U.S.‖ Environ. Sci. Technol . 42(7):2268

- 2274.

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- 37 Task Force on Hemispheric Transport of Air Pollution (HTAP). 2010. Hemispheric Transport of Air Pollution 2010 . Informal Document No.10. Convention on Long

- range Transboundary Air Pollution Exe cutive Body 28th Session. ECE/EB.AIR/2010/10 (Cor rected). Chapter 4, pp. 148

- 149

. Tol, R

. ( 2006 ). NEEDS Project 502687  ̳ New Energy Externalities Developments for Sustainability Integrated Project ‘ < http://www.needs

project.org/RS1b/NEEDS_RS1B_TP_T5.4_T5.5.pdf >. Accessed March 30, 2011.

Tol, R, R. J. Heintz, and P.E.M. Lammers. 2003. ― Methane emission reduction: An application of FUND. ‖ Climatic Change 57(1):71

– 98

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U.S. Environmental Protection Agency (U.S. EPA). 2006 a . Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). EPA/600/R

- 05/004aF

- cF. Washington, DC: U.S. EPA. < http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923 >

. Accessed March 30, 2011.

U.S. Environme ntal Protection Agency (U.S. EPA). 2006b. Regulatory Impact Analysis, 2006 National Ambient Air Quality Standards for Particulate Matter , Chapter 5. Office of Air Quality Planning and Standards, Research Triangle Park, NC. <http://www.epa.gov/ttn/ecas/r egdata/RIAs/Chapter%205

-- Benefits.pdf>. Accessed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 1995. Regulatory Impact Analysis for the Petroleum Refinery NESHAP. Revised Draft for Promulgation . Office of Air Quality Planning and Standards, Research Triangle Park, N.C. <http://www.reg

markets.org/admin/authorpdfs/page.php?id=705>. Accessed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 2009a. Integrated Science Assessment for Particulate Matter (Final Report). EPA

- 600

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- 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 Propos ed 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.
U.S. Environmental Protection Agency (U.S. EPA). 2010 a

. 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 >. Accesse d March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 201 1 b. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

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. EPA 430

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- 38 Washington, DC. <http://epa.gov/climatechange/emissions/ usinventory.html >. Accessed July 21 , 2011.
U.S. Environmental Protection Agency (U.S. EPA). 2010 c

. Regulatory Impact Analysis for the Proposed Federal Transport Rule. Office of Air Quality Planning and Standards, Research Triangle Park, NC. <http://www.ep a.gov/ttn/ecas/regdata/RIAs/proposaltrria_final.pdf>. Accessed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 2010 d

. Regulatory Impact Analysis for the SO 2 

### 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 a nd 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 Regist er Vol. 75, No. 106
, June 3, 2010 . 31514

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. 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). 2011 b

. 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://ww w.epa.gov/ttn/ecas/regdata/RIAs/boilersriafinal110221_psg.pdf >. Accessed March 30, 2011.
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 C ategories

. 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 Triangl e Park, NC. March

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

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- 39 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

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- 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 05BF6F 6/$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.

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- 1 5 STATUTORY AND EXECUT IVE O RDER 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

―eco nomically 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.

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- 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 Benefits 2 N/A N/A N/A

Total Costs 3

- $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 exposure 5 Health effects of HAP exposure 5 Health effects of HAP exposure 5
Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Visibility impairment Visibility impairment Visibility impairment Vegetation effects Vegetation effects Vegetation effects
Climate effects 5 Climate effects 5 Climate effects 5

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 a nd indirect impacts of the reductions in emissions for this industrial sector with the data currently available. The specific control techn ologies for the proposed NSPS are anticipated to have minor secondary disbenefits, including an increase of 990,000 tons of CO 2 , 510 tons of NOx, 7.6 tons of PM, 2,8 00 t ons of CO, and 1,000 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO 2 - equivalent emission reductions are 6 2 million metric tons.

3 T he engineering compliance costs are annualized using a 7 percent discount ra t e.

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.

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- 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 ba sed 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

sp ecifically 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 for th 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 on ly 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 o n 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 estimat es 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 exce pt 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 base d on an average of 1,459 operators responding per year

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- 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. B urden 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 monit oring. 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 ot her 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 t he impact of this rule on small entities, a small entity is defined as: (1) a small business whose par ent company has no more than 500 employees (or revenues of less than $7 million for firms that transport natural gas via pipeli ne ) ; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a

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- 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 ec onomic 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 sma ll entitie s (SISNO SE)

. EPA performed a screening a nalysis for impacts on a sample
of expected affected small entities by comparing compliance costs to entity revenues.

Based u pon the analysis in Section 3.6.2.1 in this RIA , EPA recognizes that a subset of small

fi rms 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 th e 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 fro m 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

- relate d compliance costs to be significantly mi tigated, 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 ent ities by the

selecti on 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 ec onomic impact of the Proposed N E SHAP Amendments on
small entitie s, I certify that this action will not have a significant economic impact on a

substantial number of small en tities. Based upon the analysis in Section 3.6.2.2 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 a nalysis for impacts on all expected affected

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- 6 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 tha n 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile 11 firms (18 percent ) are likely to have impacts greater than 1 percent . Four of these 11 firms are likely to have impacts greater than 3
percent

. While these 11 fir ms 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 n ot 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 conta ins 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 rela tionship 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.

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- 7 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 comp liance 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 th e 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 Execut ive 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 asse ssments (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.

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- 8 Section 4(b) of Executive Order 13211 defines ―significant energy actions‖ as ―any action by an agency (normally published in the Federal Register ) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: 1)(i) that is a significant regulatory

action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or 2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy
action.‖ 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 suppl y, 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.

W e use the NEMS to estimate the imp acts 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 E nergy 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

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- 9 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. Additionally, the NSPS establishes several performanc e 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 Nationa l 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 di rects the EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable VCS

. The proposed rule involve s technical standards. Therefore, the requirements of the NTTAA apply to this action. We are proposing t o revise 40 CFR part 63, subparts HH and HHH

to allow ANSI/ASME PTC 19.10

– 1981, Flue and Exhaust Gas Analyses ( Par t 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 Mech anical Engineers (ASME), Three Park Avenue, New York,

NY 10016

- 5990. Also, we are proposing to revise 40 CFR p art 63, s ubpart HHH, to allow

ASTM D6420

- 99(2004), ―Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatogra phy/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 o il and n atural g as p roduction NESHAP (Area Sources) (72 FR 36, January 3, 200 7).
As a result, the EPA is proposing ASTM D6420

- 99 for use in 40 CFR p art 63, s ubpart 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.

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- 10 Th e EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially

- applicable VCS and to explain why such standards should be used in this regulation.

5.10 Executive Order 12898: Federal Actions to A ddress Environmental Justice in Minority Populations and Low

- Income Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on E nvironmental Justice (EJ) . Its main provision directs federal agencies, to the gr eatest 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 minorit y 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 V II.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 c onsideration, 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, respectiv ely)

. 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

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- 11 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 re gulations for

the oil and natural gas production and natural gas transmission and storage source categories , are associated with an acceptable level of risk and that the proposed additional requirements will provide an ample margin of safety to protect pub lic 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.

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- 1 6 COMPARISON OF BENEFI TS AND C OSTS

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 estimat ed 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 previous ly 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 amendm ents floor option to be $16 million. 56 

### EPA anticipates that this rule would reduce 9,200 tons of VOC , 4,900 tons of methane, and 1,4 00 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. Howeve r, 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. There fore, 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

56 See Section 3 of this RIA for more information regarding the cost estimates for the NESHAP.

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- 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 pri ce 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 in to 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 val ued at $26 0 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 PM 2.5 

### health

- related benef its

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- 3 of VOC emissions are valued at $280 to $7,000 per ton across a range of eight urban areas. 57 

### 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 a pproximately $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

valu e. 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 s hould be considered. Furthermore, a single pollutant can have multiple effects (e.g., VOCs contribute to both ozone

and PM 2.5 

### 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 th at 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 th ese 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.

57 See Section 4.5 of this RIA for more information regarding PM 2.5 benefits and Section 4.6 for more information regarding ozone benefits.

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- 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: Proposed 4 Option 3: Alternative

Total Monetized Benefits 2 N/A N/A N/A

Total Costs 3

- $19 million

- $45 million $77 million

Net Benefits N/A N/A N/A

Non

- monetized Benefits 17,000 tons of HAPs 5 37,000 tons of HAPs 5 37,000 tons of HAPs 5
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 exposure 5 Health effects of HAP exposure 5 Health effects of HAP exposure 5
Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Visibility impairment Visibility impairment Visibility impairment Vegetation effects Vegetation effects Vegetation effects
Climate effects 5 Climate effects 5 Climate effects 5

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 parti culate 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 techn ologies for the proposed NSPS are anticipated to have minor secondary disbenefits, including an increase of 990,000 tons of CO 2 , 510 tons of NOx, 7.6 tons of PM, 2,8 00 t ons of CO, and 1,000 tons of total hydrocarbons (THC) as well as emission reductions associated with th e energy system impacts. The net CO 2 - equivalent emission reductions are 6 2 million metric tons.

3 T he engineering compliance costs are annualized using a 7 percent discount ra t e.

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 th e engineering costs analysis section in the RIA.

5 Reduced exposure to HAPs and climate effects are co

- benefits.

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- 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 Benefits 2 N/A

Total Costs 3 $16 million

Net Benefits N/A

Non

- monetized Benefits 1,400 tons of HAPs 9,200 tons of VOCs 4

4,900 tons of methane 4

Health effects of HAP exposure

Health effects of PM 2.5 and ozone exposure 4

Visibility impairment 4 Vegetation effects 4

Climate effects 4

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 th ose 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 CO 2 , 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 CO 2 - equivalent emission reductions are 93 thousand metric tons.

3 The cost estimates are assumed to be equivalent to the engineering cost estimates. T he engineering compliance costs are annualized using a 7 percent discount ra t e

.

4 Reduced exposure to VOC emissions, PM 2.5 and ozone exposure, visibility and vegetation effects, and climate effects are co

- benefits.

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- 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 CO 2 990,000 990,000 990,000 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) CO 2 - e

- 1,000,000 1,700,000 1,400,000 N/A

Net Change in CO 2 - equivalent Emissions CO 2 - 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.