***E.O. 12866 Review

– Draft

– Do Not Cite, Quote, or Release During Review ***

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



# Regulatory Impact Analysis **Fi nal**  **New Source Performance Standards and Amendments to the**  **National Emissions Standards for Hazardous Air Pollutants**  **for the Oil and Natural Gas** 

**Industry**

U . S . Environmental Protection Agency Office of Air and Radiation Office of Air Quality Planning and Standards Research Triangle Park, NC 27711

April 201 2ii **CONTACT INFORMATION** This document has been prepared b y 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 IC F International contributed data and anal ys is to this document. Specific sections where EC/R In corporated made contributions include the sections describing emissions options, pollution control options, secondary impacts anal ys is, engineering cost anal ys is , and employ ment impacts . Specific sections where ICF Internati onal made contributions also include the sections describing emissions opti ons, pollution control options, engineering cost anal ys is , employ ment impacts , and small business impacts .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 S UMMARY OF RESULTS ................................ ................................ ................................ ................................ 1 - 2 1.2.1 NSPS Results ................................ ................................ ................................ ................................ ..... 1 - 2 1.2.2 NESHAP Amendments Results ................................ ................................ ................................ ......... 1 - 5 1.2.3 Results for Combined Small Entity Analysis for the NSPS and NESHAP Amendments ................. 1 - 7 1.3 S UMMARY OF NSPS I MPACTS C HANGES FROM THE P ROPOSAL RIA ................................ ............................ 1 - 7 1.4 S UMMARY OF NESHAP AMENDMENTS I MPACTS C HANGES FROM THE P ROPOSAL RIA .............................. 1 - 8 1.5 O RGANIZATION OF THIS REPORT ................................ ................................ ................................ .................. 1 - 8 **2 I**  **NDUSTRY P**  **ROFILE ................................**  **................................ ................................**  **............. 2**  **- 1**  2.1 INTRODUCTION ................................ ................................ ................................ ................................ ............ 2 - 1 2.2 P RODUCTS O F THE C RUDE O IL AND N ATURAL G AS INDUSTRY ................................ ................................ .... 2 - 2 2.2.1 Crude Oil ................................ ................................ ................................ ................................ ........... 2 - 2 2.2.2 Natural Gas ................................ ................................ ................................ ................................ ........ 2 - 2 2.2.3 Condensates ................................ ................................ ................................ ................................ ....... 2 - 3 2.2.4 Other Recovered Hydrocarbons ................................ ................................ ................................ ......... 2 - 3 2.2.5 Produced Water ................................ ................................ ................................ ................................ . 2 - 4 2.3 O IL AND 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 Tr ansmission and Distribution ................................ ................................ ....................... 2 - 8 2.4 RESERVES 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 INDUSTRY C OSTS ................................ ................................ ................................ ................................ ....... 2 - 31 2.5.1 Finding Costs ................................ ................................ ................................ ................................ ... 2 - 31 2.5.2 Lifting Costs ................................ ................................ ................................ ................................ .... 2 - 33 2.5.3 Operating and Equipment Costs ................................ ................................ ................................ ...... 2 - 34 2.6 F IRM C HARACTERI STICS ................................ ................................ ................................ ............................ 2 - 36 2.6.1 Ownership ................................ ................................ ................................ ................................ ........ 2 - 36 2.6.2 Size Distribution of Firms in Affected ................................ ................................ ............................. 2 - 37 2.6.3 Trends in National Employment and Wages ................................ ................................ ................... 2 - 39 2.6.4 Horizontal and Vertical Integration ................................ ................................ ................................ . 2 - 44 2.6.5 Firm - level Information ................................ ................................ ................................ .................... 2 - 45 2.6.6 Financial Performance and Condition ................................ ................................ .............................. 2 - 49 2.7 REFERENCES ................................ ................................ ................................ ................................ .............. 2 - 53 **3 E**  **MISSIONS AND E**  **NGINEERING C**  **OSTS ................................**  **................................ ................**  **3 -**  **1** 3.1 INTRODUCTION ................................ ................................ ................................ ................................ ............ 3 - 1 3.2 E MI SSI ONS P OINTS , C ONTROLS , AND ENGINEERI NG C OSTS A

NALYSIS ................................ ........................ 3 - 1iv

3.2.1 Emission Points and Pollution Controls assessed in the RIA ................................ ............................ 3 - 2 3.2.1.1 NSPS Emission Points and Pollution Controls ................................ ................................ ........ 3 - 2 3.2.1.2 NESHAP Emission Points and Pollution Controls ................................ ................................ ... 3 - 6 3.2.2 Engineering Cost Analysis ................................ ................................ ................................ ................. 3 - 7 3.2.2.1 NSPS Sources ................................ ................................ ................................ ........................... 3 - 8 3.2.2.2 NESHAP Sources ................................ ................................ ................................ ................... 3 - 25 3.3 REFERENCES ................................ ................................ ................................ ................................ .............. 3 - 26 **4 B**  **ENEFITS OF E**  **MISSIONS R** **EDUCTIONS ................................**  **................................ ...............**  **4 -**  **1** 4.1 INTRODUCTION ................................ ................................ ................................ ................................ ............ 4 - 1 4.2 D IRECT E MI SSION REDUCTIONS FROM THE O IL AND N ATURAL G AS R ULES ................................ ................ 4 - 2 4.3 S ECONDARY I MPACTS A NALYSI S 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 - Hexane ................................ ................................ ................................ ................................ .......... 4 - 17 4.4.7 Other Air Toxics ................................ ................................ ................................ .............................. 4 - 18 4.5 VOC ................................ ................................ ................................ ................................ .......................... 4 - 18 4.5.1 VOC as a PM 2.5 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 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 climate effects and valuation ................................ ................................ ............................. 4 - 27 4.7.2 Methane as an ozone precursor ................................ ................................ ................................ ........ 4 - 34 4.7.3 Com

bined methane and ozone effects ................................ ................................ ............................. 4 - 34 4.8 REFERENCES ................................ ................................ ................................ ................................ .............. 4 - 35 **5 S**  **TATUTORY AND E**  **XECUTIVE O**  **RDER R** **EVIEWS ................................**  **................................ 5**  **- 1**  5.1 E XECUTI

VE O RDER 12866, REGULATORY P LANNING AND REVIEW A ND E XECUTIVE O RDER 13563, I MPROVI

NG REG ULATION AND REGULATORY REVIEW ................................ ................................ .......................... 5 - 1 5.2 P APERWORK REDUCTION A CT ................................ ................................ ................................ ..................... 5 - 3 5.3 REGULATORY F LE XIBILITY A CT ................................ ................................ ................................ .................. 5 - 3 5.4 UNFUNDED M ANDATES REF ORM A CT ................................ ................................ ................................ ......... 5 - 5 5.5 E XECUTI

VE O RDER 13132: F EDERALISM ................................ ................................ ................................ .... 5 - 5 5.6 E XECUTI

VE O RDER 13175: C ONSULTATION AND C OORDINATION WITH INDIAN T RIBAL G OVERNMENTS ... 5 - 6 5.7 E XECUTI

VE O RDER 13045: P ROTECTION OF C HILDREN FROM ENVIRONMENTAL H EALTH RIS KS AND S AFETY RIS KS ................................ ................................ ................................ ................................ ................................ ..... 5 - 6 5.8 E XECUTI

VE O RDER 13211: A CTIONS C ONCERNI NG REG ULATIONS T HAT S IGN IF IC ANTLY A FFECT ENERGY S UPPLY , D ISTR IB UTION , OR U SE ................................ ................................ ................................ ............................ 5 - 7 5.9 NATIONAL T ECHNOLOGY T RANSFER AND A DVANCEMENT A CT ................................ ................................ .. 5 - 8 5.10 E XECUTI

VE O RDER 12898: F EDERAL A CTIONS TO ADDRESS ENVIRONMENTAL JUSTICE I N M IN ORITY P OPULATIONS AND L OW - INCOME P OPULATIONS ................................ ................................ ................................ ... 5 - 8 5.11 C ONGRESSIONAL REVIEW A CT ................................ ................................ ................................ .............. 5 - 10 **6 C**  **OMPARISON OF B**  **ENEFITS AND C**  **OSTS ................................**  **................................ .............**  **6 -**  **1 7**  **E CONOMIC**  **I MPACT**  **A NALYSIS AND**  **D ISTRIBUTIONAL**  **A SSESSMENTS**  **............................... 7**  **- 1** v

7.1 INTRODUCTION ................................ ................................ ................................ ................................ ............ 7 - 1 7.2 ENERGY S YSTEM I MPACTS A NALYSIS OF F INAL NSPS ................................ ................................ ................ 7 - 1 7.2.1 Description of the Department of Energy National Energy Modeling System ................................ .. 7 - 2 7.2.2 Inputs to National Energy Modeling System ................................ ................................ ..................... 7 - 5 7.2.2.1 Com

pliance Costs for Oil and Gas Exploration and Production ................................ .............. 7 - 6 7.2.2.2 Adding Averted Methane Emissions into Natural Gas Production ................................ .......... 7 - 9 7.2.2.3 Fixing Canadian Drilling Costs to Baseline Path ................................ ................................ ... 7 - 10 7.2.3 Energy System Impacts ................................ ................................ ................................ ................... 7 - 11 7.2.3.1 Im

pacts on Drilling Activities ................................ ................................ ................................ 7 - 11 7.2.3.2 Im

pacts on Production, Prices, and Consumption ................................ ................................ .. 7 - 12 7.2.3.3 Im

pacts on Imports and National Fuel Mix ................................ ................................ ............ 7 - 16 7.3 E MPL OYMENT I MPACT A NALYSI S ................................ ................................ ................................ .............. 7 - 19 7.3.1 Em

ployment Impacts from Pollution Control Requirements ................................ ........................... 7 - 20 7.3.2 Em

ployment Impacts Primarily on the Regulated Industry ................................ ............................. 7 - 23 7.4 S MALL B USINESS I MPACTS A NALYSIS ................................ ................................ ................................ ....... 7 - 27 7.4.1 Small Business National Overview ................................ ................................ ................................ . 7 - 28 7.4.2 Small Entity Economic Impact Measures ................................ ................................ ........................ 7 - 33 7.4.3 Small Entity Economic Impact Analysis, Final NSPS ................................ ................................ ..... 7 - 35 7.4.3.1 Overvie w of

Sample Data and Methods ................................ ................................ ................. 7 - 35 7.4.3.2 Small Entity Impact Analysis, Final NSPS, Results ................................ .............................. 7 - 41 7.4.3.3 Small Entity Impact Analysis, Final NSPS, Additional Qualitative Discussion .................... 7 - 47 7.4.4 Small Entity Economic Impact Analysis, Final NESHAP Amendments ................................ ........ 7 - 50 7.4.5 Conclusions for NSPS and NESHAP Amendments ................................ ................................ ........ 7 - 52 7.5 REFERENCES ................................ ................................ ................................ ................................ .............. 7 - 53vi **LIST OF TABLES** Table 1 - 1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS

in 2015 (millions of 2008$) 1

................................ ................................ ................................ ............... 1 - 4 Table 1 - 2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas

NESHAP in 2015 (millions of 2008$) 1

................................ ................................ .............................. 1 - 6 Table 2 - 1 Technically Re coverable 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 Cr

ude 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 W ellhead Prices, 2010 - 2035 ................................ ..... 2 - 29 Table 2 - 15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price ................................ ...... 2 - 31 Table 2 - 16 SBA Size Standards and Size Distribution of Oil and Natural Gas Firms ................................ ....... 2 - 38 Table 2 - 17 Oil and Natural Gas Industry Employment by NAICS, 1990 - 09 ................................ ..................... 2 - 39 Table 2 - 18 Oil and Natural Gas Industry Average Wages by NAICS, 1990 - 2009 (2008 dollars) ..................... 2 - 43 Table 2 - 19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2010 ................................ .......... 2 - 47 Table 2 - 20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009 ................................ .............. 2 - 48 Table 2 - 21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2009 ............................. 2 - 49 Table 2 - 22 Selected Financial Items from Income Statements (Billion 2008 Dollars) ................................ ...... 2 - 50 Table 2 - 23 Return on Investment for Lines of Business (all FRS), for 1998, 2003, and 2008 (percent) ........... 2 - 51 Table 2 - 24 Income and Production Taxes, 1990 - 2008 (Million 2008 Dollars) ................................ .................. 2 - 52 Table 3 - 1 Emissions Sources, Points, and Controls Included in th e Final NSPS ................................ ............... 3 - 9 Table 3 - 2 Summary of Capital and Annualized Costs per Unit for NSPS Emissions Points ........................... 3 - 15 Table 3 - 3 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost Effectiveness by Emissions Sources and Points, NSPS, 2015 ................................ ......................... 3 - 16 Table 3 - 4 Engineering Compliance Costs, NSPS (2008$)
................................ ................................ ............... 3 - 18 Table 3 - 5 Estimates of Control Unit - level and National Level Natural Gas and Condensate Recovery, NSPS,

2015 ................................ ................................ ................................ ................................ .................. 3 - 21 Table 3 - 6 Simple Rate of Return Estimate for Final NSPS Controls ................................ ............................... 3 - 23 Table 3 - 7 Summary of Estimated Capital and Annual Costs, Emissions Reductions, and HAP Reduction Cost Effectiveness for Final NESHAP Amendments ................................ ................................ ............... 3 - 26 Tabl e 4 - 1 Direct Emission Reductions Associated with the Oil and Natural Gas NSPS and NESHAP

Amendments in 2015 (short tons per year) ................................ ................................ ........................ 4 - 3 Table 4 - 2 Secondary Air Pollutant Impacts Associated with Control Techniques by Emissions Category

(“Producer - Side”) (tons per year) ................................ ................................ ................................ ....... 4 - 6 Table 4 - 3 Modeled Changes in Energy - related CO 2 - equivalent Emissions by Fuel Type for the Final Oil and

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

................................ ........................... 4 - 7 Table 4 - 4 Total Change in CO 2 - equivalent Emissions including Secondary Impacts for the Final Oil and Gas

NSPS in 2015 (million metric tons) ................................ ................................ ................................ ... 4 - 7 Table 4 - 5 Summary of Emissions Changes for the Final Oil and Gas NSPS and NESHAP in 2015 (short tons

per year) ................................ ................................ ................................ ................................ .............. 4 - 8 Table 4 - 6 Monetized Benefits - per - Ton Estimates for VOC (2008$)
................................ ............................... 4 - 22 Table 4 - 7 Climate Methane Benefits Using ‘GWP’ Approach ................................ ................................ ......... 4 - 32 Table 5 - 1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS

and NESHAP Amendments in 2015 (millions of 2008$) 1

................................ ................................ . 5 - 2vii

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

in 2015 (millions of 2008$) 1

................................ ................................ ................................ ............... 6 - 4 Table 6 - 2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas

NESHAP Amendments in 2015 (millions of 2008$) 1

................................ ................................ ........ 6 - 5 Table 6 - 3 Summary of Emissions Changes for the Final Oil and Gas NSPS and NESHAP in 2015 (short tons

per year) ................................ ................................ ................................ ................................ .............. 6 - 6 Table 7 - 1 Summary of Additional Annualized O&M Costs (on a Per New Well Basis) for Environmental Controls Entered into NEMS ................................ ................................ ................................ .............. 7 - 8 Table 7 - 2 Summary of Additional Per Completion/Recompletion Costs (2008$) for Environmental Controls

Entered into NEMS ................................ ................................ ................................ ............................ 7 - 9 Table 7 - 3 Successful Oil and Gas Wells Drilled, NSPS ................................ ................................ ................... 7 - 11 Table 7 - 4 Successful Wells Drilled by Well Type (Onshore, Lower 48 States), NSPS ................................ ... 7 - 12 Table 7 - 5 Annual Domestic Natural Gas and Crude Oil Production, NSPS ................................ .................... 7 - 13 Table 7 - 6 Natural Gas Production by Well Type (Onshore, Lower 48 States), NSPS ................................ ..... 7 - 14 Table 7 - 7 Lo wer 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS ................................ ............ 7 - 15 Table 7 - 8 Delivered Natural Gas Prices by Sector (2008$ per million BTU), 2015, NSPS ............................. 7 - 15 Table 7 - 9 Natural Gas Consumption by Sector, NSPS ................................ ................................ ..................... 7 - 16 Table 7 - 10 Net Imports of Natural Gas and Crude Oil, NSPS ................................ ................................ ........... 7 - 17 Table 7 - 11 Total Energy Consumption by Energy T ype (Quadrillion BTU), NSPS ................................ .......... 7 - 18 Table 7 - 12 Modeled Change in Energy - related "Consumer - Side" CO 2 - equivalent GHG Emissions ................ 7 - 19 Table 7 - 13 Labor - based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and

Maintaining Control Equipment Requirements, NSPS, 2015 ................................ .......................... 7 - 25 Table 7 - 14 Labor - based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and

Maintaining Control Equipment Requirements, Final NESHAP Amendments, 2015 ..................... 7 - 26 Table 7 - 15 Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007 .... 7 - 30 Table 7 - 16 Distribution of Small and Large Firms by Number of Firms, Total Employment, and Estimated

Receipts by Firm Size and NAICS, 2007 ................................ ................................ ......................... 7 - 31 Table 7 - 17 Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009 ............................... 7 - 33 Table 7 - 18 Estimated Revenues for Firms in Sample, by Firm T ype and Size ................................ .................. 7 - 37 Table 7 - 19 Descriptive Statistics of Capital and Exploration Expenditures, Small and Large Firms in Sample,

2008 and 2009 (million 2008 dollars) ................................ ................................ .............................. 7 - 38 Table 7 - 20 Descriptive Statistics of Estimated Wells Drilled, Small and Large Firms in Sample, 2008 and 2009

(million 2008 dollars) ................................ ................................ ................................ ....................... 7 - 39 Table 7 - 21 Distribution of Estimated Final NSPS Compliance Costs Without Revenues from Additional Natural

Gas Product Recovery across Firm Size in Sample of Firms ................................ ........................... 7 - 42 Table 7 - 22 Distribution of Estimated Final NSPS Compliance Costs With Revenues from Additional Natural Gas

Product Recovery across Firm Size in Sample of Firms ................................ ................................ .. 7 - 43 Table 7 - 23 Summary of Sales Test Ratios, Without Revenues from A dditional Natural Gas Product Recovery for

Firms Affected by Final NSPS ................................ ................................ ................................ ......... 7 - 44 Table 7 - 24 Summary of Sales Test Ratios, With Revenues from Additional Natural Gas Product Recovery for

Firms Affected by Final NSPS ................................ ................................ ................................ ......... 7 - 45 Table 7 - 25 Im

pact Levels of Final NSPS on Small Firms as a Percent of Small Firms in Sample, With and Without Revenues from Additional Natural Gas Product Recovery ................................ ................ 7 - 46 Table 7 - 26 Summary of Sales Test Ratios for Firms Affected by Final NESHAP Amendments ...................... 7 - 51 Table 7 - 27 Affected Small Firms as a Percent of Sm all Firms Nationwide, Final NESHAP Amendments ...... 7 - 52 Table 7 - 28 Affected Small Firms as a Percent of Small Firms Nationwide, Final NSPS and NESHAP

Amendments ................................ ................................ ................................ ................................ ..... 7 - 52viii **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, 199 0 - 2009. ................................ ...................... 2 - 16 Figure 2 - 3 U.S. Produced Water Volume by Management Practice, 2007 ................................ ........................ 2 - 19 Figure 2 - 4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990 - 2009 ............................. 2 - 22 Figure 2 - 5 Natural Gas Consumption by Sector (Percent of Total Consumption), 1990 - 2009 ......................... 2 - 24 Figure 2 - 6 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010 - 2035 ................................ ....... 2 - 28 Figure 2 - 7 Forecast of Domestic Crude Oil Production and Net Imports, 2010 - 2035 ................................ ....... 2 - 30 Figure 2 - 8 Costs of Crude Oil and Natural Gas Wells Drilled, 1981 - 2008 ................................ ....................... 2 - 32 Figure 2 - 9 Finding Costs for FRS Companies, 1981 - 2008 ................................ ................................ ................ 2 - 33 Figure 2 - 10 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981 - 2008 (3 - year Running Average) 2 -

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

dollars), 1976 - 2009 ................................ ................................ ................................ .......................... 2 - 35 Figure 2 - 12 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas Price, 1976 - 2009

2 - 36 Figure 2 - 13 Em

ployment 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 Em

ployment in Crude Petroleum and Natural Gas Extraction (NAICS 211111) and Total Crude Oil and Natural Gas Production (boe), 1990 - 2 009 ................................ ................................ ................. 2 - 41 Figure 2 - 15 Em

ployment in Natural Gas Liquid Extraction (NAICS 211112), Employment in Pipeline Transportation of Natural G as (NAICS 486210), and Total Natural Gas Production, 1990 - 2009 ... 2 - 42 Figure 2 - 16 Oil and Natural Gas Industry Average Wages by NAICS, 1990 - 2009 ($2008)
............................... 2 - 44 Figure 3 - 1 Sensitivity Analysis of Final NSPS Annualized Costs after Revenues from Additional Product

Recove ry are Included ................................ ................................ ................................ ...................... 3 - 19 Figure 4 - 1 Conceptual Diagram of Secondary Impacts from Oil and Gas NSPS and NESHAP Amendments ... 4 - 5 Figure 4 - 2 Estimated Chronic Census Tract Carcinogenic Risk from HAP exposure from outdoor sources (2005

NATA) ................................ ................................ ................................ ................................ ............. 4 - 10 Figure 4 - 3 Estimated Chronic Census Tract Noncancer (Respiratory) Risk from HAP exposure from outdoor

sources (2005 NATA) ................................ ................................ ................................ ...................... 4 - 11 Figure 6 - 1 Illustrative Break - Even Diagram for Alternate Natural Gas Prices for the NSPS .............................. 6 - 2 Figure 7 - 1 Organization of NEMS Modules (source: U.S. Energy Information Administration) ....................... 7 - 41 - 1 **1 EXECUTIVE SUMMARY**  **1.1 Background**  The U.S. Environmental Protectio n Agency (EPA) reviewed the New Source Performance Standards (NSPS) for volatile organic compound and sulfur dioxide emissions from Natural Gas Processing Plants. As a result of these NSPS, this rule amends the Crude Oil and Natural Gas Production source category currently listed under section 111 of the Clean Air Act to include Natural Gas Transmission and Distribution, amends the existing NSPS for volatile organic compounds ( VOC ) from Natural Gas Processing Plants, and finalizes NSPS for stationary sourc es in the source categories that are not covered b y the existing NSPS. In addition, this rule address es the residual risk and technology review conducted for two source categories in the Oil and Natural Ga s sector regulated by separate National Emission S tandards for Hazardous Air P ollutants (NESHAP) . It also finalizes standards for emission sources not currentl y addressed, as well as amendments to improve aspects of these NESHAP related to applicability

and implementation. Finall y, it address es provisio ns in these NESHAP related to emissions during periods of startup, shutdown, and malfunction. As part of the regulatory

process, EPA is required to develop a regulatory impact anal ys is (RIA) for rules that have costs or benefits that exceed $100 million. EPA estimates the final NSPS will have costs that exceed $100 million, so the Agency has prepared an RIA. Because the NESHAP Amendments are being finalized in the same rulemaking package (i.e., same P reamble), we have chosen to present the economic impact anal ys is for the final NESHAP Amendments within the same document as the NSPS RIA. This RIA includes an economic impact anal ys is and an anal ys is of human health and climate impacts anticipated from th e final NSPS and NESHAP Amendments . We also estimate potential impacts of the final NSPS on the national energy economy using the U.S. Energy In formation Administration’s National Energy Modeling S ys tem (NEMS). The engineering compliance costs are annual ized using a 7 percent discount rate . This anal ysis assumes an anal ys is year of 2015. Several emission controls for the NSPS capture VOC emissions that otherwise would be vented to the atmosphere. Since methane is co - emitted with VOC , a large proportion of the1 - 2

averted methane emissions can be directed into natural gas production streams and sold. One emissions control option, reduced emissions well completions, also recovers saleable hydrocarbon condensates which would otherwise be lost to the environment. The revenues derived from additional natural gas and condensate recovery are expected to offset the engineering costs of implementing the NSPS . In the economic impact and energy econom y anal ys es for the NSPS, we present results that include the additi onal product recovery and the revenues we expect producers to gain from the additional product recovery. **1.2 Summary of Results**  **1.2.1 NSPS Results**  For the final NSPS, the key results of the RIA follow and are summarized in Table 1 - 1 :

 **Benefits Analysis:** The final NSPS is anticipated to prevent significant new emissions , including 290,000 tons of VOC , as well as 19,000 tons of hazardous air pollutants ( HAP ) and 1.7 million tons of methane. While we expect that these avoided emissions will result in improvements in ambient air quality and reductions in health effects associated with exposure to HAP , ozone, and particulate matter (PM), we have determined that quantification of those benefits cannot be accomplished for this rule . This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impac ts of the reductions in emissions for this industrial sector with the data currentl y available. In addition to health improvements, there will be improvements in visibility effects, ecos ys tem effects, as well as additional natural gas recovery . The methan e emissions reductions associated with the final NSPS are likely to result in significant climate co - benefits. The specific control technologies for the final NSPS are anticipated to have minor secondary

disbenefi ts, including an increase of 1.2 million t ons of carbon dioxide (CO 2 ), 630 tons of nitrogen oxides NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy s ys tem impacts. The net CO 2 - equivalent (CO 2 - e ) emission reductions are 31 million metric tons.

 **Engineering Cost Analysis:** EPA estimates the total capital cost of the final NSPS will be $3 40 million. T he estimate of total annualized engineering costs of the final NSPS will be $33 0 million. When estimated re venues from additional natural gas and condensate recovery are included, the annualized engineering costs of the final NSPS are estimated at - $ 18 million, assuming a wellhead natural gas price of $4/thousand cubic feet (Mcf) and condensate price of $70/bar rel. Possible explanations for why there appear to be negative cost control technologies are discussed in the engineering costs analy sis section in the RIA. The estimated engineering compliance costs that include the product recovery are sensitive to the assumption about the price of the recovered product. There is also geographic variability in wellhead prices, which can also influence estimated engineering costs. For example, $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $ 82 million, given EPA estimates that 8 2 billion cubic feet of natural gas will be recovered b y imple menting the NSPS . All estimates are in 2008 dollars.1 - 3

 **Energy System Impacts:** Using the NEMS, when additional natural gas recove ry is included, the anal ys is of energy s ys tem impacts for the final NSPS shows that domestic natural gas production is likely to increase slightly ( about 60 billion cubic feet or 0.3 percent) and average natural gas prices to decrease slightl y (about $0 .05 /Mcf or 1.2 percent at the wellhead for onshore production in the lower 48 states). Domestic crude oil production is not expected to change, while average crude oil prices are estimated to decrease slightly (about $0.01 /barrel or about 0.01 percent at the wellhead for onshore production in the lower 48 states). All prices are in 2008 dollars.  **Small Entity Analyses:** For the final NSPS, EPA performed a screening analysis for impacts on a sample of expected affected small entities by comparing compliance costs to entity revenues. When revenue from additional natural gas product recovered is not included, we estimate that 120 of the 127 small firms analyzed (9 4.5 percent) are likely to have impacts less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, seven firms (5.5 percent) are likely to have impacts greater than 1 percent. Three of these seven firms are likely to have impacts greater than 3 percent. However, when revenue from additional natural gas p roduct recovery is included, we estimate that none of the anal yz ed firms will have an impact greater than 1 percent.

 **Employment Impacts Analy sis:**  EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipment, as w ell as labor associated with new reporting and recordkeeping requirements. We estimate up - front and continual, annual labor requirements b y estimating hours of labor required for compliance and converting this number to full - time equivalents (FTEs) b y div iding b y 2,080 (40 hours per week multiplied by 52 weeks). The up - front labor requirement to comply with th e final NSPS is estimated at 50 full - time - equivalent employees. The annual labor requirement to comply with final NSPS is estimated at about 1,100 f ull - time - equivalent employees. We note that this ty pe of FTE estimate cannot be used to identify the specific number of people involved or whether new jobs are created for new employe **e** s , versus displacing jobs from other sectors of the econom y .1 - 4

**Table 1**  **- 1**  **Summary of the Monetized Benefits,**  **Costs, and Net Benefits for the Fi**  **nal Oil**  **and Natural Gas NSPS in 2015 (millions of 2008$)**  **1 Final**  **4** Total Monetized Benefits 2 N/A Total Costs 3 - $1 8 million Net Benefits N/A Non - monetized Benefits 19 ,000 tons of HAP 5 290 ,000 tons of VOC 1.7 million tons of methane 5 Health effects of HAP exposure 5 Health effects of PM 2.5 and ozone exposure

Visibility impairment Vegetation effects 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 HAP , ozone, and particulate matter (PM) as well as climate effects associated with methane, we have determined that quantification of those benefits and co - benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits or co - benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefi ts, including an increase of 1.2 million to ns of carbon dioxide (CO 2 ), 630 tons of nitrogen oxides NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO 2 - equivalent (CO 2 - e ) emission reductions are 31 million metric tons. 3 T he engineering compliance costs are annualized using a 7 percent discount rat e. 4 The negative cost for the NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recove ry

that are estimated as a result of the final NSPS. Possible explanations for why there appear to be negative cost control technologies are discussed in the engineering costs analysis section in the RIA. 5 Reduced exposure to HAP and climate effects ar e co - benefits.1 - 5

**1.2.2 NESHAP Amendments**  **Results** For the final NESHAP Amendments , th e key results of the RIA follow and are summarized in Table 1 - 2 :

 **Benefits Analysis:** The final NESHAP Amendments are anticipated to reduce a significant amount of e xisting emissions, including 1,300 tons of HAP , 9,000 tons of VOC , and 4,800 tons of meth ane. While we expect that these avoided emissions will result in improvements in ambient air quality

and reductions in health effects associated with exposure to HAP , ozone, and PM , we have determined that quantification of those benefits cannot be accomp lished 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 currentl y available. In addition to health improvements, there will be improvements in visibility effects, ecosy stem effects, and climate effects as well as additional natural gas recovery . The specific control technologies for the NESHAP is anticipated to have minor secondary disbenefits, including an increase of 5,500 tons of 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 s ys tem impacts. The net CO 2 - equivalent emission reductions are 90,000 metric tons.

 **Engineering Cost Analysis:** EPA estimates the total capital costs of the final NESHAP Amendments to be $47 million. Total annualized engineering costs of the final NESHAP Amendments are estimated to be $18 m i llion. All estimates are in 2008 dollars.

 **Energy System Impacts:** We did not estimate the energy econom y impacts of the final NESHAP Amendments as the expected costs of the rule are not likel y to have estimable impacts on the national energy ec onom y.
 **Small Entity Analyses:** For the final NESHAP Amendments , EPA estimates that 54 of the 108 firms (50 percent) that own potentially affected facilities are small entities. The EPA performed a screening analy sis for impacts on all expected affected small entities by comparing compliance costs to entity revenues. Among the small firms, 45 of the 54 (83 percent) are likely

to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, nine firms (17 percent) are likely to have impacts greater than 1 percent. Three of these nine firms are likely to have impacts greater than 3 percent. While these nine firms might receive significant impacts from the final NESHAP Amendments , they

represent a very

small slice of the oil and gas industry in its entirety , less than 0.2 percent of the estimated 6,427 small firms in NAI CS 211.

 **Employment Impacts Analysis:** EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipment, as well as labor associated with new reporting and recordkeeping requirements. We estimate up - front and continual, annual labor requirements b y estimating hours of labor required for compliance and converting this number to full - time equivalents (FTEs) b y dividing b y 2,080 (40 hours per week multiplied by 52 weeks). The up - front labor requirement to comply with the final NESHAP Amendments is estimated at 120 full - time - equivalent employees. The annual labor requirement to compl y with final NESHAP Amendments is estimated at about 94 full - time equivalent emplo yees. We no te that this ty pe of FTE estimate cannot be used to identify the1 - 6

specific number of people involved or whether new jobs are created for new employees , versus displacing jobs from other sectors of the economy .  **Break -**  **E ven Analysis:**  A break - even anal ys is suggests that HAP emissions would need to be valued at $1 4 ,000 per ton for the benefits to exceed the costs if the health benefits , ecos ys tem 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 , 9 00 per ton or the methane emissions would need to be valued at $ 3 , 7 00 per ton for the benefits to exceed the costs. Previous asses sments 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 specific urban areas. , ozone benefits valued at $240 to $1,000 per ton of VOC emissions reduced, and climate co
- benefits valued at $110 to $1,400 per short ton of methane reduced. All estimates are in 2008 dollars. **Table 1**  **- 2**  **Summary of the Monetized Benefits,**  **Costs, and Net Benefits for the Fi**  **nal Oil**  **and Natural Gas NESHAP in 2015 (millions of 2008$) 1**  **Final** Total Monetized Benefits 2 N/A Total Costs 3 $18 million Net Benefits N/A Non - monetized Benefits 1,3 00 tons of HAP 9,0 00 tons of VOC 4 4,8 00 tons of methane 4 Health effects of HAP exposure Health effects of PM 2.5 and ozone exposure 4

Visibility impairment4 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 HAP, ozone, and PM as well as climate effects associated with methane, we have determined that quantification of those benefits and co - benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits or co - benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. The specific control technologies for the NESHAP is anticipated to have minor secondary disbenefits, including an increase of 5,500 tons of 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 CO 2 - equivalent emission reductions are 9 0,000 metric tons. 3 The engineering compliance costs are annualized using a 7 percent discount rat e. 4 Reduced exposure to VOC emissions, PM 2.5 and ozone exposure, visibility and vegetation effects, and climate1 - 7

effects are co - benefits. **1.2.3 Results for**  **Combined Small Entity**  **Analysis for the NSPS and NESHAP Amendments**  After considering the economic impact of the combined NSPS and NESHAP Amendments on small entities, EPA certifies this action will not have a significant impact on a substantial number of small entities (SI SNOSE). While both the NSPS and NESHAP amendment would individually result in a no SI SNOSE finding, EPA performed an additional sc reening anal ys is in order to certify the rule in its entirety . This anal ys is compared compliance costs to entity

revenues for the total of all the entities affected b y the NESHAP Amendments and the sample of entities anal yz ed for the NSPS. When revenues from additional natural gas product sales are not included, 153 of the 169 small firms (91 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, 16 firms (9 percent) are likely to have impacts greater than 1 percent. Six of these 16 firms are likel y to have impacts greater than 3 percent. When revenues from additional natural gas product sales are included, 160 small firms (95 percent) are likely to have impacts of less than 1 p ercent. Nine firms (5 percent) are likely to have impacts greater than 1 percent, while only

three of these nine are likel y to have impacts greater than 3 percent. **1.3 Summary of NSPS Impacts Changes from the Proposal RIA**  This section summarizes significant c hanges from the proposal version of the RIA. These changes were a result of revised assumptions and technical factors, as well as changes in the rule itself from proposal.

 **Changed estimate of number of recompleted wells:** The NSPS proposal estimated that 12, 050 reduced emissions completions ( RECs ) for existing natural gas well recompletions would be required in addition to those already required b y state regulations. EPA has reevaluated the assumption based on data submitted to the Agency . Based on this information, EPA has estimated the recompletion frequency to be 1% of fractured gas wells per year , rather than 10 percent .  **W ell completions**  **with insufficient pressure to implement RECs required to combust completions emissions:**  Using the formula estimated to identify wells that would not have sufficient pressure to perform an REC, ap proximately 10 percent of well completions and recompletions would be required to combust emissions rather than implement an REC.  **Revised natural gas emissio ns factor for well completions and recompletions of**  **hydraulically fractured wells:** The EPA received several comments regarding the emission factor selected to calculate whole gas emissions (and the associated VOC emissions) from hydraulically fractured wel l completions. Comments focused on the data1 - 8

behind the emission factor, what the emission factor is intended to represent, and the procedures used to develop the emission factor from the selected data sets. We reviewed all information received and have de cided to retain the data set and the analy sis conducted to develop the emission factor , but rounded from 9,175 Mcf per completion to 9,000 Mcf per completion. More detailed discussion is presented in a technical memorandum on this subject in the docket.  **Re moval of compressors and pneumatic devices in**  **the natural gas transmission segment from NSPS:**  In the final rule, proposed requirements relating to reciprocating and centrifugal compressors and pneumatic devices in transmission segment are removed. Requ irements pertaining to storage vessels in the transmission segment remain.  **Reporting and recordkeeping costs** : EPA identified several way s to streamline reporting and recordkeeping requirements. As a result, the estimated annual cost of reporting and recordkeeping from $19 million per year to $7.1 million per year. **1.4 Summary of**  **NESHAP Amendments Im**  **pacts Changes from the Proposal RIA** The cost and emissions reduction estimates for the NESHAP Amendments did not change significantl y from proposal. Total annualiz ed costs increased about $1.5 million per year. **1.5 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 . Sec tion 3 describe s the emissions and engineering cost anal ys is. Section 4 presents the benefits analy sis . Section 5 presents statutory

and executive order analy ses. Section 6 presents a comparison of benefits and costs. Section 7 presents energy s ys tem impact, employ

ment impact, and small business impact anal ys es.2 - 1 **2 INDUSTRY PROFILE**  **2.1 Introduction**  The oil and natural gas industry i ncludes the following five segments : drilling and extraction, processing, transportation, refining , and marketing. The Oil and Natural Gas NSPS and NESHAP Amendments require controls for the oil and natural gas products and processes of the drilling and extraction of crude oil and natural gas, natural gas processing, and natural gas transportation segments. Most crude oil and natural gas production facilities are classified under NAICS 211 : Crude Petroleum and Natural Gas Extraction (211111) and Natural Gas Liquid Extraction (211112). The drilling of oil and natural gas wells is included in NAI CS 213111. Most natural gas transmission and storage facilities are classified under NAICS 486210

—Pipeline Transportation of Natural Gas. While other NAICS (213112

— Support Activities for Oil and Gas Operations, 221210

— Natural Gas Distribution, 486110

—Pipeline Transportation of Crude Oil, and 541360

—Geophy sical Surveying and Mapping Services) are often included in the oil and natural gas sector, these are not discussed in detail in the Industry Profile because they

are not directly

affected by

the final N SPS 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, the Energy Information Administration ( EIA ) estimates that about 526,000 producing oi l wells and 493,000 producing natural gas wells operated in the United States. Domestic dry natural gas production was 20.5 trillion cubic feet (tcf) in 2009, the highest production level since 1970. The leading five natural gas producing states are Texa s, Alaska, Wyoming, Oklahoma, and New Mexico. Domestic crude oil production in 2009 was 1 , 938 million barrels (bbl ) . The leading five crude oil producing states are Texas, Alaska, California, Oklahoma, and New Mexico. The Industry

Profile provides a brief introduction to the components of the oil and natural gas industry

that are relevant to the final NSPS and NESHAP Amendments . The purpose is to give the reader a general understanding of the geophy sical, engineering, and economic aspects of the industry

that are addressed in subsequent economic anal ys is in this RIA . The Industry Profile relies heavily

on background material from the U.S. EPA ’s “ Economic Analy sis of Air2 - 2

Pollution Regulations: Oil and Natural Gas Production ” (1996) and the U.S. EPA ’s “ Sector Notebook Project : Profile of the Oil and Gas Extraction Industry” (2000). **2.2 Products of the**  **Crude Oil and Natural Gas Industry**  Each producing crude oil and natural gas field has its own unique properties. The composition of the crude oil and natural gas and reservoir characteristics are likely to be different from that of an y other reservoir. **2.2.1 Crude Oil**  Crude oil can be broadl y classified as paraffinic, naphthenic (or asphalt - based), or intermediate. Generall y, paraffinic crudes are used in the manu facture of lube oils and kerosene . Paraffinic crudes have a high concentration of straight chain hydrocarbons and are relativel y low in sulfur compounds. Naphthenic crudes are generally used in the manufacture of gasolines and asphalt and have a high con centration of olefin and aromatic h ydrocarbons. Naphthenic crudes may contain a high concentration of sulfur compounds. Intermediate crudes are those that are not classified in either of the above categories. Another classification measure of crude oil and other hydrocarbons is by APIgravity . APIgravity

is a weight per unit volume measure of a hydrocarbon liquid as determined by a method recommended b y the American Petroleum Institute (API). A heavy or paraffinic cru de oil is ty pically one with APIgravity

of 20 o or less, while a light or naphthenic crude oil, which ty picall y 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 indus try 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 varyingquantities of non - hy drocarbons that exists in a gaseous phase or in solution with crude oil or other hydrocarbon liquids in natural2 - 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 partiall y processed natural gas produced from a reservoir that contains condensable hydrocarbons. Dry gas is either 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 ar e classified as sour gases. Those with threshold concentrations of CO 2 are classified as acid gases. The process b y which these two contaminants are removed from the natural gas stream is called sweetening. The most common sweetening method is amine tre ating. Sour gas contains a H 2 S concentration 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 nearl y all of offshore natural gas production is classified as sweet. **2.2.3 Condensates**  Condensates are h ydrocarbons in a gaseous state under reservoir conditions, but become liquid in either the wellbore or the production process. Condensates, including volatile oils, ty picall y have an API gravity 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 Recovered Hydrocarbons**  Various h ydrocarbo ns may be recovered through the processing of the extracted hydrocarbon streams. These hydrocarbons include mixed natural gas liquids (NGL), natural gasoline, propane, butane, and liquefied petroleum gas (LPG).2 - 4

**2.2.5 Produced Water**  Produced water is the water recovered from a production well. Produced water is separated from the extra cted hydrocarbon streams in various production processes and operations . **2.3 Oil and Natural Gas Production Processes**  **2.3.1 Ex** 

**ploration and Drilling** Exploration involves the search for ro ck formations associated w ith oil or natural gas deposits and involves geophy sical prospecting and/or exploratory drilling. Well development occurs after exploration has located an economically recoverable field and involves the construction of one or more wells from the beginning (called spudding) to either abandonment if no hydrocarbons are found or to well completion if hydrocarbons are found in sufficient quantities. After the site of a well has been located, drilling commences. A well bore is created by using a rotary

drill to drill into the ground. As the well bore gets deeper sections of drill pipe are added. A mix of fluids called drilling mud is released down into the drill pipe then up the walls of the we ll bore, 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 infil tration into the well and to prevent crude oil and natural gas from contaminating the water table. The steel pipe is cemented by filling the gap between the steel casing and the wellbore with cement . Horizontal drilling technology has been available sin ce 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 ga s can move into the well. Horizontal wells are particularl y 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 the2 - 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 open to secure gas flow from the form ation (U.S. EPA, 2004) . **2.3.2 Production**  Production is the process of extracting the h ydrocarbons and separating the mixture of liquid hydrocarbons, gas, water, and solids, removing the constituents that are non - saleable, and selling the liquid hydrocarbons an d gas. The major activities of crude oil and natural gas production are bringing the fluid to the surface, separating the liquid and gas components, and removing impurities. Oil and natural gas are found in the pores of rock s and sand (H yn e, 2001) . In 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 drilled to reach the reservoir, the oil and gas can be extracted in different way s d epending on the well pressure (H yne, 2001) . Frequently , oil and natural gas are produced from the same reservoir. As wells deplete the reservoirs into which they are drilled, the g as 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 l iquid. Production sites often handle crude oil and natural gas from more than one well (Hy ne, 2001) .2 - 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 the res ource out of the well directl y. Well pressure depletes during this process. Ty pically , about 30 to 35 percent of the resource in the reservoir is extracted this way (Hy ne, 2001) . The amount extracted depends on the specific well characteristics (such as permeability and oil viscosity). Lacking enough pressure for the resource to surface, gas or water is injected into the well to increase the well pressure and force the resource out ( **s econdary**  or **im proved oil recovery** **).** Finally , **in tertiary e**  **xtraction** o r **enhanced recovery,**  g as, chemicals or steam are injected into the well. This can result in recovering up to 60 percent of the original amount of oi l in the reservoir (Hy ne, 2001) . In contrast to conventional sources, unconventional oil and gas are trapp ed 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 nventional source. M ining, induced pressure, or heat is required t o release the resource. The specific ty pe of extraction method needed depends on the ty pe of formation where the resource is located. Unconventional natural gas resource ty pes relevant for this rule 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 fragmented, 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 Gas:** Reservo irs 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 drilling2 - 7

is used but given that coalbed methane reservoir s are frequentl y associated with underground water reservoirs, hydraulic fracturing is often restricted (Andrews, 2009) . **2.3.3 Natural Gas Processing**  Natural gas conditioning is the process of removing impurities from the gas stream so that it is of sufficient q

uality to pass through transportation sy stems and used by final consumers. Conditioning is not always required. Natural gas from some formations emerges from the well sufficiently

pure that it can be sent directly to the pipeline. As the natural gas is separated from the liquid components, it may contain impurities that pose potential hazards or other problems. The most significant impurity is H 2 S, which may

or may not be contained in natural gas. H 2 S is toxic (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 ga s hydrates, which are solids that can clog pipes, valves, and gauges, especiall y at cold temperatures (Manning and Thompson, 1991) . Nitrogen and other gases may

also be mixed with the natural gas in the subsurface. These other gases must be separated fro m 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 . Deh ydration 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 gl yc ol 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 cry stals with high surface areas that attract the water molecules. The solids can be regenerated simply by heating them above the boiling po int of water. Finally , particularl y 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, gl ycol deh ydration is the most common when processing at or near the well.2 - 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 process, the gas stream is exposed to an amine so lution, which will react with the H 2 S and separate them from the natural gas. The contaminant gas solution is then heated, thereb y s eparating the gases and regenerating the amine. The sulfur gas may

be disposed of by

flaring, incinerating, or when a mark et 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 stations, high - pressure transmission pipelines, and often - underground storage sites. Compressor stations are any facility which supplies energy

to move natural gas at increased pressure in trans mission pipelines or into underground storage. Typically , compressor stations are located at intervals along a transmission pipeline to maintain desired pressure for natural gas transport. These stations will use either large internal combustion engines or gas turbines as prime movers to provide the necessary horsepower to maintain system pressure. Underground storage facilities are subsurface facilities utilized for storing natural gas which has been transferred from its original location for the primary purpose of load balancing, which is the process of equalizing the receipt and delivery of natural gas. Processes and operations that may be located at underground storage facilities include compression and dehydration. **2.4 Reserves and Markets**  Crude oil and natural gas have historicall y served two separate and distinct 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. Ho wever, as pipeline infrastructure and L NG trade expand, natural gas is increasingl y a national and international commodity . The following subsections provide historical and forecast data on the U.S. reserves, production, consumption, and foreign trade of crude oil and natural gas .2 - 9

**2.4.1 Domestic Proved Reserves**  Table 2 - 1 shows crude oil and natural gas proved reserves , inferred reserves, undiscovered technicall y recoverable resources 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 anal ys is of geologic and engineering data demonstrates with reasonable certainty are recoverable under existing economic and operating conditions.

 **Inferred reserves:**  the estimate of total volume recovery from known crude oil or natural gas 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 recoverab le resources equal the total technicall y recoverable resources. As seen in Table 2 - 1 , as of 2007, proved domestic crude oil reserves accounted for about 12 percent of the totally technicall y recoverable crude oil reso urces.

1 U.S. Department of Energy, Energy Information Administration, Glossary of Terms <http://www.eia.doe.gov/glossary/index.cfm?id=P > Accessed 12/21/2010.2 - 10

**Table 2**  **- 1**  **Technically Recoverable Crude Oil and Natural Gas Resource Estimates, 2007**  Region Proved Reserves Inferred

Reserves Undiscovered

Technically Recoverable Resources Total

Technically Recoverable Resources Crude Oil and Lease Condensate (billion bbl) 48 States Onshore 14.2 48.3 25.3 87.8 48 States Offshore 4.4 10.3 47.2 61.9 Alaska 4.2 2.1 42.0 48.3 Total U.S. 22.8 60.7 114.5 198.0 Dry Natural Gas (tcf) Conventionally Reservoired Fields 194.0 671.3 760.4 1625.7 48 States Onshore Non - Associated Gas 149.0 595.9 144.1 889.0 48 States Offshore Non - Associated Gas 12.4 50.7 233.0 296.0 Associated - Dissolved Gas 20.7 117.2 137.9 Alaska 11.9 24.8 266.1 302.8 Shale Gas and Coalbed Methane 43.7 385 64.2 493.0 Total U.S. 237.7 1056.3 824.6 2118.7 Source: U.S. Energy Information Administration, **Annual Energy Review 2010 .**  Inferred reserves for 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 technical ly

recoverable natural gas resources. Significant proportions of these reserves exist in Alaska and offshore areas. Table 2 - 2 and Figure 2 - 1 show trends in crude oil and natural gas production and reserves from 1990 to 2008. In Table 2 - 2 , proved ultimate recovery equals the sum of cumulative production and proved reserves. While crude oil and natural gas are nonrenewable resources, the table shows that proved ultimate recovery rises over time as new discoveries become economicall y 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, when oil prices are high there is mo re of an incentive to use secondary and tertiary recovery , as well as to develop unconventional sources.2 - 11

**Table 2**  **- 2**  **Crude Oil and Natural Gas Cumulative Domestic Production, Proved Reserves, and Proved**  **Ultimate Recovery, 1977 -**  **2008**

Crude Oil and Lease Condensate

(million bbl) Dry Natural Gas (bcf) Year Cumulative

Production Proved

Reserves Proved

Ultimate Recovery Cumulative

Production Proved

Reserves Proved

Ultimate Recovery 1990 158,175 27,556 185,731 744,546 169,346 913,892 1991 160,882 25,926 186,808 762,244 167,062 929,306 1992 163,507 24,971 188,478 780,084 165,015 945,099 1993 166,006 24,149 190,155 798,179 162,415 960,594 1994 168,438 23,604 192,042 817,000 163,837 980,837 1995 170,832 23,548 194,380 835,599 165,146 1,000,745 1996 173,198 23,324 196,522 854,453 166,474 1,020,927 1997 175,553 23,887 199,440 873,355 167,223 1,040,578 1998 177,835 22,370 200,205 892,379 164,041 1,056,420 1999 179,981 23,168 203,149 911,211 167,406 1,078,617 2000 182,112 23,517 205,629 930,393 177,427 1,107,820 2001 184,230 23,844 208,074 950,009 183,460 1,133,469 2002 186,327 24,023 210,350 968,937 186,946 1,155,883 2003 188,400 23,106 211,506 988,036 189,044 1,177,080 2004 190,383 22,592 212,975 1,006,564 192,513 1,199,077 2005 192,273 23,019 215,292 1,024,638 204,385 1,229,023 2006 194,135 22,131 216,266 1,043,114 211,085 1,254,199 2007 196,079 22,812 218,891 1,062,203 237,726 1,299,929 2008 197,987 20,554 218,541 1,082,489 244,656 1,327,145 Source: U.S. Energy Information Administration, **Annual Energy Review 2010**  **.** However, annual production as a percentage of proved reserves has declined over time for both crude oil and natural gas, from above 10 percent in the earl y 1990s to 8 to 9 percent from 2006 to 2008 for crude oil and from above 11 percent during the 1990s to about 8 percent from 2008 to 2008 for natural gas.2 - 12

**Figure 2**  **- 1**  **A) Domestic**  **Crude Oil Proved Reserves an d 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 b y state or producing area as of 2008. Four areas currently account for 77 percent of the U.S. total proved reserves of crude o il, 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. **A). C**  **rude O** **il**

0 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008**C r** **u d** **e O** **i l** **( m** **i l** **l i** **o n** **b b** **l )** 

**B) . N**  **at ur**  **al G**  **as**

0 50,000 100,000 150,000 200,000 250,000

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008**N a** **t u** **r a** **l G** **a s** **( b** **c f** **)**

Cu

mu lati veProdu cti on Prov

ed R eserv es2 - 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 currentl y 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 b y almost 750 million bbl since 1990 .2 - 14

**Table 2**  **- 4**  **Crude Oil Domestic Production, Wells, Well Productivity, and U.S.**  **Average First Purchase Price**  Year Total Production

(million bbl) Producing Wells (1000s) Avg. Well

Productivity (bbl/well) U.S. Average First

Purchase Price/Barrel (2005 dollars) 1990 2,685 602 4,460 27.74 1991 2,707 614 4,409 22.12 1992 2,625 594 4,419 20.89 1993 2,499 584 4,279 18.22 1994 2,431 582 4,178 16.51 1995 2,394 574 4,171 17.93 1996 2,366 574 4,122 22.22 1997 2,355 573 4,110 20.38 1998 2,282 562 4,060 12.71 1999 2,147 546 3,932 17.93 2000 2,131 534 3,990 30.14 2001 2,118 530 3,995 24.09 2002 2,097 529 3,964 24.44 2003 2,073 513 4,042 29.29 2004 1,983 510 3,889 38.00 2005 1,890 498 3,795 50.28 2006 1,862 497 3,747 57.81 2007 1,848 500 3,697 62.63 2008 1,812 526 3,445 86.69 2009 1,938 526 3,685 51.37* Source: U.S. Energy Information Administration, **Annual Energy Review 2010.**  First purchase price represents the average price at the lease or wellhead at which domestic crude is purchased. * 2009 Oil price is preliminary 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 gener ally 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 nearly 3000 bcf from the 1990 to 2009 ( Table 2 - 5 ) . Natural gas extracted from crude oil wells (associated natural gas) has remained more or less constant for the last twenty years . Coalbed methane has become a significant component of overall gas withdrawals in recent years.2 - 15

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

(bcf) Natural Gas Well Productivity
Year Natural Gas

Wells Crude Oil

Wells Coalbed

Methane Wells Total Dry Gas Production* Producing

Wells (no.) Avg.

Productivity per Well (MMcf) 1990 16,054 5,469 NA 21,523 17,810 269,100 59.657 1991 16,018 5,732 NA 21,750 17,698 276,337 57.964 1992 16,165 5,967 NA 22,132 17,840 275,414 58.693 1993 16,691 6,035 NA 22,726 18,095 282,152 59.157 1994 17,351 6,230 NA 23,581 18,821 291,773 59.468 1995 17,282 6,462 NA 23,744 18,599 298,541 57.888 1996 17,737 6,376 NA 24,114 18,854 301,811 58.770 1997 17,844 6,369 NA 24,213 18,902 310,971 57.382 1998 17,729 6,380 NA 24,108 19,024 316,929 55.938 1999 17,590 6,233 NA 23,823 18,832 302,421 58.165 2000 17,726 6,448 NA 24,174 19,182 341,678 51.879 2001 18,129 6,371 NA 24,501 19,616 373,304 48.565 2002 17,795 6,146 NA 23,941 18,928 387,772 45.890 2003 17,882 6,237 NA 24,119 19,099 393,327 45.463 2004 17,885 6,084 NA 23,970 18,591 406,147 44.036 2005 17,472 5,985 NA 23,457 18,051 425,887 41.025 2006 17,996 5,539 NA 23,535 18,504 440,516 40.851 2007 17,065 5,818 1,780 24,664 19,266 452,945 37.676 2008 18,011 5,845 1,898 25,754 20,286 478,562 37.636 2009 18,881 5,186 2,110 26,177 20,955 495,697 38.089 Source: U.S. Energy Information Administration, **Annual Energy Review 2010.**  *Dry gas production is gas production after accounting for gas used repressurizing wells, the removal of nonhydrocarbon gases, vented and flared gas, and gas used as fuel during the production process. The number of wells producing natural gas wells has nearl y 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.2 - 16

**Figure 2**  **- 2**  **A) Total Producing Crude Oil Wells and Average Well Productivity, 1990**  **- 2009. B) Total Producing Natural Gas Wells and Average Well Productivity, 1990**  **- 2009.**  Domestic e xploration and development for oil has continued during the last two decades. From 2002 to 2009, crude oil well drilling s howed significant increases, although the 1992 - 2001 period showed relativel y low levels of crude drilling activity compared to periods before and after ( Table 2 - 6 ). The drop in 2009 showed a departure from this trend, likely due to the recession experienced in the U.S. Meanwhile, natural gas drilling has increased significantly during the 1990 - 2009 period . Like crude oil drilling, 2009 saw a relativel y 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 **A) . C**  **rude Oil W** **el ls** 

0 100 200 300 400 500 600 700

19 90 19 91 19 92 19 93 19 94 19 95 19 96 19 97 19 98 19 99 20 00 20 01 20 02 20 03 20 04 20 05 20 06 20 07 20 08 20 09**P r** **o d** **u c** **i n** **g W** **e l** **l s** 

0 1, 000 2, 000 3, 000 4, 000 5, 000**C r** **u d** **e O** **i l** **( b** **b l** **) /** **W e** **l l** 

Pro duci ng We lls (1000s ) Avg. W el l Pro duc ti vi ty (b bl /well) **B) . N**  **at ur** **al Ga**  **s We**  **lls**

0 100 200 300 400 500 600

19 90 19 91 19 92 19 93 19 94 19 95 19 96 19 97 19 98 19 99 20 00 20 01 20 02 20 03 20 04 20 05 20 06 20 07 20 08 20 09**P r** **o d** **u c** **i n** **g W** **e l** **l s** 

0 10 20 30 40 50 60 70**N a** **t u** **r a** **l G** **a s** **( M** **M c** **f )** **/ W** **e l** **l**

Pro duci ng We lls (1000s ) Avg. W ell Pro duc ti vi ty (M Mcf

)2 - 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 by product of the oil and natural gas industry, as management, including reuse and recycling, of produced water can be costly and challenging. Texas, California, Wyoming , Oklahoma , and Kansas were the top five states in terms of produced water volumes in 2007 ( Table 2 - 7 ). These estimates do not include estimates of flowback water from h ydraulic fracturing activities (ANL 2 009 ) .2 - 18

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

State Crude Oil

(1000 bbl) Total Gas

(bcf) Produced Wate r

(1000 bbl) Total Oil and

Natural Gas (1000 bbls oil equivalent) Barrels

Produced Water per Barrel Oil Equivalent Alabama 5,028 285 119,004 55,758 2.13 Alaska 263,595 3,498 801,336 886,239 0.90 Arizona 43 1 68 221 0.31 Arkansas 6,103 272 166,011 54,519 3.05 California 244,000 312 2,552,194 299,536 8.52 Colorado 2,375 1,288 383,846 231,639 1.66 Florida 2,078 2 50,296 2,434 20.66 Illinois 3,202 no data 136,872 3,202 42.75 Indiana 1,727 4 40,200 2,439 16.48 Kansas 36,612 371 1,244,329 102,650 12.12 Kentucky 3,572 95 24,607 20,482 1.20 Louisiana 52,495 1,382 1,149,643 298,491 3.85 Michigan 5,180 168 114,580 35,084 3.27 Mississippi 20,027 97 330,730 37,293 8.87 Missouri 80 no data 1,613 80 20.16 Montana 34,749 95 182,266 51,659 3.53 Nebraska 2,335 1 49,312 2,513 19.62 Nevada 408 0 6,785 408 16.63 New Mexico 59,138 1,526 665,685 330,766 2.01 New York 378 55 649 10,168 0.06 North Dakota 44,543 71 134,991 57,181 2.36 Ohio 5,422 86 6,940 20,730 0.33 Oklahoma 60,760 1,643 2,195,180 353,214 6.21 Pennsylvania 1,537 172 3,912 32,153 0.12 South Dakota 1,665 12 4,186 3,801 1.10 Tennessee 350 1 2,263 528 4.29 Texas 342,087 6,878 7,376,913 1,566,371 4.71 Utah 19,520 385 148,579 88,050 1.69 Virginia 19 112 1,562 19,955 0.08 West Virginia 679 225 8,337 40,729 0.20 Wyoming 54,052 2,253 2,355,671 455,086 5.18 **State Total 1,273,759**  **21,290 20,258,560**  **5,063,379 4.00**  Federal Offshore 467,180 2,787 587,353 963,266 0.61 Tribal Lands 9,513 297 149,261 62,379 2.39 **Federal Total 476,693**  **3,084 736,614**  **1,025,645 0.72**  **U.S. Total 1,750,452**  **24,374 20,995,174**  **6,089,024 3.45**  Source: Argonne National Laboratory and Department of Energy (2009). Natural gas production converted to barrels oil equivalent to facilitate comparison using the conversion of 0.178 barrels of crude oil equals 1000 cubic feet natural gas. Totals may not sum due to ind ependent rounding .2 - 19

As can be seen in Table 2 - 7 , the amount of water produced is not necessarily correlated with the ratio of water produced to the volume of oil or natural gas produced. Texas, Alaska and Wyoming were the three largest producers in barrels of oil equivalent (boe) terms , but had relativel y low rates of water production compared to more Midwestern states, such Il linois , Missouri, Indiana, and Kansas . Figure 2 - 3 shows the distribution of produced water management practices in 2007.

**Figure 2**  **- 3**  **U.S. Produced Water Volume by Management Practice, 2007** More than half of the water produced (51 percent) was re - injected to enhance resource recovery through maintaining reservoir pressure or hydraulically pushing oil from the reservoir. Another third (34 percent) was injected, typicall y 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 m ovement 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 relativel y constant. 51% 34% 3% 11% Injec ti on f or Enhanc ed R

ecov er y Injec ti on or Di sposal Su rf ace D is ch arge Unkno wn
Sourc e:A

rgonne National

L aboratory2 - 20

**Table 2**  **- 8**  **U.S. Oil and Natural Gas Pipeline Mileage, 1990 -**  **2008**

Oil Pipelines Natural Gas Pipelines Year Crude

Lines Product

Lines Total Distribution Mains Transmission

Pipelines Gathering

Lines Total 1990 118,805 89,947 208,752 945,964 291,990 32,420 1,270,374 1991 115,860 87,968 203,828 890,876 293,862 32,713 1,217,451 1992 110,651 85,894 196,545 891,984 291,468 32,629 1,216,081 1993 107,246 86,734 193,980 951,750 293,263 32,056 1,277,069 1994 103,277 87,073 190,350 1,002,669 301,545 31,316 1,335,530 1995 97,029 84,883 181,912 1,003,798 296,947 30,931 1,331,676 1996 92,610 84,925 177,535 992,860 292,186 29,617 1,314,663 1997 91,523 88,350 179,873 1,002,942 294,370 34,463 1,331,775 1998 87,663 90,985 178,648 1,040,765 302,714 29,165 1,372,644 1999 86,369 91,094 177,463 1,035,946 296,114 32,276 1,364,336 2000 85,480 91,516 176,996 1,050,802 298,957 27,561 1,377,320 2001 52,386 85,214 154,877 1,101,485 290,456 21,614 1,413,555 2002 52,854 80,551 149,619 1,136,479 303,541 22,559 1,462,579 2003 50,149 75,565 139,901 1,107,559 301,827 22,758 1,432,144 2004 50,749 76,258 142,200 1,156,863 303,216 24,734 1,484,813 2005 46,234 71,310 131,348 1,160,311 300,663 23,399 1,484,373 2006 47,617 81,103 140,861 1,182,884 300,458 20,420 1,503,762 2007 46,658 85,666 147,235 1,202,135 301,171 19,702 1,523,008 2008 50,214 84,914 146,822 1,204,162 303,331 20,318 1,527,811 Source: U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Office of Pipeline Safety, Natural Gas Transmission, Gas Distribution, and Hazardous Liquid Pipeline Annual Mileage , available at http://ops.dot.gov/stats.htm as of Apr. 28, 2010. Totals may not sum due to independent rounding . Table 2 - 8 splits natural gas pipelines into three types: distribution mains, transmission pipelines, and gathering lines. Gathering lines are low - volume pipelines that gather natural gas from production sites to deliver directly to gas processing plants or compres sion 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 di stribution sy stem that delivers the gas to final consumers. Table 2 - 8 shows gathering lines decreasing from 1990 from above 30,000 miles from 1990 to 1995 to around 20,000 miles in 2007 and 2008. Transmission pipelin es added2 - 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 ty pes of pipeline was in distribution, which increased about 260,000 miles during the 1990 to 2008 period , dri ving 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 e xpanding 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 graduall y until 2008 when consumption dropped as a result of the economic recession. The share of residential, commercial, industrial, and electric power on a percentage basis declined during this period, while the share of total consumption by

the transportation sector rose from 64 percent in 1990 t o 71 percent in 2009.

**Table 2**  **- 9**  **Crude Oil Consumption by Sector, 1990 -**  **2009** Percent of Total Year Total

(million bbl) Residential Commercial Industrial Transportation Sector Electric

Power 1990 6,201 4.4 2.9 25.3 64.1 3.3 1991 6,101 4.4 2.8 25.2 64.4 3.1 1992 6,234 4.4 2.6 26.5 63.9 2.5 1993 6,291 4.5 2.4 25.7 64.5 2.9 1994 6,467 4.3 2.3 26.3 64.4 2.6 1995 6,469 4.2 2.2 25.9 65.8 1.9 1996 6,701 4.4 2.2 26.3 65.1 2.0 1997 6,796 4.2 2.0 26.6 65.0 2.2 1998 6,905 3.8 1.9 25.6 65.7 3.0 1999 7,125 4.2 1.9 25.8 65.4 2.7 2000 7,211 4.4 2.1 24.9 66.0 2.6 2001 7,172 4.3 2.1 24.9 65.8 2.9 2002 7,213 4.1 1.9 25.0 66.8 2.2 2003 7,312 4.2 2.1 24.5 66.5 2.7 2004 7,588 4.0 2.0 25.2 66.2 2.6 2005 7,593 3.9 1.9 24.5 67.1 2.6 2006 7,551 3.3 1.7 25.1 68.5 1.4 2007 7,548 3.4 1.6 24.4 69.1 1.4 2008 7,136 3.7 1.8 23.2 70.3 1.1 2009* 6,820 3.8 1.8 22.5 71.1 0.9 Source: U.S. Energy Information Administration, **Annual Energy Review 2010**  **.** 2009 consumption is preliminary.2 - 22

**Figure 2**  **- 4**  **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 b y an average of about 1 percent per ye ar ( 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 dramaticall y , an important trend in the industry as man y utilities increasingl y 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 consumption levels at more or less constant levels during this time period. 0% 10% 20% 30% 40% 50% 60% 70% 80%

19 90 19 91 19 9219 93 19 9419 95 19 96 19 97 19 98 19 99 20 0020 01 20 02 20 03 20 04 20 05 20 06 20 07 20 08 20 09 ***C o** **n s** **u m** **p t** **i o** **n (** **% o** **f t** **o t** **a l** **)**

Resi den ti al Co mmerc ial In du stri al Transportati on Sector El ect ri c Power2 - 23

**Table 2**  **- 10**  **Natural Gas Consumption by Sector, 1990 -**  **2009** Percent of Total Year Total

(bcf) Residential Commercial Industrial Transportation Sector Electric

Power 1990 19,174 22.9 13.7 43.1 3.4 16.9 1991 19,562 23.3 13.9 42.7 3.1 17.0 1992 20,228 23.2 13.9 43.0 2.9 17.0 1993 20,790 23.8 13.8 42.7 3.0 16.7 1994 21,247 22.8 13.6 42.0 3.2 18.4 1995 22,207 21.8 13.6 42.3 3.2 19.1 1996 22,609 23.2 14.0 42.8 3.2 16.8 1997 22,737 21.9 14.1 42.7 3.3 17.9 1998 22,246 20.3 13.5 42.7 2.9 20.6 1999 22,405 21.1 13.6 40.9 2.9 21.5 2000 23,333 21.4 13.6 39.8 2.8 22.3 2001 22,239 21.5 13.6 38.1 2.9 24.0 2002 23,007 21.2 13.7 37.5 3.0 24.7 2003 22,277 22.8 14.3 37.1 2.7 23.1 2004 22,389 21.7 14.0 37.3 2.6 24.4 2005 22,011 21.9 13.6 35.0 2.8 26.7 2006 21,685 20.1 13.1 35.3 2.8 28.7 2007 23,097 20.4 13.0 34.1 2.8 29.6 2008 23,227 21.0 13.5 33.9 2.9 28.7 2009* 22,834 20.8 13.6 32.4 2.9 30.2 Source: U.S. Energy Information Administration, **Annual Energy Review 2010**  **.** 2009 consumption is preliminary. Totals may not sum due to independent rounding .2 - 24

**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 ye ars , 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 h ave increased by about 2 percent per ye ar on average, whereas petroleum products have increased b y 1 percent on average per year. 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50%

19 90 19 91 19 92 19 93 19 94 19 95 19 96 19 97 19 98 19 99 20 00 20 01 20 02 20 03 20 04 20 05 20 06 20 07 20 08 20 09 ***C o** **n s** **u m** **p t** **i o** **n (** **% o** **f t** **o t** **a l** **)**

Resi den ti al Com merci al Ind ustri al Transportati on Sect or El ectri c Power2 - 25

**Table 2**  **- 11**  **Total Crude Oil and Petroleum Products Imports (Million Bbl), 19 90**  **- 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 steadil y 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 L NG - 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 Egy pt. Until recent years, industry analy sts forecast that L

NG imports would continue to grow as a percentage of U.S consumption. However, it is possible that increasingl y accessible domestic unconventional gas resources, such as shale gas and coalbed methane, might reduce the need for the U.S. to import natural gas, either via pipeline or shipped LNG.2 - 26

**Table 2**  **- 12**  **Natural Gas Imports and Exports, 1990 -**  **2009** Year Total Imports

(bcf) Total Exports

(bcf) Net Imports

(bcf) Percent of

U.S. Consumption 1990 1,532 86 1,447 7.5 1991 1,773 129 1,644 8.4 1992 2,138 216 1,921 9.5 1993 2,350 140 2,210 10.6 1994 2,624 162 2,462 11.6 1995 2,841 154 2,687 12.1 1996 2,937 153 2,784 12.3 1997 2,994 157 2,837 12.5 1998 3,152 159 2,993 13.5 1999 3,586 163 3,422 15.3 2000 3,782 244 3,538 15.2 2001 3,977 373 3,604 16.2 2002 4,015 516 3,499 15.2 2003 3,944 680 3,264 14.7 2004 4,259 854 3,404 15.2 2005 4,341 729 3,612 16.4 2006 4,186 724 3,462 16.0 2007 4,608 822 3,785 16.4 2008 3,984 1,006 2,979 12.8 2009 * 3,748 1,071 2,677 11.7 Source: U.S. Energy Information Administration, **Annual Energy Review 2010**  **.** 2009 Imports are preliminary. **2.4.5 Forecasts**  In this section, we provide forecasts of well drilling activity and crude oil and natural gas domestic production, imports, and prices. The forecasts are from the 201 1 Annual Energy Outlook produced b y EIA, the most current forecast information available from EIA. A s will be discussed in det ail in Section 3, to analy ze the impacts of the final NSPS on the national energy econom y, we use the National Energy Modeling Sy stem (NEMS ) that was used to produce the 2011 Annual Energy

Outlook . Table 2 - 13 and Figure 2 - 6 present forecasts of successful wells drilled in the U.S. from 2010 to 2035. Crude oil well forecasts for the lower 48 states show a rise from 2010 to a peak in 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 success ful offshore crude oil wells shows a variable but generally

increasing trend.2 - 27

**Table 2**  **- 13**  **Forecast of Total Successful Wells Drilled , Lower 48 States**  **, 2010 -**  **2035** Lo wer 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 ty pes of natural gas drilling in the lower 48 states. Drilling in shale reservoirs is expected to rise most dramaticall y, about 190 percent during the forecast period, while drilling in coalbed methane and tight sands reservoirs increase significantly , 61 percent and 13 8 percent, respecti vely . Despite the growth in drilling in unconventional reservoirs, E IA forecasts successful conventional natural 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 the degree of onshore drilling.2 - 28

**Figure 2**  **- 6**  **Forecast of Total Successful Wells Drilled , Lower 48 States**  **, 2010 -**  **2035** Table 2 - 14 presents forecasts of domestic crude oil production, reserves, imports and prices. Domestic crude oil production increases slightly during the forecast period, with much of the growth coming from onshore production in the lower 48 states . Alaskan oil production is forecast to decline from 2010 to a low of 99 million barrels in 2030, but rising above that level for the final five years of the forecast. Net imports of crude oil are forecast t o decline slightl y during the forecast period . Figure 2 - 7 depicts these trends graphicall y. All told, EIA forecasts total crude oil to decrease about 3 percent from 2010 to 2035. 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000

2010 2015 2020 2025 2030 2035**S u** **c c** **e s** **s f** **u l** **W e** **l l** **s**

Cru de Oil Co nventio na l Nat ur alG as Tigh t Sands Devoni an S hal e Co albed Me th

ane2 - 29

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

Domestic Production (million bbls)

Year Total Domestic Lo wer 48

Onshore Lo wer 48

Offshore Alaska Lo wer 48

End of Year Reserves Net

Im ports T otal

Crude Supply (million bb ls) Lo wer 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 rapidl y than production. Table 2 - 14 also2 - 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 from 2010 to 2035. Contrasted against the much higher growth in natural gas wells drilled as shown in Table 2 - 13 , per well productivity is expected to continue its decl ining trend. Meanwhile, imports of natural gas via pipeline are expected to decline during 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. 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

2010 2015 2020 2025 2030 2035**C r** **u d** **e O** **i l** **( M** **i l** **l i** **o n** **b b** **l )** 

To ta l Domesti c Net Im ports Lo wer 48 Onshor

e Lo wer 48 Of fs hore Al aska2 - 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

Im ports (Pipeline) Net

Im ports (LNG) Total

Supply Lo wer 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 significantl y over the past two decades , particularly in recent ye ars . Cost per well has increas ed b y an annual average of about 15 percent , and cost per foot has increased on average of about 13 percent per ye ar ( Figure 2 - 8 ).2 - 32

**Figure 2**  **- 8**  **Costs of Crude Oil and Natural Gas Wells Drilled, 1981**  **- 2008**  The average finding costs compiled and published by EIA add an additional level of detail to drilling costs, in that finding costs incorporate the costs more broadl y 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 - ye ar averages, in order to better compare these costs, which occur over several ye ars, 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 S ys tem (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 ye ars. After this period, offshore finding costs rose faster than domestic onshore and foreign costs.

0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000 4,500,000 5,000,000

1981 1984 1987 1990 1993 1996 1999 2002 2005 2008**D r** **i l** **l i** **n g** **C o** **s t** **s P** **e r** **W e** **l l** **( $** **2 0** **0 5** **)**

0 100 200 300 400 500 600 700 800**D r** **i l** **l i** **n g** **C o** **s t** **s P** **e r** **F o** **o t** **( $** **2 0** **0 5** **)**

Do lla rs per Wel

l (2005 dol

la rs) Do lla

rs per Foot

(2005 dol

la rs)2 - 33

**Figure 2**  **- 9**  **Finding Costs for FRS Companies, 1981 -**  **2008** After 2000, average finding costs rose sharpl y, 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. 0 10 20 30 40 50 60 70 80

19 81 -1 98 3 19

86 -1 98 8 19

91 -1 99 3 19

96 -1 99 8 20

01 -2 00 3 20

06 -2 00 8**$ 2** **0 0** **8 /** **b o** **e**

U. S. O nsho re U. S. O ffsho re Forei gn2 - 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 ro yalties ) for domestic production r ose a little more than $2 per barrels of oil equivalent from 1981 to 1985, then declined almost $5 per barrel of oil equivalent from 1985 until 2000. From 2000 to 2008, domestic lifting costs inc reased sharpl y, about $6 per barrel of oil equivalent . Foreign lifting costs diverged from domestic lifting costs from 1981 to 1991, as foreign lifting costs were lower than domestic costs during this period. Foreign and domestic lifting costs followed a similar track until they again diverged in 2004, with domestic lifting again becoming more expensive. Combined with finding costs, the total finding and lifting costs rose significantly in from 2000 to 2008. **2.5.3 Operating and Equipment Costs**  The EIA report, “ Oil and Gas Lease Equipment and Operating Costs 1994 through 2009 ” 2 , contains indices and estimated costs for domestic oil and natural gas equipment and production operations. The indices and cost trends track costs for representative op erations in

2 U.S. Energy Information Adminis tration. “ Oil and Gas Lease Equipment and Operating Costs 1994 through 2009 .” September 28, 2010. < http://www.eia.doe.go v/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/current/ coststudy.html > Accessed February 2, 2011. 0 2 4 6 8 10 12

19 81 19

84 19

87 19

90 19

93 19

96 19

99 20

02 20

05 20

08**$ 2** **0 0** **8 /** **b o** **e**

Do me sti c Forei gn2 - 35

six regions (California, Mid - Continent, South L ouisiana, 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 steepl y in the late 1970s, but ge nerally 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 ag ain generall y 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, respectivel y. 0 20 40 60 80 100 120 140 160 180 200

1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009CostIndex(1976=100)

0 5 10 15 20 25 30 35 40 45 50OilPrice($/bbl,1976Dollars)

Cr ude Oi l Op erati ng Costs Cr ude Oi l Equ ip me nt Cost In dex Cr ude Oi l Pr ic e ($/bbl , 1976 D ol

la rs)2 - 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 quickl y than equipment costs. Operating and equipment costs and gas prices also rose steepl y in the late 1970s, but generall y decreased from about 1980 until the mid 1990 s. The 20 09 index values for natural gas operating and equipment costs are 137 and 112, respectivel y. **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 entities that have the capacity to conduct business transactions and make business decisions that affect the facility . **2.6.1 Ownership**  Enterprises in the oil and natural gas industry may be divided into di fferent groups that include p roducers, transporters, and distributors. The producer segment may be further divided between major and independent producers. Major producers include large oil and gas companies 0 20 40 60 80 100 120 140 160

1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009CostIndex(1976=100)

0 1 1 2 2 3 3 4 4 5 5NaturalGasPrice($/MMcf,1976Dollars)

Natu ral Gas O perati

ng Costs Natu ral Gas Equ ip ment Costs Natu ral Gas P ri ce ($/ Mcf , 1976 D ol

lars)2 - 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 man y producers. However, now it is of primary importance to many producers. IP AA reports that about 50 percent of its members’ spending in 2007 was directed toward natural gas produ ction, largel y toward production of unconventional gas ( IPAA, 2009 ). Meanwhile, transporters are comprised of the pipeline companies, while distributors are comprised of the local distribution companies. **2.6.2 Size Distribution of Firms in Affected**  As of 2007, there were 6,563 firms within the 211 111 and 211112 NAI CS codes, of which 6427 (98 percent) were considered small businesses ( Table 2 - 16 ). Within NAI CS 2111 11 and 211112 , large firms compose about 2 percent of the firms, but account for 59 percent of employ ment and generate about 80 percent of estimated rec eipts listed under the NAI CS.2 - 38

**Table 2**  **- 16**  **SBA Size Standards and Size Distribution of Oil and Natural Gas Firms** NAICS NAICS Description SBA Size Standard Small

Firms Large Firms Total Firms **Number of Firms by Firm Size**  211111 Crude Petroleum and Natural Gas Extraction 500 6,329 95 6,424 211112 Natural Gas Liquid Extraction 500 98 41 139 213111 Drilling Oil and Gas Wells 500 2,010 49 2,059 486210 Pipeline Transportation of Natural Gas $7.0 million 61* 65* 126 **Total Employment by Firm Size** 211111 Crude Petroleum and Natural Gas Extraction 500 55,622 77,664 133,286 211112 Natural Gas Liquid Extraction 500 1,875 6,648 8,523 213111 Drilling Oil and Gas Wells 500 36,652 69,774 106,426 486210 Pipeline Transportation of Natural Gas $7.0 million N/A* N/A* 24,683 **Estimated Receipts by Firm Size ($1000)** 211111 Crude Petroleum and Natural Gas Extraction 500 44,965,936 149,141,316 194,107,252 211112 Natural Gas Liquid Extraction 500 2,164,328 37,813,413 39,977,741 213111 Drilling Oil and Gas Wells 500 7,297,434 16,550,804 23,848,238 486210 Pipeline Transportation of Natural Gas $7.0 million N/A* N/A* 20,796,681 Note: *The counts of small and large firms in NAICS 486210 is based upon firms with less than $7.5 million in receipts, rather than the $7 million required by the SBA Size Standard. We used this value because U.S. Census reports firm counts for firms with receipts less than $7.5 million. **Employment and receipts could not be split between small and large businesses because of non - disclosure requirements faced by the U.S. Census Bureau. Source: U.S. Census Bureau. 2010. “Number of Firms, Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterprise Receipt Size for the United States, All Industries: 2007.” <http://www.census.gov/econ/susb/> The small and large firms within NAI CS 21311 are similarly distributed, with large firms accounting for about 2 percent of firms, but 66 percent and 69 percent of employ ment and estimated receipts, respectively . Because there are relativel y few firms within NAI CS 486210, the Census Bureau cannot re lease breakdowns of firms by size in sufficient detail to perform similar calculation.2 - 39

**2.6.3 Trends in National Employment and Wages**  As well as producing much of the U.S. energy supply , the oil and natural gas industry directly employ s a significant number of people. Table 2 - 17 shows employ ment in oil and natural gas - related NAICS codes from 1990 to 2009. The overall trend shows a decline in total industry employ ment thro ughout the 1990s, hitting a low of 313,703 in 1999, but rebounding to a 2008 peak of 511,805. Crude Petroleum and Natural Gas Extraction (NAICS 211111) and Support Activities for Oil and Gas Operations (NAI CS 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/>2 - 40

**Figure 2**  **- 13**  **Employment in Drilling of Oil and Natural Gas Wells (NAICS 213111), and**  **Total Oil and Natural Gas Wells Drilled, 1990 -**  **2009** Figure 2 - 13 compares employ ment in Drilling of Oil and Natural Gas Wells (NAI CS 213111) with the total number of oil and natural gas wells drilled from 1990 to 2009. The figure depicts a strong positive correlation between employ ment in the sector with drilling activity . This correlation also holds throughout the period covered b y the data. 0 10, 000 20, 000 30, 000 40, 000 50, 000 60, 000 70, 000 80, 000 90, 000 100, 000

Em pl

oym en t: Drillin g of Oil an d Na tural GasWe lls(

NAI CS 213111)2 - 41

**Figure 2**  **- 14**  **Employment in Crude Petroleum and Natural Gas Extraction (NAICS 211111) and Total Crude Oil and Natural Gas Production (boe), 1990**  **- 2009**  Figure 2 - 14 compares employ ment in Crude Petroleum and Natural Gas Extraction (NAICS 211111) with total domestic oil and natural gas production from 1990 to 2009 in barrels of oil equivalent terms. While until 2003, employ ment in this s ector and total production declined gradually , employ ment levels declined more rapidl y. However, from 2004 to 2009 employ ment in Extraction recovered, rising to levels similar to the earl y 1990s. 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000

19 90 19 91 19 92 19 93 19 94 19 95 19 96 19 97 19 98 19 99 20 00 20 01 20 02 20 03 20 04 20 05 20 06 20 07 20 08 20 09**E m** **p l** **o y** **m e** **n t** 

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000**T o** **t a** **l O** **i l** **a n** **d G** **a s** **P r** **o d** **u c** **t i** **o n** **( b** **o e** **)**

Em pl oy me nt : Cr ud e Petrol eu m an d N atu ral GasE xt ra cti on (N AIC S 211111) To tal Oi l an d Gas Produ

cti on (boe)2 - 42

**Figure 2**  **- 15**  **Employment in Natural Gas Liquid Extraction (NAICS 211112), Employment in Pipeline Transportation of Natural Gas (NAICS 486210), and Total**  **Natural Gas Production, 1990 -**  **2009** Figure 2 - 15 depicts employ ment in Natural Gas Liquid Extraction (NAI CS 211112), Employ ment in Pipeline Transportation of Natural Gas (NAI CS 486210), and Total Natural Gas Production, 1990 - 2009 . While to tal natural gas production has risen slightly over this time period, employ

ment in natural gas pipeline transportation has steadily declined to almost half of its 1991 peak. Employ

ment 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 decreasingl y labor intensive, unlike the trends depicted in Figure 2 - 13 and Figure 2 - 14 . From 1990 to 2009, average wages for the oil and natural gas industry have increased. Table 2 - 18 and Figure 2 - 16 show real wages (in 2008 dollars) from 1990 to 2009 for the NAI CS codes associated with the oil and natural gas industry . 0 10,000 20,000 30,000 40,000 50,000 60,000

19 90 19 91 19 92 19 93 19 94 19 95 19 96 19 97 19 98 19 99 20 00 20 01 20 02 20 03 20 04 20 05 20 06 20 07 20 08 20 09 Em pl oy me nt: Nat ural Gas L iqui d E xt ra ct ion (N AIC S 211112) Em pl oy me nt: Pi pel in e T ran s. of Nat ural Gas (N AIC S 486210) Nat ural Gas Produ

cti on (bcf )2 - 43

**Table 2**  **- 18**  **Oil and Natural Gas Industry Average Wages**  **by NAICS, 1990 -**  **20 09**  **(2008 doll**  **ars)**

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) Pipelin e

Transportation of Natural Gas (486210) Total 1990 71,143 66,751 42,215 45,862 68,044 61,568 59,460 1991 72,430 66,722 43,462 47,261 68,900 65,040 60,901 1992 76,406 68,846 43,510 48,912 74,233 67,120 64,226 1993 77,479 68,915 45,302 50,228 72,929 67,522 64,618 1994 79,176 70,875 44,577 50,158 76,136 68,516 64,941 1995 81,433 67,628 46,243 50,854 78,930 71,965 66,446 1996 84,211 68,896 48,872 52,824 76,841 76,378 68,391 1997 89,876 79,450 52,180 55,600 78,435 82,775 71,813 1998 93,227 89,948 53,051 57,578 79,089 84,176 73,722 1999 98,395 89,451 54,533 59,814 82,564 94,471 79,078 2000 109,744 112,091 60,862 60,594 81,097 130,630 86,818 2001 111,101 111,192 61,833 61,362 83,374 122,386 85,333 2002 109,957 103,653 62,196 59,927 87,500 91,550 82,233 2003 110,593 112,650 61,022 61,282 87,388 91,502 82,557 2004 121,117 118,311 63,021 62,471 93,585 93,684 86,526 2005 127,243 127,716 70,772 67,225 92,074 90,279 90,292 2006 138,150 133,433 74,023 70,266 91,708 98,691 94,925 2007 135,510 132,731 82,010 71,979 96,020 105,441 96,216 2008 144,542 125,126 81,961 74,021 101,772 99,215 99,106 2009 133,575 123,922 80,902 70,277 100,063 100,449 96,298 Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2011 , < http://www.bls.gov/cew/> Employees in the NAICS 211 codes enjo y 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, more than doubling in real terms. However, since 2000 wages have declined in the pipeline transportation sector, while wages have risen in the other NAI CS.2 - 44

**Figure 2**  **- 16**  **Oil and Natural Gas Industry Average Wage 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 integrati on. The vertical aspects of a firm’s size reflect the extent to which goods and services that can be bought from outside are produced in house, while the horizontal aspect of a firm’s size refers to the scale of production in a single - product firm or its scope in a multiproduct one. Vertical integration is a potentially important dimension in anal yz ing firm - level impacts because the regulation could affect a vertically integrated firm on more than one level. The regulation may affect companies for whom o il and natural gas production is only

one of several processes in which the firm is involved. For example, a compan y 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 verticall y 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 wil l ultimately affect the cost of producing final petroleum products. Horizontal integration is also a potentially important dimension in firm - level analy ses for any of the following reasons . A horizontally integrated firm may

own many

facilities of which 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

19 90 19 91 19 92 19 93 19 94 19 95 19 9619 97 19 98 19 99 20 00 20 01 20 02 20 03 20 04 20 05 20 06 20 07 20 08 20 09**A v** **e r** **a g** **e W** **a g** **e (** **2 0** **0 8** **d o** **l l** **a r** **s )** 

Cru de Pe troleu m and Na tural G as E xt ra cti on (211111) Na tural G as L iq ui d Ex traction (211112) Drillin g of

Oil a nd Natural

G as W ells (213111) Suppor t Acti vi ties fo r Oil and Ga s Op s. (213112) Pip elin e Tran s. o f Cru de Oil (486110) Pip elin e Tran s. o f Na tural G as (486210) Total2 - 45

o nly some are directly

affected by

the regulation. Additionally , a horizontally integrated firm may own facilities in unaffected industries. This ty pe of diversification would help mitigate the financial impacts of the regulation. A horizontally integrat ed firm could also be indirectl y as well as directl y affected by the regulation. In addition to the vertical and horizontal integration that exists among the large firms in the industry , man y major producers often diversify within the energy industry and produce a wide array

of products unrelated to oil and gas production. As a result, some of the effects of regulation of oil and gas production can be mitigated if demand for other energy sources moves inversel y compared to petroleum product demand. In the natural gas sector of the industry , vertical integration is less predominant than in the oil sector. Transmission and local distribution of natural gas usually occur at individual firms, although processing is increasing performed by the integrated major companies. Several natural gas firms operate multiple facilities. However, natural gas wells are not exclusive to natural gas firms onl y. Ty pically wells produce both oil and gas and can be owned b y a natural gas firm or an oil company . Unlike the lar ge integrated firms that have several profit centers such as refining, marketing, and transportation, most independents have to rel y onl y on profits generated at the wellhead from the sale of oil and natural gas or the provision of oil and gas production - r elated engineering or financial services. Overall, independent producers ty pically sell their output to refineries or natural gas pipeline companies and are not verticall y integrated. Independents may also own relativel y few facilities, indicating limit ed horizontal integration. **2.6.5 Firm**  **- level Information**  The annual Oil and Gas Journal (OGJ) survey , the OGJ150, reports financial and operating results for top 150 public oil and natural gas companies with domestic reser ves and headquarters in the U.S . In the past, the survey reported information on the top 300 companies, now the top 150. In 2010, only 137 companies are listed 3
. Tabl e 2 - 19 lists selected statistics for

3 Oil and Gas Journal. “ OGJ150 Financial Results Down in '09; Production, Reserves Up .” September 6, 2010.2 - 46

the top 20 companies in 2010. The results presented in the table reflect relatively lower production and financial figures as a result of the economic recession of this period. Total earnings for the top 137 companies fell from 2008 to 2009 from $71 billion to $27 billion, reflecting the weak econom y. Revenues for these companies also fell 35 percent during this period. 69 percent of the firms posted net losses in 2009, compared to 46 percent one year earlier ( Oil and Gas Journal , September 6, 2010). The total worldwide liquids production for the 137 firms declined 0.5 percent to 2.8 billion bbl, while total worldwide gas production increased about 3 percent to a total of 16.5 tcf ( Oil and Gas Journal , September 6, 2010). Meanwhil e, the 137 firms on the OGJ list increased both oil and natural gas production and reserves from 2008 to 2009. Domestic production of liquids increased about 7 percent to 1.1 billion bbl , and natural gas production increased to 10.1 tcf. For context, the OGJ150 domestic crude production represents about 57 percent of total domestic production (1.9 billion bbl, according to EIA). The OGJ 150 natural gas production represents about 54 percent of total domestic production (18.8 tcf, according to EIA). The OG J also releases a period report entitled “Worldwide Gas Processing Survey”, which provides a wide range of information on existing processing facilities. We used a recent list of U.S. gas processing facilities ( Oil and Gas Journal , June 7, 2010) and other resources, such as the American Business Directory and company

websites, to best identify the parent compan y 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 d ay 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 f

acilities. 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 facilitie s, which also tend to be relativel y large facilities ( Table 2 - 20 ). While we estimate 142 companies own the 579 facilities, the top 20 companies (in terms of total throughput) own 264 or 46 percent of the facilities. That larger companies tend to own larger facilities is indicated by these top 20 firms owning 86 percent of the total capacit y and 88 percent of actual throughput.2 - 47

**Tabl e**  **2 -**  **19 Top 20 Oil and Natural Gas Companies**  **(Based on Total Assets) , 2010**  Worldwide Production U.S. Production Rank by Total Assets Com pany Em

ployees 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 Petrohaw

k Energy Corp. 469 6,662 41,084 - 1,025 2 174 2 174 162 Source: Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. Notes: The source for employment figures is the American Business Directory.2 - 48

**Table 2**  **- 20**  **Top 20 Natural Gas Processing Firms (Based on Throughput), 2009**  Rank Com pany 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 TO TAL FOR TOP 20 264 63,163 40,028 TO TAL 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 ompanies, which amounts to 136 companies in 2010 ( Oil and Gas Journal , November 1, 2010) . Table 2 - 21 presents the pipeline mileage, volumes of natural gas transported, operating revenue, and net income for the top 20 U.S. natural gas pipeline companies in 2009. Ownership of gas pipeli nes 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 largel y based upon firm s serving regional market. The top 20 companies maintain about 63 percent of the total pipeline mileage and transport about 54 percent of the volume of the industry ( Table 2 - 21 ) . Operating revenues of the2 - 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 o f the industry . **Table 2**  **- 21**  **Performance of Top 20 Gas Pipeline Companies (Based on Net Income)**  **, 2009** Rank Com pany 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 TO TAL FOR TOP 20 124,903 21,097,914 11,510,401 3,021,774 TO TAL FOR ALL COMPANIES 198,381 38,793,532 18,934,674 4,724,456 Source: Oil and Gas Journal . “Natural Gas Pipelines Continue Grow th 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 S ys te 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 released to the public in aggregate form. While the companies that report information to FRS each year changes, EIA makes an effort to retain sufficie nt consistency such that trends can be evaluated.2 - 50

For 2008, there are 27 companies in the FRS 4 that accounted for 41 percent of total U.S. crude oil and NGL production, 43 percent of natural gas production, 77 percent of U.S. refining capacity , and 0.2 percent of U.S. electricit y 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 remaine d relatively flat during this period. Meanwhile, recent years have shown that other income and income taxes have played a more significant role for the industry . Net income has risen as well, although 2008 saw a decline from previous periods, as oil and natural gas prices declined significantl y during the latter half of 2008. **Table 2**  **- 22**  **Selected Financial Items from**  **Income Statements (Billion 2008 Dollars)** Year Operating

Revenues Operating

Expenses Operating

Income Interest

Expense Other

Income* Income

Taxes Net Income 1990 766.9 706.4 60.5 16.8 13.6 24.8 32.5 1991 673.4 635.7 37.7 14.4 13.4 15.4 21.3 1992 670.2 637.2 33.0 12.7 - 5.6 12.2 2.5 1993 621.4 586.6 34.8 11.0 10.3 12.7 21.5 1994 606.5 565.6 40.9 10.8 6.8 14.4 22.5 1995 640.8 597.5 43.3 11.1 12.9 17.0 28.1 1996 706.8 643.3 63.6 9.1 13.4 26.1 41.8 1997 673.6 613.8 59.9 8.2 13.4 23.9 41.2 1998 614.2 594.1 20.1 9.2 11.0 6.0 15.9 1999 722.9 682.6 40.3 10.9 12.7 13.6 28.6 2000 1,114.3 1,011.8 102.5 12.9 18.4 42.9 65.1 2001 961.8 880.3 81.5 10.8 7.6 33.1 45.2 2002 823.0 776.9 46.2 12.7 7.9 17.2 24.3 2003 966.9 872.9 94.0 10.1 19.5 37.2 66.2 2004 1,188.5 1,051.1 137.4 12.4 20.1 54.2 90.9 2005 1,447.3 1,263.8 183.5 11.6 34.6 77.1 129.3 2006 1,459.0 1,255.0 204.0 12.4 41.2 94.8 138.0 2007 1,475.0 1,297.7 177.3 11.1 47.5 86.3 127.4 2008 1,818.1 1,654.0 164.1 11.4 32.6 98.5 86.9 Source: Energy Information Administration, Form EIA - 28 ( Financial Reporting System). * Other Income includes other revenue and expense (excluding interest expense), discontinued operations, extraordinary items, and accounting changes. Totals may not sum due to independent rounding .

4 Alenco, Anadarko Petroleum Corporation, Apache Corporation, BP America, Inc., Chesapeake Energy Corporation, Chevron Corporation, CITGO Petroleum Corporation, ConocoPhillips, Devon Energy Corporation, El Paso Corporation, EOG Resources, Inc., Equitable Re sources, Inc., Exxon Mobil Corporation, Hess Corporation, Hovensa, Lyondell Chemical Corporation, Marathon Oil Corporation, Motiva Enterprises, L.L.C., Occidental Petroleum Corporation, Shell Oil Company, Sunoco, Inc., Tesoro Petroleum Corporation, The Wil liams Companies, Inc., Total Holdings USA, Inc., Valero Energy Corp., WRB Refining LLC, and XTO Energy, Inc.2 - 51

Table 2 - 23 shows in percentage terms the estimated return on investments for a variety of business lines, in 1998, 2003, and 2008, for FRS companies. For U.S. petroleum - related business activities, oil and natural gas production has remained the most profitable line of business relative to refining/marketing and pipelines, sustaining a return on investment greater than 10 percent for the three ye ars 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 highl y 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 Inve stment 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 local authorizes were $3,060 million in 2008, about 13 percent of the total paid to U.S. authorities.2 - 52

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

Year U . S . Federal, State,

and Local Taxes Paid or Accrued Total Current Total Deferred Total Income Tax Expense Other 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 exceeds domestic taxes paid. Other non - income production taxes p aid , which have risen almost three - fold between 19 90 and 2008, include windfall profit and severance taxes, as well as other production - related taxes.2 - 53

**2.7 References**  Andrews, et al. 2009. Unconventional Gas Shales: Development, Technology , and Policy I ssues . Congressional Research Servic e . R40894 . Argonne National Laboratory . 2009. Produced Water Volumes and Management Practices in the United States. ANL/EVS/R - 09/1 . Hy ne, N.J. 2001. Nontechnical Guide to Petroleum Geology, Exploration, Drilling and Production
. Tulsa, OK: Penwell Books. Independent Petroleum Association of America. 2009. Profile of Independent Producers. <http://www.ipaa.org/news/docs/IPAAProfile2009.pdf > Accessed March 30, 2011. Manning , F.S. and R.E. Thompson. 1991. Oil Field Processing of Petroleum

– Volume 3: Produced and Injection Waters . Tulsa, OK: Penn Well Books. Oil and Gas Journal . “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow.” November 1, 2010. Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. Oil and Gas Journal . “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010. U.S. Energy

Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial Link betwe en 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. 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

Information Administration (U.S. EIA) . 2010. Annual Energy Review (AER). <http://www.eia.doe.gov/emeu/aer/contents.html > U.S. Energy

Information Administration (U.S. EIA). 2010. Oil and Gas Lease Equipment and Operating Costs 1994 through 2009 <http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment

_ production/current/coststudy .html > Accessed March 30, 2011.2 - 54

U.S. 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_publ ications/crude_oil_natural_gas_re serves/cr.html > Accessed March 30, 2011. U.S. Energy

Information Administration (U.S. EIA). 2010. Performance Profiles of Major Energy Producers 2008. <http://www.eia.gov/finance/performanceprofiles > Accessed March 30, 2011 . U.S. Energy

Information Administration (U.S. EIA) . 201 1 . Annual Energy Outlook 2011 . <http://www.eia.gov/forecasts/aeo > June 2 , 2011. U.S. Environmental Protection Agency (U.S. EPA) , Office of Air Quality Planning and Standards. 1996. Economic Analy sis of Air Pollution Regulations: Oil and Natural Gas Production **.** <http://www.epa.gov/ttnecas1/regdata/IPs/Oil%20and%20NG%20Production%20and%2 0NG%20Transmission_IP.pdf > Accessed March 30, 2011. U.S. Environmental Protection Agency (U.S. EPA) . 2004. Impacts to Underground Sources of Drinking Water b y 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 In dustry . EPA/310 - R - 99 - 006. <http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/oil. html > Accessed March 30, 2011.3 - 1 **3 EMISSIONS AND ENGINE**  **ERING COSTS 3.1**  **Introduction** This section include s three sets of discussions for both the final NSPS and NESHAP Amendments :
 Emission Sources and Points

 Emissions Control Options

 Engineering Cost Anal ys is **3.2 Emissions Points, Controls, and**  **Engineering Costs**  **Analysis** This section discusses the emissions points and pollution control options for the final NSPS and NESHAP Amendments . This discussion of emissions points and control options is meant to assist the reader of the RIA in better understanding the economic impact anal ys is. However, we provide reference to the detailed technical memoranda prepared by the Office of Air Quality

Planning and Standards (OAQPS) for the reader interested in a greater level of detail. This section also presents the engineering cost analy sis, which provides a cost basis for the energy s ys tem, employ

ment, and small bu siness analy ses. Before going into detail on emissions points and pollution controls, it is useful to provide estimates of overall emissions from the crude oil and natural gas industry to provide context for estimated reductions as a result of the final ru les . To estimate VOC emissions from the oil and gas sector, we modified the emissions estimate for the crude oil and natural gas sector in the 2008 National Emissions Inventory (NE I). During this review, EPA identified VOC emissions from natural gas sources which are likel y relatively under - represented in the NEI, natural gas well completions primarily . Crude oil and natural gas sector VOC emissions estimated in the 2008 NEI total approximately 1.76 million tons. Of these emissions, the NEI identifies a bout 21 thousand tons emitted from natural gas well completion processes. We substituted the estimates of VOC emissions from natural gas well completions estimated as part of the engineering anal ys is (249 ,000 tons, which is discussed in more detail in the next section) , bringing the total estimated VOC emissions from the crude oil and natural gas sector to about 1.99 million tons VOC.3 - 2

The Inventory

of U.S. Greenhouse Gas Emissions and Sinks: 1990 - 2009 (published April 2011) estimates 2009 methane emissions from Petroleum and Natural Gas Sy stems (not including petroleum refineries and petroleum transportation) to be 251.55 (MMtCO 2 - e). It is important to note that the 2009 emissions estimates from well completions and recompletions exclude a significant numb er of wells completed in tight sand play s and the Marcellus Shale, due to availability

of data when the 2009 Inventory was developed. The estimate in this analy sis includes an adjustment for tight sand play s and the Marcellus Shale, and such an adjustment is also being considered as a planned improvement in next year's Inventory . This adjustment would increase the 2009 Inventory estimate by

about 80 MMtCO 2 - e to approximately 330 MMtCO 2 - e. **3.2.1 Emission Points and Pollution Controls assessed in the RIA**  3.2.1.1 NSPS Emission Points and Pollution Controls A series of emissions controls were evaluated as part of the NSPS review. This section provides a basic description of possible emissions sources and the controls evaluated for each source to facilitate the reader’s understanding of the economic impact and benefit anal ys es. The reader who is interested in more technical detail on the engineering and cost basis of the anal ys is is referred to the relevant chapters within the Technical Support Document (TSD) which is published in the Docket. The chapters are also referenced below. **Centrifugal and r ec**  **iprocating compressors**  (UPDATED REFERENCE TO BE ADDED ) **:** There are man y locations throughout the oil and gas sector where compression of natural gas is required to move the gas along the pipeline. This is accomplished b y compressors powered b y combustion turbines, reciprocating internal combustion engines, or e lectric motors. Turbine powered compressors use a small portion of the natural gas that they compress to fuel the turbine. The turbine operates a centrifugal compressor, which compresses and pumps the natural gas through the pipeline. Sometimes an electric motor is used to turn a centrifugal compressor. This ty pe of compression does not require the use of any of the natural gas from the pipeline, but it does require a source of electricity . Reciprocating spark ignition engines are also used to power many

compressors, referred to as reciprocating compressors, since they compress gas using pistons that are driven by the engine. Like combustion turbines, these engines are fueled by natural gas from the pipeline.3 - 3

Both centrifugal and reciprocating compre ssors 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 co mpressors use oil, which is circulated under high pressure between three rings around the compressor shaft, forming a barrier against the compressed gas leakage. Very little gas escapes through the oil barrier, but considerable gas is absorbed by the oil. Seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated, and the gas is commonly vented to the atmosphere. These are commonly called “wet” seals. An alternative to a wet seal sy stem is the mechanica l dry seal sy stem. This seal sy stem does not use any

circulating seal oil. Dry

seals operate mechanically under the opposing force created b y h ydrodynamic grooves and static pressure. Fugitive VOC is emitted from dry seals around the compressor shaft. T he use of dry gas seals substantially

reduces emissions. In addition, they

significantly

reduce operating costs and enhance compressor efficiency . Reciprocating compressors in the natural gas industry leak natural gas during normal operation. The highest volume of gas loss is associated with piston rod packing s ys tems. Packing s ys tems 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 m ove freely . Monitoring and replacing compressor rod packing s ys tems on a regular basis can greatl y reduce VOC emissions. **Equipment leaks** (UPDATED REFERENCE TO BE ADDED ) **:** Equipment leaks are fugitive emissions emanating from valves, pump seals, flanges, compressor seals, pressure relief valves, open - ended lines, and other process and operation components. There are several potential reasons for equipment leak emissions. Components such as pumps, valves, pressure relief valves, flanges, agitators, and c ompressors are potential sources that can leak due to seal failure. Other sources, such as open - ended lines, and sampling connections may leak for reasons other than faulty

seals. In addition, corrosion of welded connections, flanges, and valves may also be a cause of equipment leak emissions. Because of the large number of valves, pumps, and other components within an oil and gas production, processing, and transmission facility , equipment leak s of volatile emissions from these components can be signifi cant. Natural gas processing3 - 4

plants, especiall y those using refrigerated absorption, and transmission stations tend to have a large number of components. These types of equipment also exist at production sites and gas transmission/compressor stations. While the number of components at individual transmission/compressor stations is relatively smaller than at processing plants, collectively there are man y components that can result in significant emissions. Therefore, EPA evaluated NSPS for equipment leak s for facilities in the production segment of the industry , which includes every thing from the wellhead to the point that the gas enters the processing plant or refinery . **Pneumatic controllers** ( UPDATED REFERENCE TO BE ADDED ): Pneumatic controllers are automated instruments used for maintaining a process condition such as liquid level, pressure, delta - pressure, and temperature. Pneumatic controllers are widely used in the oil and natural gas sector. In man y situations, the pneumatic controllers used in the oil and gas sector make use of the available high - pressure natural gas to regulate temperature, pressure, liquid level, and flow rate across all areas of the industry . In these “gas - driven” pneumatic controllers, natural gas may be released with every valve movement or continuously from the valve control pilot. Not all pneumatic controllers are gas driven. These “non - gas driven” pneumatic controllers use sources of power other than pressurized natural gas. Examples include solar, electric, and instru ment air. At oil and gas locations with electrical service, non gas - driven controllers are typicall y used. Gas - driven pneumatic controllers are typically characterized as “high - bleed” or “low - bleed”, where a high - bleed device releases at least 6 cubic fe et of gas per hour. EPA evaluated the impact of requiring low - bleed controllers. **Storage vessels** ( UPDATED REFERENCE TO BE ADDED ): Crude oil, condensate, and produced water are typically stored in fixed - roof storage vessels. Some vessels used for storin g produced water may

be open - top tanks. These vessels, which are operated at or near atmospheric pressure conditions, are ty pically located at tank batteries. A tank battery refers to the collection of process equipment used to separate, treat, and store crude oil, condensate, natural gas, and produced water. The extracted products from productions wells enter the tank battery through the production header, which may collect product from many wells. Emissions from storage vessels are a result of working , breathing, and flash losses. Working losses occur due to the emptying and filling of storage tanks. Breathing losses are the release of gas3 - 5

associated with dail y temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid with entrained gases is transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing entrained gases or a portion of the liquid to vaporize or flash. In the oil and natural gas production segment, flashing losses occur when live crude oils or condensates flow into a storage tank from a processing vessel operated at a higher pressure. Ty pically , the larger the pressure drop, the more flashing emission will occur in the storage stage. The two way s of controlling tanks with significant emissions would be to install a vapor recovery unit (VRU) and recover all the vapors from the tanks or to route the emissions from the tanks to a control device. **Well completions** (UPDATED REFERENCE TO BE ADDED ): In the oil and natural gas sec tor, well completions contain multi - phase processes with various sources of emissions. One specific emission source during completion activities is the venting of natural gas to the atmosphere during flowback. Flowback emissions are short - term in nature and occur as a specific event during completion of a new well or during activities that involve re - drilling or re fracturing an existing well. Well completions include multiple steps after the well bore hole has reached the target depth. These steps include inserting and cementing - in well casing, perforating the casing at one or more producing horizons, and often hydraulically fracturing one or more zones in the reservoir to stimulate production. Hydraulic fracturing is one completion step for improving gas production where the reservoir rock is fractured with very high pressure fluid, ty

picall y 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 frac ture fluids and reservoir gas at high velocity necessary

to lift excess proppant to the surface. This multi - pha se 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 eventuall y contains more volume of natural gas from the formation. Thus, we estimate c ompletions involving hydraulic fracturing vent substantially more natural gas , approxim ately 23 0 times more, than completions not involving hydraulic fracturing. Specificall y, we estimate that uncontrolled well completion emissions for a hydraulicall y fractured well are about 23 tons3 - 6

of VOC, where emissions for a conventional ga s well co mpletion are around 0.1 ton VOC. Our data indicate that h ydraulically fractured wells have higher emissions but we believe some wells that are not h ydraulically fractured may have higher emissions than our data show , or in some cases, h ydraulicall y 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 an d 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 deh ydration. Equipment costs assoc iated with reduced emission completions will vary from well to well. Based on information provided to the EPA Natural Gas STAR program, 90 percent of gas potentially

vented during a completion can be recovered during a reduced emission completion . 3.2.1.2 NESHAP Emission Points and Pollution Controls A series of emissions controls will be required under the final NESHAP Amendments . This section provides a basic description of potential sources of emissions and the controls intended for each to facilitate the read er’s understanding of the economic impacts and subsequent benefits analy sis section. The reader who is interested in more technical detail on the engineering and cost basis of the anal ys is 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 b y deh ydration. Dehydration is necessary because water vapor may form hydrates, which are ice - like structures, and can cause corrosion in or plug equipment lines. The most widely used natural gas dehydration processes are gl ycol deh ydration and solid desic cant dehydration. Solid desiccant dehydration , which is ty picall y onl y used for lower throughputs,

5 Memorandum. Brow

n, Heather, EC/R Incorporated, to Bruce Moore and Greg Nizich, EPA/OAQPS/SPPD/FIG . Oil and Natural Gas Production MA CT and Natural Gas Transmission and Storage MACT - Glycol Dehydrators: Im pacts of MACT Review Options. July 17,2011 UPDATED REFERENCE TO BE ADDED.3 - 7

uses adsorption to remove water and is not a source of HAP emissions. Glycol deh ydration is an absorption process in which a liquid absorbent, glycol, dire ctl y contacts the natural gas stream and absorbs an y entrained water vapor in a contact tower or absorption column. The rich gl ycol, which has absorbed water vapor from the natural gas stream, leaves the bottom of the absorption column and is directed either to (1) a gas condensate glycol separator (GCG separator or flash tank) and then a reboiler or (2) directly to a reboiler where the water is boiled off of the rich gl ycol. The regenerated gl ycol (lean gl ycol) is circulated, b y pump, into the absorption tower. The vapor generated in the reboiler is directed to the reboiler vent . The reboiler vent is a source of HAP emissions. In the gl yc ol contact tower, glycol not onl y absorbs water but also absorbs selected h ydrocarbons, including BTEX and n - hexane. The h ydrocarbons are boiled off along with the water in the reboiler and vented to the atmosphere or to a control device. The most commonly

used control device is a condenser. Condensers not only reduce emissions, but also recover condensable h ydrocar bon vapors that can be recovered and sold. In addition, the dry

non - condensable off

- gas from the condenser may be used as fuel or recycled into the production process or directed to a flare, incinerator, or other combustion device. If present, the GCG separator (flash tank) is also a potential source of HAP emissions. Some gl ycol deh ydration units use flash tanks prior to the reboiler to separate entrained gases, primarily methane and ethane from the gl yc ol. The flash tank off - gases are ty

picall y recove red as fuel or recycled to the natural gas production header. However, the flash tank may also be vented directl y to the atmosphere. Flash tanks typically enhance the reboiler condenser’s emission reduction efficiency by reducing the concentration of non - condensable gases present in the stream prior to being introduced into the condenser. **Storage vessels :**  Please see the discussion of storage vessels in the NSPS section above. **3.2.2 Engineering Cost Analysis**  In this section, w e provide an overview of the engineering cost anal ys is used to estimate the additional private expenditures industry may make in order to comply with the final NSPS and NESHAP Amendments . A detailed discussion of the methodology used to estimate cost impa cts is presented in series of memos published in the Docket as part of the TSD.3 - 8

3.2.2.1 NSPS Sources Table 3 - 1 shows the emissions sources, points, and controls anal yz ed f or the final rule. The final NSPS contains reduced emission completion (REC) and completion combustion requirements for a subset of newl y drilled natural gas wells that are h ydraulically fractured. The NSPS also requires a subset of wells that are rec ompleted using hydraulic fracturing to implement RECs. The NSPS requires emissions reductions from reciprocating compressors at gathering and boosting stations and processing plants . The NSPS also requires emissions reductions from centrifugal compressors at processing plants . Finall y, the NSPS requires emissions reductions from pneumatic controllers at oil and gas production facilities and reductions from high throughput storage vessels.3 - 9

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

Emissions Sources and Point s Emissions Control Final NSPS **Well Completions of Post -**  **NSPS Wells** Hydraulically Fractured Gas Wells that Meet Criteria for Reduced Emissions Completion (REC) REC **X** Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC Com bustion **X** Conventional Gas Wells Com bustion Oil Wells Com bustion **Well Recompletions** Hydraulically Fractured Gas Wells (post -NSPS wells) REC **X** Hydraulically Fractured Gas Wells (pre -NSPS wells) REC **X** Conventional Gas Wells Com bustion Oil Wells Com bustion **Equipment Leaks** Well Pads NSPS Subpart VV Gathering and Boosting Stations NSPS Subpart VV Processing Plants NSPS Subpart VVa **X** Transmission Com

pressor Stations NSPS Subpart VV **Reciprocating Com pressors**  Well Pads Annual Monitoring/ Maintenance (AMM) Gathering/Boosting Stations AMM **X** Processing Plants AMM **X** Transmission Compressor Stations AMM Underground Storage Facilities AMM **Centrifugal Com pressors**  Processing Plants Dry Seals/Route to Process or Control **X** Transmission Compressor Stations Dry Seals/Route to Process or Control **Pneumatic Controllers -**  Oil and Gas Production Lo w Bleed/Route to Process **X** Natural Gas Transmission and Storage Lo w Bleed/Route to Process **Storage Vessels** High Throughput 95% control **X** Lo w Throughput 95% control Table 3 - 2 summarizes the unit level capital and annualized costs for the evaluated NSPS emissions sources and points. The detailed description of costs estimates is provided in the3 - 10

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 additional natural gas and hydrocarbon condensate s that would otherwise be emitted to the environment are recovered from several control options evaluated in the NSPS review. First, engineering capital costs were annualized using a 7 percent interest rate. However, different emissions control options were annualized using expected lifetimes that were determined to be most appropriate for individual options. For control options evaluated for the NSPS, the following lifetimes were used:

 Reduced emissions completions and combustion devices: 1 year (more discussion of the selection of a one - ye ar lifetime follows in this section momentarily)  Reciprocating compressors: 3 years  Centrifugal compress ors and pneumatic controllers: 10 years  Storage vessels: 15 years  Equipment leaks: 5 to 10 years , depending on specific control To estimate total annualized engineering compliance costs, we added the annualized costs of each item wi thout accounting for different expected lifetimes. This approach is mathematically

equivalent to establish ing an overall, representative project time horizon and annualiz ing costs after consideration of control options that would need to be replaced periodicall y within the given time horizon. For example, a 15 ye ar project would require replacing reciprocati ng compressor - related controls five times, but only require a single installation of controls on storage vessels. Second , the projected number of affected units is the number of units that our anal ys is shows would be affected in 2015, the anal ys is year. The projected number of affected units accounts for estimates of the adoption of controls in absence of Federal regulation. While the procedures used to estimate adoption in absence of Federal regulation are presented in detail within the TSD, because REC requirements provide a significant component of the estimated3 - 11

emissions reductions and engineering compliance costs, it is worthwhile to go into some detail on the projected number of RECs within the RIA. We use EIA projections consistent with the Annual Energy

Outlook 2011 to estimate the number of natural gas well completions with hydraulic fracturing in 2015, assuming that successful wells drilled in coal bed methane, shale, and tight sands used h ydraulic fracturing . Based on this assumption , we estimate that 11,403 wells were successfully

completed and used hydraulic fracturing. To approximate the number of wells that would not be required to perform RECs because of the absence of sufficient infrastructure, we draw upon the distin ction in EIA anal ys is between exploratory and developmental wells . We assume exploratory wells do not have sufficient access to infrastructure to perform a REC and are exempt from the REC requirement. These 446 wells are removed from the REC estimate and are assumed to combust emissions using pit flares. The number of h ydraulically fractured recompletions of existing wells was approximated using assumptions found in Subpart W’s TSD 6 and applied to well count data found in the proprietary HPDI ® database . The underl yi ng assumption is that wells found in coal bed methane, shale, and tight sand formations require re - fracture, on average, every 10 years. In other words, one percent of the total wells classified as being performed with hydraulic fracturing would perform a recompletion in an y gi ven year. Natural g as w ell recompletion s performed without hydraulic fracturing were based only on 2008 well data from HPDI ®

. The number of completions and recompletions already controlling emissions in absenc e 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 this criterion, 1 5 percent 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 without 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 1 ,205 recompletions of existing wells that will require a REC under the final NSPS in 2015 . However,

6 U.S. Environmental Protection Agency (U.S. EPA) . 2010. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Background Technical Support Document. Climate Change Divisio n. Washington, DC .3 - 12

because the pressure level for some wells may be insufficient to successfully perform an REC, these wells will be required to combust emissions, rather than implement an REC. EPA analy sis shows about 10 percent of the wells that otherwise would be required b y the NSPS to perform an REC will combust emissions. In summary , we expect 8,382 completions of new wells and 1,085 recompletions of existing wells will ultimately require a REC, after consideration of state regulations and pressure levels. As just mentioned, the baseline for the impacts analy sis of our NSPS for natural gas well completions takes into account reduced emission completions conducted pursuant to state regulations covering these operations. However, based on public comments an d reports to EPA's Natural Gas Star program, EPA acknowledges that some producers conduct well completions using REC techniques voluntarily . However, EPA normally does not account for voluntary actions in baseline emissions estimates when we analyze potential impacts of our regulatory actions, since there is no assurance that such voluntary emission reduction measures will continue in the future. As such, emissions reductions obtained from RECs implemented voluntarily

are not reflected in our baseline emi ssions estimates. It also should be noted that natural gas prices are stochastic and, historically , there have been periods where prices have increased or decreased rapidl y. These price changes would be expected to affect adoption of emission reduction technologies in absence of regulation, particularl y control measures such as RECs that capture emission significantly over short periods of time. T he completion requirements (combustion and RECs) are essentially one - shot events; the emissions controls are applied over the course of a well completion, which will ty picall y range over a few day s 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 ye ars later . Consequently , we counted these requirements as as recurring costs , implicitly treating the number of completions taking place in 2015 as representative of a ty pical year. Fourth , for annualized cost, we present two figures, th e annualized costs with revenues from additional natural gas and condensate recovery and annualized costs without additional3 - 13

revenues this product recovery . Several emission controls for the NSPS capture VOC emissions that otherwise would be vented to the atmosphere. Since methane is co - emitted with VOC , a large proportion of the averted methane emissions can be directed into natural gas production streams and sold. When including the additional natural gas recovery in the cost anal ys is, we assume that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the wellhead. RECs also capture saleable condensates that would otherwise be lost to the environment. The engineering analy sis assumes a REC will capture 34 barrels of condens ate per REC and that the value of this condensate is $70/barrel. The $4/Mcf is below the 2015 EIA
- forecasted wellhead price , $4.22 /Mcf in 2008 dollars. The $4/Mcf pay

ment rate does not reflect any taxes or tax credits that might apply to producers implem enting the control technologies. As natural gas prices can increase or decrease rapidl y, the estimated engineering compliance costs can vary when revenue from additional natural gas recovery is included. There is also geographic variability in wellhead p rices, which can also influence estimated engineering costs. A $1/Mcf change in the wellhead price causes a change in estimated engineerin g compliance costs of about $82 million in 2008 dollars. As will be seen in subsequent anal ys is, the estimate of re venues from additional product recovery is critical to the economic impact analy sis. However, before discussing this assumption in more depth, it is important to further develop the engineering estimates to contextualize the discussion and to provide insi ght into why , if it is profitable to capture natural gas emissions that are otherwise vented, producers may not already

be doing so. Table 3 - 3 present s the estimated nationwide compliance costs, emissions reductions, and VOC r eduction cost - effectiveness broken down by emissions sources and points for those sources and points evaluat ed in the NSPS analy sis. The annual reporting and recordkeeping costs for the final NSPS are estimated at $7 .1 million per year and are included in Table 3 - 3 . As can be seen from Table 3 - 3 controls associated with well completions and recompl etions of h ydraulically fractured wells provide the largest potential for emissions reductions from evaluated emissions sources and points, as well as present the most significant compliance costs if revenue from additional natural gas recovery is not included. Emissions reductions from conventional natural gas wells and crude oil wells are clearly not as significant as the potential from h ydraulicall y fractured wells, as was discussed in Section 3.2.1.1.3 - 14

Several evaluated emissions sources and points are estimated to have net financial savings when including the revenue from additional natural gas recovery . Table 3 - 4 presents the estimated engineering costs, emiss ions reductions, and VOC reduction cost - effectiveness for the final NSPS evaluated in the RIA. The resulting total national annualized cost impact of the final NSPS rule is estimated at $3 4 0 m illion per year without considering revenues from additional natural gas recovery . Annual costs for the final NSPS are estimated at - $18 million when revenue from additional natural gas recovery is included. All figures are in 2008 dollars.3 - 15

**Table 3**  **- 2**  **Summary of**  **Capital and 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$)**  **Without**

**Revenues from Additional**  **Product Recovery**  **With**

**Revenues from Additional**  **Product Recovery**  **Well Completions** Hydraulically Fractured Gas Wells that Meet Criteria for REC 8,382 $33,237 $33,237
- $1,543 Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Com pletion Combustion) 1,498 $3,523 $3,523 $3,523 Conventional Gas Wells 7,694 $3,523 $3,523 $3,523 Oil Wells 12,193 $3,523 $3,523 $3,523 **Well Recompletions** Hydraulically Fractured Gas Wells (existing wells) 1,085 $33,237 $33,237
- $1,543 Conventional Gas Wells 42,342 $3,523 $3,523 $3,523 Oil Wells 39,375 $3,523 $3,523 $3,523 **Equipment Leaks** Well Pads 4,774 $68,970 $23,413 $21,871 Gathering and Boosting Stations 275 $239,494 $57,063 $51,174 Processing Plants 29 $8,041 $12,273 $8,474 Transmission Compressor Stations 107 $96,542 $25,350 $25,350 **Reciprocating Com pressors**  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 Com pressors**  Processing Plants 13 $22,000 $3,132
- $50,106 Transmission Compressor Stations 14 $75,000 $10,678
- $77,622 **Pneumatic Controllers -**  Oil and Gas Production 13,632 $165 $23
- $1,519 Natural Gas Trans. and Storage 67 $165 $23 $23 **Storage Vessels** High Throughput 304 $65,243 $19,864 $19,281 Lo w Throughput 17,086 $65,243 $19,864 $19,2813 - 16

**Table 3**  **- 3**  **Estimated Nationwide Compliance Costs, Emissions Reductions, and**  **VOC Reduction Cost**  **- Effectiveness by**  **Emissions Sources and Points, NSPS , 2015** 

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

**Reductions (tons/year)**  **VOC Emissions Reduction Cost**  **- Effectiveness**  **(2008$/ton) Without**  **Addl. Revenues**  **With Addl.**

**Revenues VOC**  **Me thane**  **HAP Without**  **Addl. Revenues**  **With Addl.**

**Revenues Well Completions (New Wells)**  Hydraulically Fractured Gas Wells REC $278,598,165
- $12,931,447 180,217 1,235,207 13,093 $1,546
- $72 Hydraulically Fractured Gas Wells Com bustion $5,276,674 $5,276,674 32,204 220,726 2,340 $164 $164 Conventional Gas Wells Com bustion $27,104,761 $27,104,761 857 5,875 62 $31,619 $31,619 Oil Wells Com bustion $42,954,036 $42,954,036 83 88 0 $520,580 $520,580 **Well Recompletions (Existing Wells)** Hydraulically Fractured Gas Wells (existing wells) REC $36,045,804
- $1,673,106 23,317 159,815 1,694 $1,546
- $72 Conventional Gas Wells Com bustion $149,164,257 $149,164,257 316 2,165 23 $472,227 $472,227 Oil Wells Com bustion $138,711,979 $138,711,979 44 47 0 $3,134,431 $3,134,431 **Equipment Leaks** Well Pads NSPS Subpart VV $111,773,662 $104,412,154 10,646 38,287 401 $10,499 $9,808 Gathering and Boosting Stations NSPS Subpart VV $15,692,325 $14,072,850 2,340 8,415 88 $6,705 $6,013 Processing Plants NSPS Subpart VVa $355,917 $245,746 132 475 5 $2,693 $1,860 Transmission Compressor Stations NSPS Subpart VV $2,712,450 $2,712,450 261 9,427 8 $10,389 $10,389 **Reciprocating Com pressors**  Well Pads Annual Monitoring/ Maintenance (AMM) $22,204,209 $21,984,763 263 947 10 $84,379 $83,545 Gathering/Boosting Stations AMM $515,764 $182,597 400 1,437 15 $1,291 $457 Processing Plants AMM $436,806
- $465,354 1,082 3,892 41 $404
- $430 Transmission Compressor Stations AMM $49,120 $49,120 12 434 0 $4,093 $4,093 Underground Storage Facilities AMM $13,396 $13,396 2 87 0 $5,542 $5,5423 - 17

**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 Em issions** 

**Reductions (tons/year)**  **VOC Emissions Reduction Cost**  **- Effectiveness**  **(2008$/ton) Without**  **Addl. Revenues**  **With Addl.**

**Revenues VOC**  **Me thane**  **HAP Without**  **Addl. Revenues**  **With Addl.**

**Revenues Centrifugal Com** **pressors** Processing Plants Dry Seals/Route to Process or Control $40,720
- $651,377 254 2,810 9 $161
- $2,569 Transmission Compressor Stations Dry Seals/Route to Process or Control $149,496
- $1,086,704 43 1,546 1 $3,495
- $25,405 **Pneumatic Controllers -**  Oil and Gas Production Lo w Bleed/Route to Process $320,071
- $20,699,918 25,210 90,685 952 $13
- $821 Natural Gas Trans. and Storage Lo w Bleed/Route to Process $1,541 $1,541 6 212 0 $262 $262 **Storage Vessels** High Throughput 95% control $6,031,787 $5,855,032 29,654 6,490 876 $203 $197 Lo w Throughput 95% control $339,388,204 $329,442,792 12,900 2,824 381 $26,308 $25,5373 - 18

**Table 3**  **- 4**  **Engineering Compliance Costs, NSPS (2008$) Final NSPS**  Capital Costs $ 344,724,611 Annualized Costs Without Revenues from Additional Natural Gas Product Recovery $ 334,927,549 With Revenues from Additional Natural Gas Product Recovery - $ 17, 607,568 VOC Reductions (tons per year) 292,532 Methane Reduction (tons per year) 1,721,763 HAP Reductions (tons per year) 19,028 VOC Reduction Cost - Effectiveness ($/ton without additional product revenues) $1,14 4 VOC Reduction Cost - Effectiveness ($/ton with additional product revenues) - $ 60 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 rapidly, the estimated engineering compliance costs can vary when revenue from additional product recovery is included. There is also geographic variability in wellhead prices, which can also influence estimated engineering costs. A $1/Mcf change in the wellhe ad price causes a change in estimated engineerin g compliance costs of about $82 mi llion in 2008 dollars. The annualized cost estimates also include s reporting and recordkeeping costs of $7.1 million . As the price assumption is very influential on estimat ed impacts, we performed a simple sensitivity

anal ys is of the influence of the assumed wellhead price paid to natural gas producers on the overall engineering costs estimate of the final NSPS. Figure 3 - 1 plots the annualized costs after revenues from natural gas product recovery have been incorporated (in millions of 2008 dollars) as a function of the assumed price of natural gas paid to producers at the wellhead for the recovered natural gas (represented b y 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 Outlo ok ($4.22 /Mcf) in 2008 dollars .3 - 19

**Figure 3**  **- 1**  **S ensitivity**  **Analysis of Final**  **NSPS Annualized Costs after Revenues from**  **Additional Product Recovery are Included** 
As shown in Table 3 - 4 , at the assumed $4/Mcf, the annualized costs are esti mated at - $1 8 million. At $4.22 /Mcf, the price forecast reported in the 2011 Annual Energy Outlook, the annual ized costs are estimated at about - $36 million , which would approximately double the estimate of net cost savings of the final NSPS . As indicated b y this difference, EPA has chosen a relativel y conservative assumption (leading to an estimate of few savings and higher net costs) for the engineering costs anal ys is. The natural gas price at which the final NSPS breaks - even is around $3.79 /Mcf. As menti oned earlier, a $1/Mcf change in the wellhead natural gas price leads to about a $82 million change in the annualized engineering costs of the final NSPS. Consequent l y, annualized engineering costs estimates would increase to about $65 million under a $3/Mcf price or decrease to about - $100 million under a $5/Mcf price. It is additi onall y helpful to put the quantity of natural gas and condensate potentially recovered in the context of domestic production levels. To do so, it is necessary to make two adjustments. First, not all emissions reductions can be directed into production streams to be

$( 300) $(200) $( 100) $
- $100 $200

$
- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 **Annual ized**  **C os**  **ts aft**  **er Pr** **oduc t**  **Re co**  **ve ry**  **($ M**  **illio ns**  **)** NaturalG as Pri ce ($ /Mcf) in2 015

RIA Assume d

Pri ce in 2015 ($ 4.00/ Mcf ) EIA Fore ca st

Pric e in 2015 ($ 4.22/ Mc f) Annual ized Costs as Functi on of Natural Gas Pri ce Assum ptio n3 - 20

ultimately

consumed b y 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 - ty pe controls, the final NSPS is estimated to capture about 82 bcf of natural gas and 320,000 barrels of condensate . E stimates of unit - level and nation - level product rec overy are presented in Section 3 of the RIA . Note that completion - related requirements for new and existing wells generate all the condensate recovery for the NSPS . For natural gas recovery , RECs contribute about 77 bcf ( or 93 percent).3 - 21

**Table 3**  **- 5**  **Estimates of Control Unit -**  **level and National Level Natural Ga s and Condensate Recovery, NSPS**  **, 2015 Projected No.**  **of Affected Units**  **Unit -**  **level Product Recovery Total Product Recovery**  **Source/ Emissions Points**  **Emissions Control Natural Gas**  **Savings (M**  **cf/unit) Condensate** 

**(bbl/unit) Natural Gas** 

**Savings (Mcf) Condensate** 

**(bbl) Well Completions**  Hydraulically Fractured Gas Wells REC 8,382 8,100 34 67,895,051 284,992 Hydraulically Fractured Gas Wells Com bustion 1,498 0 0 0 0 Hydraulically Fractured Gas Wells (existing wells) REC 1,085 8,100 34 8,784,450 36,873 **Equipment Leaks** Processing Plants NSPS Subpart VVa 29 950 0 27,548 0 **Reciprocating Com pressors**  Gathering/Boosting Stations Annual Monitoring/ Maintenance (AMM) 210 397 0 83,370 0 Processing Plants AMM 209 1,079 0 225,540 0 **Centrifugal Com pressors**  Processing Plants Dry Seals/Route to Process or Ctrl 13 11,527 0 149,853 0 **Pneumatic Controllers -**  Oil and Gas Production Lo w Bleed/Route to Process 13,632 386 0 5,254,997 0 Processing Plants Instrument Air 15 871 0 13,064 0 **Storage Vessels** High Throughput 95% control 304 146 0 44,189 0 **Total (Mcf) 82,478,062**  **321,865**3 - 22

A second adjustment to the natural gas quantities is necessary to account for nonhydrocarbon gases removed and gas that reinjected to repressurize wells, vented or flared, or consumed in production processes. Generall y, wellhead production is metered at or near the wellhead and pay

ments 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 pro cessed out of the natural gas at processing plants. This means that the engineering cost estimates of revenues from additional natural gas recovery arising from controls implemented at the wellhead include pay ment for the impurities, such as the VOC and HAP content of the unprocessed natural gas. According to EIA, in 2009 the gross withdrawal of natural gas totaled 26,013 bcf, but 20,580 bcf was ultimately considered dry

production (these figures exclude EIA estimates of flared and vented natural gas). U sing these numbers, we appl y a factor of 0.79 (20,580 bcf divided b y 26,013 bcf) to the adjusted sums in the previous paragraph to estimate the volume of gas that is captured by controls that may

ultimatel y b e consumed b y final consumers. After making th ese adjustments, we estimate that the final NSPS will potentially recover about 65 bcf of natural gas that will ultimately be consumed by

natural gas consumers. 7 EIA forecasts that the domestic dry natural gas production in 2015 will be 20,080 bcf. Conse quentl y, the final NSPS may

recover production representing about 0. 3 percent of domestic dry natural gas production predicted in 2015 . These estimates, however, do not account for adjustments producers might make, once compliance costs and potential revenues from additio nal natural gas recovery factor into economic decision - making . Also, as discussed in the previous paragraph, these estimates do not include the nonhydrocarbon gases removed, natural gas reinjected to repressurize wells, and natural gas co nsumed in production processes, and therefore will be lower than the estimates of the gross natural gas captured b y implementing controls. Clearly , this discussion raises the question as to why , if emissions can be reduced profitably using environmental co ntrols, more producers are not adopting the controls in their own economic self

- interest. This question is made clear when examining simple estimates of the rate of return to installing emissions controls that, using the engineering compliance costs

7 To convert U.S. short tons of methane to a cubic foot measure, we use the conversion factor of 48.04 Mcf per U.S. short ton.3 - 23

estim ates, the estimates of natural gas product recovery , and assumed product prices ( Table 3 - 6 ). The rates of return presented in are for evaluated controls where estimated revenues from additional product recovery exceed the costs. The rate of return is calculated using the simple formula : 

### estimated revenues rate of return 1 1 00

estimated costs          . **Table 3**  **- 6**  **Simple Rate of Return Estimate for Final**  **NSPS Control**  **s Emission Point**  **Control Option Rate of Return**  New Completions of Hydraulically Fractured Wells Reduced Emissions Completions 4.6% Re - com pletions of Existing Hydraulically Fractured Wells Reduced Emissions Completions 4.6% Reciprocating Compressors (Processing Plants) Replace Packing 106.5% Centrifigal Compressors (Processing Plants) Dry Seals/Route to Control 1,599.7% Pneumatic Controllers (Oil and Gas Production ) Low Bleed /Route to Process 6,467.2% **Overall NSPS Low** **Bleed 5.4**  **%** Note: The table presents only control options where estimated revenues from natural gas product recovery exceeds estimated annualized engineering c osts Recall from Table 2 - 23 in the Industry Profile, th at EIA estimates an industry- level rate of return on investments for various segments of the oil and natural gas industry . While the numbers varies greatl y over time because of industry and economic factors, EIA estimates a 10.7 percent rate of return on investments for oil and natural gas production in 2008. While th is amount is higher than the 4.6 percent rate estimated for RECs, it is significantly lower than the rate of returns estimated for other controls anticipated to have net savings. Assuming financially

rational producers, standard economic theory suggests that all oil and natural gas firms would incorporate all cost - effective improvement s, which they are aware of, without government intervention. The cost analy sis of this RIA nevertheless is based on the observation that emission reductions that appear to be profitable in our analy sis have not been generall y adopted. One possible explanation may be the difference between the average profit margin garnered b y productive capital and the enviro nmental capital where the primary3 - 24

motivation for installing environmental capital would be to mitigate the emission of pollutants and confer social benefits as discussed in Chapter 4. Another explanation for why there appear to be negative cost control t echnologies that are not generall y adopted is imperfect information. If emissions from the oil and natural gas sector are not well understood, firms may underestimate the potential financial returns to capturing emissions. Quantifying emissions is diffic ult and has been done in relatively few studies. Recently , however, advances in infrared imagery have made it possible to affordabl y visualize, if not quantify , methane emissions from any source using a handheld camera. This infrared camera has increased awareness within industry and among environmental groups and the public at large about the large number of emissions sources and possible scale of emissions from oil and natural gas production activities. Since, as discussed in the TSD chapter (UPDATED REFERENCE TO BE ADDED ) referenced above, 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 estimated to be controlled by either flare or REC in th e baseline, it is unlikely that a lack of information will be a significant reason for these emission points to not be addressed in the absence of Federal regulation in 2015. However, for other emission points, a lack of information, or the cost associate d with doing a feasibility study of potential emission capture technologies, may continue to prevent firms from adopting these improvements in the absence of regulation. Another explanation is the cost associated with irreversibility associated with implem enting these environmental controls are not reflected in the engineering cost estimates above. Due to the high volatility of natural gas prices, it is important to recognize the value of flexibility taken away

from firms when requiring them to install and use a particular emissions capture technology . If a firm has not adopted the technology on its own, then a regulation mandating its use means the firm loses the option to postpone investment in the technology in order to pursue alternative investments to day , and the option to suspend use of the technology if it becomes unprofitable in the future. Therefore, the full cost of the regulation to the firm is the engineering cost and the lost option value minus the revenues from the sale of the additional reco vered 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 this3 - 25

RIA may underestimate the full costs faced by the affected firms. With these caveats in mind, EPA believes it is analy

tically appropriate to anal yze costs and economic impacts costs presented in Table 3 - 2 and Table 3 - 3 using the additional product recovery and associated revenues. 3.2.2.2 NESHAP Sources As discussed in Section 3.2.1.2 , EPA examined three emissions points as part of its anal ys is for the final NESHAP Amendments . Unlike the controls for the final NSPS, the controls evaluated under the final NESHAP Amendments do not direct significant quantities of natural gas that would otherwise be flared or vented into the production stream. Table 3 - 7 shows the projected number of controls required, estimated unit - level capital and annualized costs, and estimated total annualized costs. The table also shows estimated emissions reductions for HAP , VOC , and methane, as well as a cost - effectiveness estimate for HAP reduction, based upon annualized engineering costs.3 - 26

**Table 3**  **- 7**  **Summary of Estimated**  **Capital and Annual Co sts, Emissions Reductions,**  **and HAP Reduction Cost -**  **Effectiveness for Final**  **NESHAP Amendments**

**Source/Emissions Point**  **Projected**

**No. of Controls**  **Required Em** **ission 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 74 35,518 22,396 1,657,300 505 915 316 3,284 Transmission - Small Glycol Dehydrators 7 19,399 18,957 132,700 164 298 103 808 Storage Vessels 674 65,243 19,864 13,388,039 589 7,812 4,364 22,722 Reporting and Recordkeeping N/A N/A N/A 2,368,627 N/A N/A N/A N/A **Total 755**  **17,546,667 1,258**  **9,024 4,783**  **13,945** Note: Totals may not sum due to independent rounding . Under the final NESHAP Amendments , about 750 controls will be required, costing a total of $18 million annually ( Table 3 - 7 ). We include reporting and recordkeeping costs as a unique line item showing these costs for the entire set of final amendments. These controls will r educe HAP emissions by

about 1,300 tons, VOC emissions by about 9,000 tons, and methane by about 4,800 tons. The cost - per - ton to reduce HAP emissions is estimated at about $14,000 per ton. All figures are in 2008 dollars. **3.3 References**  Oil and Gas Journal . “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow.” November 1, 2010. Oil and Gas Journal . “OGJ150.” September 21, 2009. Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Productio n, Reserves Up.” September 6, 2010. Oil and Gas Journal . “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010.4 - 1 **4 BENEFITS OF EMISSION**  **S REDUCTIONS 4.1**  **Introduction** The final Oil and Natural Gas NSPS and NESHAP Amendments are expected to result in significant reductions in existing emissions and prevent new emissions from expansions of the industry . While we expect that these avoided emissions will result in improvements in air quality and reduce health effects associated with exposure to HAP, ozone, and fine particulate matter (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 th at there are no health benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. For the final NSPS, the HAP and climate benefits can be considered “co - benefits”, and for the final NESHAP Amendments , the ozone and 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 HAP and methane. The final NSPS is anticipated to prevent 19,000 tons of HAP , 290,000 tons of VOC , and 1.7 million tons of methane from new sources, while the final NESHAP Amendments is anticipated reduce 1,300 tons of HAP , 9,000 tons of VOC , and 4,800 tons of methane from existing sources The specific control technologies for the final NSPS are anticipated to have minor secondary

disbenefits, including an increase of 1.1 million tons of carbon dioxide (CO 2 ), 630 tons of nitrogen oxides NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy s ys tem impacts. Both rules would have additional emission changes associated with the energy s ys tem impacts. The net CO 2 - equivalent emission reductions are 31 million metric tons for the final NSPS and 90,000 metric tons for the final NESHAP. As described in the subsequent sections, these pollutants are associated with substantial health effects, welfare effects, and climate effects. With the data available, we are not able to provide a credible benefits estimates for any of th ese 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 agreed4 - 2

upon valuation estimates 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 anal ys is in Chapter 6 of this RIA. A break - even anal ys is 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 anal ys is, we feel the results are illustrative, particularly in the context of previous benefit per ton estimates. **4.2 Direct**  **Em ission Reductions from the Oil and Natural Gas**  **Rules** As described in Section 2 of this RIA, oil and natural gas operations in the U.S. include a variety of emission points for VOC and HAP including wells, processing plants, compressor stations, storage equipment, and transmission and distribution lines. These emission poi nts are located throughout much of the country with significant concentrations in particular regions. For example, wells and processing plants are largel y concentrated in the South Central, Midwest, and Southern California regions of the U.S., whereas gas compression stations are located all over the country . Distribution lines to customers are frequently located within areas of high population density . In implementing these rules, emission controls may lead to reductions in ambient PM 2.5 and ozone belo w 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 determ ine how these rules might affect attainment status without air quality modeling data. 8 Because the NAAQS RIAs also calculate ozone and PM benefits, there are important differences worth noting in the design and anal yt ical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs h ypothesize, but do not predict, the control strategies that S tates may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits
8 The responsiveness of ozone and PM 2.5 formation is discussed in greater detail in sections 4.4.1 and 4.5.1 of this RIA.4 - 3

of other regulations that result in specific costs of control and emission reductions. However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in an illustrative NAAQS RIA. By contrast, the emission reductions for this rule are from a specific class of 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 r esult in emission increases elsewhere (other than potential energy disbenefits). Emission reductions achieved under these and other promulgated rules will ultimately

be reflected in the baseline of future NAAQS anal ys es, which would reduce the incremental costs and benefits associated with attaining the NAAQS. EPA remains forward looking towards the next iteration of the 5 - ye ar review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline f or NAAQS implementation. For more information on the relationship between the NAAQS and rules such as anal yz ed here, please see Section 1.2.4 of the SO 2 NAAQS RIA (U.S. EPA, 2010d). Table 4 - 1 shows the direct emission reductions anti cipated for these rules . It is important to note that these benefits accrue at different spatial scales. HAP emission reductions reduce exposure t o 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 Em**  **ission Reductions Associated with the Oil and Natural Gas NSPS and**  **NESHAP Amendments in 2015 (**  **short tons per year)** 

Pollutant NESHAP Amendments NSPS HAP 1,258 19,028 VOC 9,024 292,532 Methane 4,783 1,721,7634 - 4

**4.3 Secondary Impacts**  **Analysis for Oil and Gas Rules**  The control techniques to avert leaks and vents of VOC and HAP are associated with several types of secondary impacts, which may partially offset the direct benefits of this rule. In this RIA, we refer to the secondary impacts associated with the specific control techniques as “producer - side” impacts. 9 For example, b y combusting VOC and HAP, combustion increases emissions of carbon monoxide, NOx, particulate matter and other pollutants. In addition to “pro ducer - side” impacts, these control techniques would also allow additional natural gas recovery , which would contribute to additional combustion of the recovered natural gas and ultimately

a shift in the national fuel mix. We refer to the secondary impacts associated with the combustion of the recovered natural gas as “consumer - side” secondary impacts. We provide a conceptual diagram of both categories of secondary impacts in Figure 4 - 1 .

9 In previous RIAs, we have also referred to these impacts as energy disbenefits.4 - 5

**Figure 4**  **- 1**  **Conceptual Diagram of Secondary Impacts from Oil and Gas NSPS and NESHAP Amendments**  Table 4 - 2 shows the estimated secondary “producer - side” impacts. Relative to the direct emission reductions anticipated from these rules, the magnitude of these secondary air pollutant impacts is small. Because the geographic distribution of these emissions from the oil and gas sector is not cons istent with emissions modeled in Fann, Fulcher, and Hubbell (2009), we are unable to monetize the PM 2.5 disbenefits associated with the producer - side secondary impacts. In addition, it is not appropriate to monetize the disbenefits associated with the inc reased CO 2 emissions without monetizing the averted methane emissions because the overall global warming potential (GWP) is actually lower . Through the combustion process, methane emissions are4 - 6

converted to CO 2 emissions, which have 21 times less global warming potential compared to methane (IPCC, 2007). 10 **Table 4**  **- 2**  **Secondary Air Pollutant Impacts Associated with Control Techniques by Emissions Category (“Producer**  **- Side”) (tons per year)**  **Emissions Category CO**  **2 NOx**  **PM CO**  **THC** Total Completions of New Wells (NSPS) 1,120,184 576 14.7 3,133 1,185 New Well Completions: REC/Combust 271,801 140 0.0 760 288 New Well Completions: Combust 848,382 436 14.7 2,373 898 Total Recompletions of Existing Wells (NSPS) 109,732 56 1.3 307 116 Existing Well Rec ompletions: REC/Combust 35,183 18 0.0 98 37 Existing Well Rec ompletions: Combust 74,549 38 1.3 208 79 Pneumatic Controllers (NSPS) 22 1.0 2.6 0.0 0.0 Storage Vessels (NSPS) 856 0.5 0.0 2.4 0.9 **Total NSPS 1,230,794**  **634 19**  **3,442 1,302**  **Total NESHAP (Storage Vessels) 5,543**  **2.9 0.1**  **16 6**  For the “consumer - side” impacts associated with the NSPS, we modeled the impact of the final NSPS on the national fuel mix and associated CO 2 - equivalent emissions ( Table 4 - 3 ) . 11 We provide the modeled results of the “consumer - side” CO 2 - equivalent emissions in Table 7 - 12 **.** The modeled results indicate that through a slight shift in the national fuel mix, the CO 2 - equivalent emissions across the energy sector would increase by 0. 5 4 million metric tons for the final NSPS in 2015. This is in addition to the other secondary impacts and directly

avoided emissions, for a total 31 million metric tons of CO 2 - equivalent emissions averted as shown in Table 4 - 4 . We estimate small increases other emissions (e.g., NOx, PM , SOx ) associated with the additional national gas consumption or the change in the national fuel mi x .

10 This issue is discussed in more detail in Section 4.7 of this RIA. 11 A full dis cussion of the energy modeling is available in Section 7 of this RIA.4 - 7

**Table 4**  **- 3**  **Modeled Changes in Energy**  **- rela**  **ted CO**  **2 -**  **equivalent Emissions by Fuel Type**  **for the Final**  **Oil and Gas NSPS in 2015**  **(million metric tons) (**  **"Consumer -**  **Side") 1**  Fuel T ype NSPS (million metric tons change in CO 2 - e) Petroleum - 0.44 Natural Gas 2.49 Coal - 1.51 Other 0.00 **Total m odeled Change**  **in CO 2**  **- e Em** **issions 0.54**  1 These estimates reflect the modeled change in CO 2 - e emissio ns using NEMS shown in Table 7 - 12 . Totals may not sum due to independent rounding.
**Table 4**  **- 4**  **Total Change in CO 2**  **- equivalent Emissions including Secondary Impacts for**  **the Final**  **Oil and Gas NSPS in 2015 (million metric tons)**  **Emissions Source NSPS**  **NESHAP Am**  **endments** Averted CO 2 - e Emissions from New Sources 1

- 32.8 - 0.09 Additional CO 2 - e Emissions from Com bustion and Supplemental Energy (Producer - side) 2 1.1 0.01 Total Modeled Change in Energy - related CO 2 - e Emissions (Consumer side) 3 0.54 -- **Total Change in CO 2**  **- e Emissions after Adjustment for Secondary**  **Impacts -**  **31.1 -**  **0.09** 1 This estimate reflects the GWP of the avoided methane emissions from new sources shown in Table 4 - 1 and has been converted from short tons to metric tons. 2 This estimate represents the secondary producer - side impacts associated with additional CO 2 emissions from combustion and from additional electricity requirements shown in Table 4 - 2 and has been conv erted from short tons to metric tons. 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 independent rounding. Based on these analy ses, the net impact of both the direct and secondary impacts of these rules would be an improvement in ambient air quality , which would reduce exposure to various harmful pollutants, improve visibility impairment, reduce vegetation dama ge, and reduce potency of greenhouse gas emissions. Table 4 - 5 provides a summary of the direct and secondary e missions changes for each rule .4 - 8

**Table 4**  **- 5**  **Summary of Emissions Changes for the Final**  **Oil and Gas NSPS and NESHAP in 2015 (short tons per year)**  Pollutant NSPS NESHAP Amendments **Change in Direct Emissions** VOC - 290,000 - 9,000 Methane - 1,700,000 - 4,800 HAP - 19,000 - 1,300
**Change in Secondary Emissions (Producer -**  **Side)** CO 2 1,200,000 5,500 NOx 630 2.9 PM 19.0 0.1 CO 3,400 16 THC 1,300 6.0 **Change in Secondary Emissions (Consumer**   ** Side)** CO 2 - e 600,000 N/A **Net Change in CO 2**  **- equivalent Emissions**  CO 2 - e - 34,000,000 ( ≈ 31,000,000 metric tons) - 95,000

( ≈ 90,000 metric tons) Note: T otals may not sum due to independent rounding. **4.4 Hazardous Air Pollutant (HAP) Benefits**  Even though emissions of air toxics from all sources in the U.S. declined by approximately 42 percent since 1990, the 2005 National - Scale Air Toxics Assessment (NATA) predicts that most Americans are exposed to ambient concentrations of air toxics at levels that have the potential to cause adverse health effects (U.S. EPA, 2011d). 12 The levels of air toxics to which people are exposed vary

depending on where they live and work and the kinds of activities in which they

engage. In order to identify and prioritize air toxics, emission source types and locations that are of greatest potential concern, U.S. EPA conducts the NATA. 13 The most recent NATA was conducted for calendar ye ar 2005 and was released in March 2011. NATA includes four steps:

12 The 2005 NATA is available on the Internet at http://www.epa.gov/ttn/atw/nata2005/. 13 The NATA modeling frame work has a number of limitations that prevent its use as the sole basis f or 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 prioritie s, and informing the decision making process. U.S. EPA. (2011) 2005 National - Scale Air Toxics Assessment. http://www.epa.gov/ttn/atw/nata2005/4 - 9

1) Compiling a national emissions inventory of air toxics emissions from outdoor sources 2) Estimating ambi ent and exposure concentrations of air toxics across the United States 3) Estimating population exposures across the United States 4) Characterizing potential public health risk due to inhalation of air toxics including both cancer and noncancer effects Based on the 2005 NATA, EPA estimates that about 5 percent of census tracts nationwide have increased cancer risks greater than 100 in a million. The average national cancer risk is about 50 in a million. Nationwide, the key pollutants that contribute mo st to the overall cancer risks are formaldeh yde and benzene. 14 , 15 Secondary formation (e.g., formaldehyde forming from other emitted pollutants) was the largest contributor to cancer risks, while stationary , mobile and background sources contribute almost equal portions of the remaining cancer risk. Noncancer health effects can result from chronic, 16 subchronic, 17 or acute 18 inhalation exposures to air toxics, and include neurological, cardiovascular, liver, kidney, and respiratory effects as well as effects o n the immune and reproductive sy stems. According to the 2005 NATA, about three - fourths of the U.S. population was exposed to an average chronic concentration of air toxics that has the potential for adverse noncancer respiratory health effects. Results from the 2005 NATA indicate that acrolein is the primary driver for noncancer respiratory

risk.

14 Details on EPA’s approach to characterization of cancer risks and uncertainties associated with the 2005 NAT A risk estimates can be found at http://www.epa.gov/ttn/atw/nata1999/riskbg.html#Z2 . 15 Details about the overall confidence of certainty ranking of the individual pieces of NATA assessments including both quantitative (e.g., model - to - mo nitor ratios) and qu alitative (e.g., quality of data, review of emission inventories) judgments can be found at http://www.epa.gov/ttn/atw/nata/roy/page16.html. 16 Chronic exposure is defined in the glossary of the Integrated Risk Information (IRIS) database (http://www.epa.go v/iris) as repeated exposure by the oral, dermal, or inhalation route for more than approximately 10% of the life span in humans (more than approximately 90 days to 2 years in typically used laboratory animal species). 17 Defined in the IRIS database as r ep eated exposure by the oral, dermal, or inhalation route for more than 30 days, up to approximately 10% of the life span in humans (more than 30 days up to approximately 90 days in typically used laboratory animal species) . 18 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.4 - 10

Figure 4 - 2 and Figure 4 - 3 depict the estimated census tract - level carcinogenic risk and noncancer respiratory

hazard from the assessment. It is important to no te that l arge reductions in HAP emissions may

not necessarily

translate into significant reductions in health risk because toxicity varies b y pollutant, and exposures may or may not exceed levels of concern. For example, acetaldeh yd e mass emissions are mo re than double acrolein emissions on a national basis, according to EPA’s 2005 National Emissions Inventory (NE I). However, the Integrated Risk Information Sy stem (IRI S) reference concentration (RfC) for acrolein is considerabl y lower than that for acetal deh yd e, suggesting that acrolein could be potentially more toxic than acetaldeh yde. 19 Thus, it is important to account for the toxicity and exposure, as well as the mass of the targeted emissions.

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

19 Details on the derivation of IRIS values and available supporting documentation for individual chemicals (as well as chemical values comparisons) can be found at http://cfpub.epa.g ov/ncea/iris/compare.cfm .4 - 11

**Figure 4**  **- 3**  **Estimated Chronic Census Tract Noncancer (Respiratory) Risk from HAP exposure from outd**  **oor sources (2005 NATA)** Due to methodology

and data limitations, we were unable to estimate the benefits associated with the hazardous air pollutants that would be reduced as a result of these rules . In a few previous anal ys es of the benefits of reductions in HAP , EPA has quantified the benefits of potential reductions in the incidences of cancer and noncancer risk (e.g., U.S. EPA, 1995 ). In those anal ys es, EPA relied on unit risk factors (URF) developed through risk assessment procedures. 20 These URFs are designed to be conservative, and as such, are more likely to represent the high end of the distribution of risk rather than a best or most likely estimate of risk. As the purpo se of a benefit analy sis is to describe the benefits most likely to occur from a reduction in pollution, use of high - end, conservative risk estimates would overestimate the

20 The unit risk factor is a quantitative estimate of the carcinogenic potency of a pollutant, often expressed as the probability of contracting cancer from a 70 - year lifetime continuous exposure to a concentration of one μg/m 3 of a pollutant.4 - 12

benefits of the regulation. While we used high - end risk estimates in past analy ses, advice from the EPA’s Science Advisory Board (SAB) recommended that we avoid using high - end estimates in benefit anal ys es (U.S. EPA - SAB, 2002 ). Since this time, EPA has continued to develop better methods for anal yz ing the benefits of reductions in HAP . As part of the second prospective anal ys is of the benefits and costs of the Clean Air Act (U.S. EPA, 2011a), EPA conducted a case study analy sis of the health effects associated with reducing exposure to benzene in Houston from implem entation of the Clean Air Act (IEc, 2009 ). While reviewing the draft report, EPA’s Advisory Council on Clean Air Compliance Anal ys is concluded that “the challenges for assessing progress in health improvement as a result of reductions in emissions of hazardous air pollutants ( HAP ) are daunting...due to a lack of exposure - response functions, uncertainties in emissions inventories and background levels, the difficulty of extrapolating risk estimates to low doses and the challenges of trackin g health progress for diseases, such as cancer, that have long latency periods” (U.S. EPA - SAB, 2008 ). In 2009, EPA convened a workshop to address the inherent complexities, limitations, and uncertainties in current methods to quantify the benefits of reducing HAP . Recommendations from this workshop included identifying research priorities, focusing on susceptible and vulnerable populations, and improving dose - response relationships (Gwinn et al., 2011 ). In summary , monetization of the benefits of reductions in cancer incidences requires several important inputs, including central estimates of cancer risks, estimates of exposure to carcinogenic HAP , and estimates of the value of an avoided case of cancer (fatal and non - fatal). Due to methodology

and data limitations, we did not attempt to monetize the health benefits of reductions in HAP in this anal ys is. Instead, we provide a qualitative anal ys is of the health effects associated with the HAP anticipated t o 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 benef its, including changes in the distribution of risk. Available emissions data show that several different HAP are emitted from oil and natural gas operations, either from equipment leaks, processing, compressing, transmission and distribution, or storage t anks. Emissions of eight HAP make up a large percentage the total HAP4 - 13

emissions by

mass from the oil and gas sector: toluene, hexane, benzene, xylenes (mixed), ethylene gl ycol, methanol, ethyl benzene, and 2,2,4 - trimethylpentane (U.S. EPA, 2011a). In the subsequent sections, we describe the health effects associated with the main HAP of concern from the oil and natural gas sector: benzene, toluene, carbon ylsulfide, eth yl benzene, mixed xylenes , and n - hexane. These rules combined are anticipated to avoid or reduce 20,000 tons of HAP per ye ar. 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, 201 2 ). The results for oil and gas production indicate that maximum lifetime individual cancer risks could be 1 0 in - a - million for existing sources with a cancer incidence of 0.02 before and after controls. Approximately

1 2 0,000 people are estimated to have cancer risks at or above 1 - in - 1 million for oil and gas production. For existing natural gas transmission and storage, the maximum individual cancer risk decreases from 2 0 - in - a - million with a cancer incidence of 0.001. Approximately 2,200 people are estimated to have cancer risk s at or above 1 - in - 1 million for oil and gas transmission and storage. Benzene is the primary cancer risk driver. The results also indicate that significant noncancer impacts from existing sources are unlikely , especiall y after controls. It is important to note that the magnitude of the HAP emissions avoided by new sources with the NSPS are much higher than the HAP emissions reduced from existing sources with the NESHAP. **4.4.1 Benzene**  The EPA’s IRIS database lists benzene as a known human carcinogen (causing leukemia) by all routes of exposure, and concludes that exposure is associated with additional health effects, including genetic changes in both humans and animals and increased proliferation of bone marrow cells in mice. 21 , 22 , 23 EPA states in its IRIS datab ase that data indicate a causal

21 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene. Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm. 22 International Agency for Research on Cancer, IARC monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 29, Some industrial chemicals and dyestuffs, International Agenc y for Research on Cancer, World Health Organization, Lyon, France, p. 345 - 389, 1982. 23 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, V.A. (1992) Synergistic action of the benzene metabolite hydroquinone on myelopoietic stimulating activity of gr anulocyte/macrophage colony - stimulating factor in vitro, Proc. Natl. Acad. Sci. 89:3691 - 3695.4 - 14

relationship between benzene exposure and acute ly mphocy tic leukemia and suggest a relationship between benzene exposure and chronic non - ly mphocy tic leukemia and chronic ly mphocy tic leukemia. The International Agency for Re search on Carcinogens (IARC) has determined that benzene is a human carcinogen and the U.S. Department of Health and Human Services (DHHS) has characterized benzene as a known human carcinogen. 24 , 25 A number of adverse noncancer health effects including blo od disorders, such as preleukemia and aplastic anemia, have also been associated with long - term exposure to benzene. 26 , 27 The most sensitive noncancer effect observed in humans, based on current data, is the depression of the absolute ly mphocy te count in b lood. 28 , 29 Inaddition, recent work, including studies sponsored by the Health Effects Institute (HEI), provides evidence that biochemical responses are occurring at lower levels of benzene exposure than previously known. 30 , 31 , 32 , 33 EPA’s IRI S program has not ye t evaluated these new data.

24 International Agency for Research on Cancer (IARC). 1987. Monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 29, Supplement 7, So me industrial chemicals and dyestuffs, World Health Organization, Lyon, France. 25 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens available at: http://ntp.niehs.nih.gov/go/16183. 26 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193 - 197. 27 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541 - 554. 28 Rothman, N., G.L. Li, M. Dosemeci, W.E. Bechtold, G.E. Marti, Y.Z. Wang, M. Linet, L.Q. Xi, W. Lu, M.T. Smith, N. Titenko - Holland, L.P. Zhang, W. Blot, S.N. Yin, and R.B. Hayes (1996) Hematotoxicity among Chinese workers heavily exposed to benzene. Am. J. Ind. Med. 29: 236 - 246. 29 U.S. Environmental Protection Age ncy (U.S. EPA). 2000. Integrated Risk Information System File for Benzene (Noncancer Effects). Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at: http://www.epa.gov/iris/s ubst/0276.htm. 30 Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; Cohen, B.; Melikian, A.; Eastmond, D.; Rappaport, S.; Li, H.; Rupa, D.; Suramaya, R.; Songnian, W.; Huifant, Y.; Meng, M.; Winnik, M.; Kwok, E.; Li, Y.; Mu, R.; Xu, B.; Zhang, X.; Li, K. (2003). HEI Report 115, Validation & Evaluation of Biomarkers in Workers Exposed to Benzene in China. 31 Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohen, et al. (2002). Hematological changes among Chinese workers with a broad range of benzene exposures. Am. J. Industr. Med. 42: 275 - 285. 32 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels of Benzene. Sc ience 306: 1774 - 1776. 33 Turtletaub, K.W. and Mani, C. (2003). Benzene metabolism in rodents at doses relevant to human exposure from Urban Air. Research Reports Health Effect Inst. Report No.113.4 - 15

**4.4.2 Toluene** **34** 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 bioassay s 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 s ys tem (CNS) is the primary t arget for toluene toxicity in both humans and animals for acute and chronic exposures. CNS dy sfunction (which is often reversible) and narcosis have been frequentl y observed in humans acutel y exposed to low or moderate levels of toluene by inhalation: sy

mptoms include fatigue, sleepiness, headaches, and nausea. Central nervous sy stem depression has been reported to occur in chronic abusers exposed to high levels of toluene. Sy mptoms include ataxia, tremors, cerebral atrophy, ny stagmus (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 dy sfunction, 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 ccupationall y exposed humans exists. The weight of evidence from these studies indicates neurological effects (i.e., impaired color vision, impaired hearing, decreased performance in neurobehavioral analy sis, 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 carbonylsulfide. Acute (short term) inhalation of high concentrations of carbonyl sulfide may cause narcotic eff

ects and irritate

34 All health effects language for this section came from: U.S. EPA. 2005. “Full IRIS Summary for Toluene (CASRN 108 - 88 - 3)” Environmental Protection Agency, Integrated Risk Information System (IRIS), Office of Health and Environmental Assessment, Environmental Criteria and Assessment Office, Cincinnati, OH. Available on the Internet at <http://www.epa.gov/iris/subst/0118.htm>.4 - 16

the eyes and skin in humans. 35 No information is available on the chronic (long - term), reproductive, developmental, or carcinogenic effects of carbonylsulfide 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. 36 **4.4.4 Ethylbenzene**  Ethylbenzene is a major industrial chemical produced b y alkyl ation of benzene. The pure chemical is used almost exclusively for sty rene production. It is als o a constituent of crude petroleum and is found in gasoline and diesel fuels. Acute (short - term) exposure to eth ylbenzene 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 sy stem from chronic inhalation exposure to ethylbenzene. No information is available on the developmental or reproductive effects of ethylbenzene in humans, but animal studies have reported developmental effects, including birth defects in animals exposed via inhalation. Studies in rodents reported increases in the percentage of animals with tumors of the nasal and oral cavities in male and female rats exposed to ethylbenzene via the oral route. 37 , 38 The reports of these studies lacked detailed information on the incidence of specific tumors, statistical analy sis, 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). 39 , 40 The NTP (1999) carried out a chronic inhalation

35 Hazardous Substances Data Bank (HSDB), online database). US National Library of Medicine, Toxicology Data Network, available online at http://toxnet.nlm.nih.gov/. Carbonyl health effects summary available at http://toxnet.nlm.nih.gov/cgi - bin/sis/search/r? dbs+hsdb:@term+@rn+@rel+463 - 58 - 1. 36 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Carbonyl Sulfide. Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at http://www.epa.gov/iris/subst/0617.htm. 37 Maltoni C, Conti B, Giuliano C and Belpoggi F, 1985. Experimental studies on benzene carcinogenicity at the Bologna Institute of Oncology: Current results and ongoing research. Am J Ind Med 7:415 - 446. 38 Maltoni C, Ciliberti A, Pinto C, Soffritti M, Belpoggi F and Menarini L, 1997. Results of long - term experimental carcinogenicity studies of the effects of gasoline, correlated fuels, and major gasoline aromatics on rats. Annals NY Acad Sci 837:15 - 52. 39 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.4 - 17

bioassay in mice and rats and found clear evidence of carcinogenic activity in male rats and some evidence in female rats, based on increased incidences of renal tubule adenoma or carcinoma in male rats and renal tubule adenoma in females. NTP (1999) also noted increases in the incidence of testicular adenoma in male rats. Increased incidences of lung alveolar/bronchiolar adenoma or carcinoma were observed in male mice and liver 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. 41 Other reporte d effects include labored breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and kidney s. 42 Lo ng - term inhalation exposure to xylenes in humans has been associated with a number of effects in the nervous s ys tem i ncluding headaches, dizziness, fatigue, tremors, and impaired motor coordination. 43 EPA has classified mixed xylenes in Category D, not classifiable with respect to human carcinogenicity. **4.4.6 n**  **- Hexane**  The studies available in both humans and animals indicate that the nervous sy stem 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) inhalati on exposure of humans to high levels of hexane causes mild central

40 National Toxicology Program (NTP), 1999. Toxicolo gy and Carcinogenesis Studies of Ethylbenzene (CAS No. 100 - 41 - 4) in F344/N Rats and in B6C3F1 Mice (Inhalation Studies). Technical Report Series No. 466. NIH Publication No. 99 - 3956. U.S. Department of Health and Human Services, Public Health Service, Nati onal Institutes of Health. NTP, Research Triangle Park, NC. 41 U.S. Environmental Protection Agency (U.S. EPA). 2003. Integrated Risk Information System File for Mixed Xylenes. Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at http://www.epa.gov/iris/subst/0270.htm. 42 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is available electronically at http://www.atsdr.cdc.gov/To xProfiles/TP.asp?id=296&tid=53. 43 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is available electronically at http://www.atsdr.cdc.gov/ToxProfiles/TP.asp?id=296&tid=53.4 - 18

nervous s ys tem effects, including dizziness, giddiness, slight nausea, and headache. Chronic (long - term) exposure to hexane in air causes numbness in the extremities, muscular weakness, blurred vision, headache, and fatigue. Inhalation studies in rodents have reported behavioral effects, neuroph ys iological changes and neuropathological effects upon inhalation exposure to n hexane. Under the Guidelines for Carcinogen Risk Assessment (U.S. EPA, 2005), the database for n - hexane is considered inadequate to assess human carcinogenic potential, therefore the EPA has classified hexane in Group D, not classifiable as to human carcinogenicity . 44 **4.4.7 Other Air Toxics**  In addition to the compounds describe d 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 IRI S database. 45 **4.5 VOC**  **4.5.1 VOC**  **as a PM 2.5**  **precursor** This rulemaking would reduce emissions of VOC , which are a precursor to PM 2.5. Most VOC 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 analy sis. Anal ys is of organic carbon measurements suggest onl y a fraction of secondarily

formed organic carbon aerosols are of anthropogenic origin. The current state of the science of secondary organic carbon aerosol formation indicates that anthropogenic VOC contribution to secondary organic carbon aerosol is often lower than the biogenic (natural) contribution. Given that a fraction of secondaril y formed organic carbon aerosols is from anthropogenic VOC emissions and the extremely small amount of VOC emissions from this sector relative to the entire VOC inventory i t is unlikely

this sector has a large contribution to

44 U.S. EPA. 2005. Guidelines fo r Carcinogen Risk Assessment. EPA/630/P - 03/001B. Risk Assessment Forum, Washington, DC. March. Available on the Internet at <http://www.epa.gov/ttn/atw/cancer_guidelines_final_3 - 25 - 05.pdf>. 45 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris4 - 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 th e court - ordered schedule and data limitations regarding locations of new well completions , we were unable to perform air quality modeling for this rule. Due to the high degree of variability in the responsiveness of PM 2.5 formation to VOC emission reducti ons, we are unable to estimate the effect that reducing VOC 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 toxicolo gical, clinical and epidemiological studies (U.S. EPA, 2009a). When adequate data and resources are available, EPA generall y quantifies several health effects associated with exposure to PM 2.5 (e.g., U.S. EPA ( 2011 g )). These health effects include premat ure mortality

for adults and infants, cardiovascular morbidity such as heart attacks, hospital admissions, and respiratory morbidity such as asthma attacks, acute and chronic bronchitis, hospital and ER visits, work loss day s, restricted activity

day s, and respiratory

s ymptoms. Although EPA has not quantified these effects in previous benefits analy ses, the scientific literature suggests that exposure to PM 2.5 is also associated with adverse effects on birth weight, pre - term births, pulmonary function, oth er 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 suffic ient to allow differentiation of effect estimates by particle ty

pe (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.4 - 20

Previous studies have estimated the monetized benefits - per - ton of reducing VOC emissions associate d 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 V OC emissions in nine urban areas of the U.S. ranges from $560 in Seattle, WA to $5,700 in San Joaquin, CA, with a national average of $2,400. These estimates assume a 50 percent reduction in VOC , the Laden et al. (2006) mortality function (based on the Harvard Six City Study, a large cohort epidemiology

study in the Eastern U.S.), an analysis year of 2015, and a 3 percent discount rate. Based on the methodology from Fann, Fulcher, and Hubbell (2009), we converted their estimates to 2008$ and applied EPA’ s current VSL estimate. 46 After these adjustments, the range of values increases to $680 to $7,000 per ton of VOC reduced for Laden et al. (2006). Using alternate assumptions regarding the relationship between PM 2.5 exposure and premature mortality from e mpirical 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 generally

presents a range of benefits estimates derived from Pope et al. (2002) to Laden et al. (2006) because they are both well - designed and peer reviewed studies, and EPA provides the benefit estimates d erived 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 anal ys is, the geographic distribution of VOC emissions from the oil and gas sector are not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition, the benefit - per - ton estimates for VOC emission reductio ns in that study are derived from total VOC emissions across all sectors. Coupled with the larger uncertainties about the relationship

46 For more information regarding EPA’s current VSL estimate, please see Section 5.4.4.1 of the RIA for the proposed Federal Transport Rule (U.S. EPA, 2010a). EPA continues to work to update its guidance on valuing mo rtality risk reductions.4 - 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 these rules, even as a bounding exercise.4 - 22

**Table 4**  **- 6**  **Monetized Benefits**  **- per**  **- Ton Estimates for**  **VOC (2008$)**  **Area Pope et** 

**al. Laden et** 

**al. Expert** 

**A Expert** 

**B Expert** 

**C Expert** 

**D Expert** 

**E Expert**  **F Expert**  **G Expert** 

**H Expert** 

**I Expert**  **J Expert**  **K Expert** 

**L** Atlanta $620 $1,500 $1,600 $1,200 $1,200 $860 $2,000 $1,100 $730 $920 $1,200 $980 $250 $940 Chicago $1,500 $3,800 $4,000 $3,100 $3,000 $2,200 $4,900 $2,800 $1,800 $2,300 $3,000 $2,500 $600 $2,400 Dallas $300 $740 $780 $610 $590 $420 $960 $540 $360 $450 $590 $480 $120 $460 Denver $720 $1,800 $1,800 $1,400 $1,400 $1,000 $2,300 $1,300 $850 $1,100 $1,400 $1,100 $280 $850 NYC/ Philadelphia $2,100 $5,200 $5,500 $4,300 $4,200 $3,000 $6,900 $3,900 $2,500 $3,200 $4,200 $3,400 $830 $3,100 Phoenix $1,000 $2,500 $2,600 $2,000 $2,000 $1,400 $3,300 $1,800 $1,200 $1,500 $2,000 $1,600 $400 $1,500 Salt Lake $1,300 $3,100 $3,300 $2,600 $2,500 $1,800 $4,100 $2,300 $1,500 $1,900 $2,500 $2,100 $530 $2,000 San Joaquin $2,900 $7,000 $7,400 $5,800 $5,600 $4,000 $9,100 $5,200 $3,400 $4,300 $5,600 $4,600 $1,300 $4,400 Seattle $280 $680 $720 $530 $550 $390 $890 $500 $330 $420 $550 $450 $110 $330 **National average $1,200**  **$3,000 $3,200**  **$2,400 $2,400**  **$1,700 $3,900**  **$2,200 $1,400**  **$1,800 $2,400**  **$1,900 $490**  **$1,800**

* These estimates assume a 50 percent reduction in VOC emissions, an analysis year of 2015, and a 3 percent discount rate. All estimates are rounded to two significant digits. These estimates have been updated from Fann, Fulcher, and Hubbell (2009) to reflect a more recent 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 percent to 52 percent . Assuming a 25 percent reduction in VOC emissions would decrease the benefit - per - ton estimates by 5 percent to 52 percent . EPA generally presents a range of benefits estimates derived from Pope et al. (2002) to Laden et al. (2006) and provides the benefits estimates derived from the expert functions from Roman et al. (2008) as a characterization of uncertainty.4 - 23

**4.5.3 Organic PM welfare effects**  According to the residual risk assessment for this sector (U.S. EPA, 2011a), persistent and bioaccumulative HAP reported as emissions from oil and ga s operations include polycyclic organic matter (POM). POM defines a broad class of compounds that includes the polycyclic aromatic h ydrocarbon compounds (PAHs). Several significant ecological effects are associated with deposition of organic particles, i ncluding persistent organic pollutants, and PAHs (U.S. EPA, 2009a). PAHs can accumulate in sediments and bioaccumulate in freshwater, flora , and fauna. The uptake of organics depends on the plant species, site of deposition, physical and chemical properties of the organic compound and prevailing environmental conditions (U.S. EPA, 2009a). PAHs can accumulate to high enough concentrations in some coastal environments to pose an environmental health threat that includes cancer in fish populations, toxicity to organisms living in the sediment and risks to those (e.g., migratory birds) that consume these organisms. Atmospheric deposition of particles is thought to be the major source of PAHs to the sediments of coastal areas of the U.S. Deposition of PM to surfaces in urban settings increases the metal and organic component of storm water runoff. This atmosphericall y- associated pollutant burden can then be toxic to aquatic biota. The contribution of atmosphericall y deposited PAHs to aquatic food webs was de monstrated in high elevation mountain lakes with no other anthropogenic contaminant sources. The recentl y completed Western Airborne Contaminants Assessment Project (WACAP) is the most comprehensive database on contaminant transport and PM depositional eff ects on sensitive ecos ys tems in the Western U.S. (Landers et al., 2008). In this project, the transport, fate, and ecological impacts of anthropogenic contaminants from atmospheric sources were assessed from 2002 to 2007 in seven ecos ys tem 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 ecos ys tems, 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 is4 - 24

counter to the original working h ypothesis 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, 1 996). Suspended particles and gases degrade visibility by scattering and absorbing light. Higher visibility impairment levels in the East are due to generally

higher concentrations of fine particles, particularl y 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 anal ys es (U.S. EPA, 2006 b ; U.S. EPA, 201 1 g ; 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 VOC**  **as an Ozone Precursor** This rulemaking would reduce emissions of VOC , 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 V OC and CO are important compounds for ozone formation, but biogenic VOC emitted from vegetation tend to be more important compounds in non - urban vegetated areas (U.S. EPA, 2006 a). Therefore, reducing these emissions would reduce ozone formation, human exp osure to ozone, and the incidence of ozone - related health effects. However, we have not quantified the ozone - related benefits in this analy sis for several reasons. First, previous rules have shown that the monetized benefits associated with reducing ozon e 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 formation introduces uncertaint y to the development and application of a benefit - per - ton estimate. Third, the impact of reducing VOC emissions is4 - 25

spatially heterogeneous depending on local air chemistry . Urban areas with a high population concentration are often VOC - limited, which means that ozone is most effectively reduced by lowering VOC . Rural areas and downwind suburban areas are often NOx - limited, which means that ozone concentrations are most effectivel y reduced b y lowering NOx emissions, rather than lowering emissions of VOC . Between these areas, ozone is relatively insensitive to marginal changes in both NOx and VOC. Due to time limitations under the court - ordered schedule and data limitations , we were unable to perform air quality modeling for this rule. Due to the high degree of variability in the responsiveness of ozone formation to VOC emission reductions and data limitations regarding the location of new well completions , we are unable to estimate the effect that reducing VOC will have on ambient ozone concentrations without air quality modeling. **4.6.1 Ozone healt** 

**h effects and valuation** Reducing ambient ozone concentrations is associated with significant human health benefits, including mortality and respiratory

morbidity

(U.S. EPA, 2010a). Epidemiological researchers have associated ozone exposure with adverse he alth effects in numerous toxicological, clinical and epidemiological studies (U.S. EPA, 2006c). When adequate data and resources are available, EPA generall y quantifies several health effects associated with exposure to ozone (e.g., U.S. EPA , 2010a ; U.S. EPA, 2011a). These health effects include respiratory morbidity such as asthma attacks, hospital and emergency department visits, school loss day s, as well as premature mortality . Although EPA has not quantified these effects in benefits anal ys es previous ly , 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 analy sis, EPA estimated that reducing 15,000 tons of VOC from industrial boilers resul ted in $3.6 to $15 million of monetized benefits from reduced ozone exposure (U.S. EPA, 2011 b ). 47 This implies a benefit - per - ton for ozone reductions of $240 to $1,000 per ton of VOC reduced. While these ranges of benefit - per - ton estimates provide useful context, the geographic distribution of VOC emissions from the oil and gas sector are not

47 While EPA has estimated the ozone benefits for many scenarios, most of these scenarios also reduce NOx emissions, which make it difficult to isolate the benefits attributable to VOC reductions.4 - 26

consistent with emissions modeled in the boiler analy sis. Therefore, we do not believe that those estimates to provide useful estimates of the monetized benefits of these rules, even as a bounding exercise. **4.6.2 Ozone vegetation effects**  Exposure to ozone has been associated with a wide array of vegetation and ecosy stem effects in the published literature (U.S. EPA, 2006a). Sensitivity to ozone is highl y 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 ecos ys tem. 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 ecos ys tems and associated ecos ys tem 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, tropospheric ozone (ozone in the lower atmospher e) is a harmful air pollutant that adversel y affects human health and the environment and contributes significantl y 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 .4 - 27

**4.7 Methane (CH**  **4 )**  **4.7.1 Methane climate effects and valuation**  Methane is the principal component of natural gas. Methane is also a potent greenhouse gas (GHG) that once emitted into the atmosphere absorbs terrestrial infrared radiation which contributes to increased global warming and continuing climate change. Methane reacts in the atmosp here to form ozone and ozone als o impacts global temperatures. Methane, in addition to other GHG emissions, contributes to warming of the atmosphere which over time leads to increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of global glaciers and ice, increasingl y severe weather events, such as hurricanes of greater intensity , and sea level rise, among other impacts. According to the Intergovernmental Panel on Climate Change (IPCC) Fourth Assessment Report (2007), c hanges in methane concentrations since 1750 contribute d 0. 48 W/m2 of forcing, which is about 18% of all global forcing due to increases in anthropogenic GHG concentrations, and which makes methane the second leading long - lived climate forcer after CO 2 . However, after accounting for changes in other greenhouse sub stances such as ozone and stratospheric water vapor due to chemical reactions of methane in the atmosphere , historical methane emissions were estimated to have contributed to 0.86 W/m2 of forcing today , which is about 30% of the forcing due to historical greenhouse gas emissions. Processes in the oil and gas category emit significant amounts of methane. The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 - 2009 (published April 2011) estimates 2009 methane emissions from Petroleum and Natural Gas Sy stems (not including petroleum refineries and petroleum transportation) to be 251.55 (MMt CO 2 - e). In 2009, total methane emissions from the oil and gas industry

represented nearly

40 percent of the total methane emissions from all sources and account for about 5 percent of all CO 2 - equivalent (CO 2 - e) emissions in the U.S., with natural gas s ys tems being the single largest contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2011b, Table ES - 2). It is important to note that the 2009 emissions estimates from well completions and recompletions exclude a significant number of wells completed in tight sand play s and the Marcellus Shale, due to availability of data when the 2009 Inventory was developed. The estimate in this final rule includes an adjustment for tight sand4 - 28

play s and the Marcellus Shale, and such an adjustment is also being cons idered as a planned improvement in next year's Inventory . This adjustment would increase the 2009 Inventory estimate by

about 80 MMtCO 2 - e. The total methane emissions from Petroleum and Natural Gas Sy stems based on the 2009 Inventory , adjusted for tight sand play s and the Marce llus Shale, is approximately

330 M MtCO 2 - e. This rulemaking finalizes emission control technologies and regulatory alternatives that will significantl y decrease methane emissions from the oil and natural gas sector in the United States . The NSPS is expected to reduce methane emissions annually by about 1.7 million short tons or approximately

33 million metric tons CO 2 - e. The se reductions represent about 13 percent of the GHG emissions for this sector reported in the 1990 - 2009 U.S. GHG Inventory (251.55 MMTCO 2 - e). This annual CO 2 - e reduction becomes about 31 million metric tons when the secondary

impacts associated with increased combustion and supplemental energy use on the producer side and CO 2 - e emissions from changes in consumption patterns previously discussed are considered. However, it is important to note the emissions reductions are based upon predicted activities in 2015; EPA did not forecast sector - level emissions to 2015 for this rule making. T he climate co - benefit from these reductions are equivalent of taking approximately 6 million typ ical passenger cars off the road or eliminating electricity use from about 4 million ty

pical homes each ye ar. 48 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 estimate of the net present value of the flow of monetized damages from a one metric ton increase in CO 2 em issions in a given ye ar (or from the alternative perspective, the benefit to society of reducing CO 2 emissions by one ton). The SCC includes (but is not limited to) climate damages due to changes in net agricultural productivity , human health, property dam ages from flood risk, and ecos ys tem services due to climate change. The SCC estimates currentl y used b y the Agency

were developed through an interagency process that included EPA and other executive branch entities, and concluded in February 2010. The Technical Support Document: Social Cost of Carbon for Regulatory Impact Analy sis Under Executive Order 12866 for the
48 US Environmental Protection Agency. Greenhouse Gas Equivalency Calculator available at: http://www.epa.gov/cleanenergy/energy - resources/calculator.html accessed 0 2 /1 3 /1 2 .4 - 29

final joint EPA/Department of Transportation Rulemaking to establish L ight - Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Econom y Standards provides a complete discussion of the methods used to develop the SCC estimates ( Interagency Working Group o n Social Cost of Carbon, 2010 ) . To estimate global social benefits of reduced CO 2 emissions, the interagency group selected four SCC values for use in regulatory analy ses: $6, $25, $40, and $76 per metric ton of CO 2 emissions in 2015, in 2008 dollars. 49 The first three values are based on the average SCC estimated using three integrated assessment models (IAMs), at discount rates of 5.0, 3.0, and 2.5 percent, respectively . When valuing the impacts of climate change, IAMs couple economic and climate sy stems into a single model to capture important interactions between the components. SCCs estimated using different discount rates are included because the literature shows that the SCC is quite sensitive to assumptions about the discount rate, and because no consensus exists on the appropriate rate to use in an intergenerational context. The fourth valu e is the 95th percentile of the distribution of SCC estimates from all three models at a 3.0 percent discount rate. It is included to represent higher - than - expected damages from temperature change further out in the tails of the SCC distribution. The inte ragency

group noted a number of limitations to the SCC analysis, including the incomplete way

in which the integrated assessment models capture catastrophic and non catastrophic impacts, their incomplete treatment of adaptation and technological change, un certainty in the extrapolation of damages to high temperatures, and assumptions regarding risk aversion. The limited amount of research linking climate impacts to economic damages makes estimating damages from climate change even more difficult. The interagency group hopes that over time researchers and modelers will work to fill these gaps and that the SCC estimates used for regulatory

anal ys is by

the Federal government will continue to evolve with improvements in modeling. Additional details on these lim itations are discussed in the SCC TSD.

49 The interagency group concluded that a global measure of the benefits from reducing U.S. emissions is preferable. The development of a domestic SCC is greatly complicated by the relatively few region - or country - specific estimates of SCC in the literature. See Interagency Working Group on Social Cost of Carbon. 2010. Technical Support Document: Social Cost of Carbon f or Regulatory Impact Analysis Under Executive Order 12866.4 - 30

A significant limitation of the aforementioned interagency process particularly

relevant to this rulemaking is that the social costs of non - CO 2 GHG emissions were not estimated. Specificall y, the interagency group did not directly estimate the social cost of non - CO 2 GHGs using the three models. Moreover, the group determined 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 particular timeframe relative to CO 2 . One potential method for approximating the value of marginal non - CO 2 GHG emission reductions is to convert the redu ctions to CO 2 - equivalents which may then be valued using the SCC. Conversion to CO 2 - e is ty picall y 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 ye ars. 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 dy namics between gases will be lost. This is a potentially conf ounding 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 Asses sment Report (SAR) 100 - year GWP estimate). Gases with a relativel y shorter lifetime, such as methane, have impacts that occur primarily in the near term and thus are not discounted as heavily as those caused by

longer - lived gases such as CO 2 , while the GW P 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 relativel y short lived gases will have a lower marginal impact rel ative 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 way s that are not captured by GWP. For instance, CO 2 emissions, unlike methane will result in CO 2 passive fertilization to plants.4 - 31

The EPA recognizes that the methane reductions finalized in this rule will provide significant econo mic climate co - benefits to society . However, the 2009 - 2010 Interagency Social Cost of Carbon Work Group did not produce directly modeled estimate s of the s ocial cost of methane . In the absence of direct model estimates from the interagency analy sis, EPA has used aA “global warming potential (GWP) approach” to estimate the dollar value of this rule’s methane co - benefits. Specificall y, EPA of converted methane to CO 2 equiv alents using the GWP of methane, then multiplied these CO 2 - equivalent emission reductions by the social cost of carbon developed b y the Interagency Social Cost of Carbon Work Group . EPA requested comments from interested parties and the public about this interim approach specifically

and more broadl y about appropriate methods to monetize the climate co benefits of methane reductions. EPA’s response to these comments, as well as a summary of the p ublic comments sent in response to this request, is provided in the response to comments document. Applying the GWP approach, these co - benefit s equate to a range of approximately $1 3 0 to $1,6 00 per metric ton of methane reduced depending upon the discount rate assumed , with an estimate of $840 per ton using the mean SCC at the 3 percent discount rate . 50 When including expected methane emission reductions from the NESHAP Amendments and NSPS and considering secondary

impacts of the oil and gas rule, the 2015 co - benefit s vary by discount rate and range from about $190 millio n to over $2.4 billion; the mean SCC at the 3 percent discount rate ($25 per metric ton) results in an estimate of $780 m illion in 2015 (T able 4 - 7) .

50 The per ton estimates range from approximately $110 to $1400 per short ton of methane reduced, depending on the discount rate assumed, with an estimate of $480 per short ton of methane, using th e mean SCC at 3% discount rate.4 - 32

**Table 4**  **- 7**  **Climate Methane Benefits Using ‘GWP’ Approach SCC Value for 2015 emission reductions ($/ton** 

**CO2 in 2008 dollars) 1**  **Total Benefits based on 100 year GWP adjustment**  **2 (millions 2008$)**  **Final NSPS Final**  **NESHAP Amendments**  $6 (mean 5% discount rate) 190 0.5 $25 (mean 3% discount rate) 780 2.3 $40 (mean 2.5% discount rate) 1,200 3.6 $76 (95 percentile at 3% discount rate) 2,400 6.8 **Methane Emission Reductions 3**  **(MMT CO 2**  **- e)**  **31 0.09**  1 SCC values for 2015 from the SCC TSD in the light duty vehicle rule adjusted to reflect 2008$ using the CPI
- U from the Bureau of Labor Statistics. 2 Estimates are given for illustrative purposes and r epresent the CO 2 - e estimate of methane reductions multiplied by the SCC estimates (“ GWP approach”) .CO 2 - e calculated using the GWP of 21 (SAR). These co - benefit estimates are not the same as would be derived using a social cost of methane directly computed from integrated assessment mo dels. See Marten and Newbold (2011) for discussion of the limitations of the GWP approach. 3 Estimates include methane reductions from the NSPS and NESHAP Amendments respectively and consider secondary impacts from Table 4 - 4. As previously

stated, these co - benefit estimates are not the same as would be derived using a directl y 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 re lative to CO 2 (about 12 years compared to CO 2 whose concentrations in the atmosphere decay on timescales of decades to millennia). The climate impacts also differ between the pollutants for reasons other than the radiative forcing profiles and atmospheric lifetimes of these gases. Methane is a precursor to ozone and ozone is a short - lived climate forcer (details below) . This use of the SAR GWP to approximate benefits may underestimate the direct radiative forcing benefits of reduced ozone levels, and does not capture any secondary

climate co - benefits involved with ozone - ecos ys tem 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 reduc tions 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 analy sis. Using the higher GWP estimate of 25 would increase these reported methane climate co - benefit estimates by

about 19 percent. Although the IPCC Fourth Assessment Report suggested a GWP of 25, EPA has used GWP of 21 consistent with the IPCC SAR to estimate the methane climate co - benefits for this oil and gas rule . The use of the SAR GWP values allows comparability of4 - 33

data collected in this final rule to the national GHG inventory that EPA compiles annually to meet U.S. commitments to the United Nations Framework Convention on Climate Change (UNFCCC). To compl y with international reporting standards under the UNFCCC, official emission estimates are to be reported by the U.S. and other countries using SAR GWP values. The UNFCCC reporting guidelines for national inventories were updated in 2 002 but continue to require the use of GWPs from the SAR. The parties to the UNFCCC have also agreed to use GWPs based upon a 100 - ye ar time horizon although other time horizon values are available. The SAR GWP value for methane is also currently used to e stablish GHG reporting requirements as mandated b y the GHG Reporting Rule (2010e) and is used by the EPA to determine Title V and Prevention of Significant Deterioration GHG permitting requirements as modified by the GHG Tailoring Rule (2010f). EPA also undertook a literature search for estimates of the marginal social cost of methane. A range of marginal social cost of methane benefit estimates are available in published literature (Fankhauser (1994), Kandlikar (1995), Hammitt et al. (1996), Tol et al. ( 2003), Tol, et al. (2006), Hope (2005) and Hope and Newberry (2006). Most of these estimates are based upon modeling assumptions that are dated and inconsistent with the current SCC estimates. Some of these studies focused on marginal methane reductions in the 1990s and early 2000s and report estimates for onl y the single ye ar of interest specific to the study . The assumptions underlying the social cost of methane estimates available in the literature differ from those agreed upon b y the SCC interagency group and in many cases use older versions of the IAMs. Without additional anal ys is, the methane climate benefit estimates available in the current literature are not acceptable to use to value the methane reductions finalized in this rulemaking. Given the uncertainties with both the ‘GWP approach’ estimates presented and estimates available in the literature, EPA chooses not to compare these co - benefit estimates to the costs of the rule for this final rule. Rather, the EPA presents the ‘GWP approach’ c limate co - benefit estimates as an interim method to produce lower - bound estimates until the interagency group develops values for non - CO 2 GHGs.4 - 34

**4.7.2 Methane as an ozone precursor**  This rulemaking would reduce emissions of methane, a GHG and also a precursor to ozone. Inremote areas, methane is a dominant precursor to tropospheric ozone formation (U.S. EPA, 2006a). Approximately 40% of the global annual mean ozone increase since preindustrial times is believed to be due to anthropogenic methane (HTAP, 2010). Projections of future emissions also indicate that methane is likely to be a key

contributor to ozone concentrations in the future (HTAP, 2010). Unlike NOx and VOC , which affect ozone concentrations regionally and at hourl y time scales, methane emissions affect ozone concentrations globally and on decadal time scales given methane’s relativel y long atmospheric lifetime (HTAP, 2010). Reducing methane emissions, therefore, can reduce global background ozone concentrations, human exposure to ozone, and the i ncidence of ozone - related health effects (West et al., 2006, Anenberg et al., 2009) . These benefits are global and occur in both urban and rural areas. Reductions in background ozone concentrations can also have benefits for agriculture and ecos ys tems (UNEP/WMO, 2011). Studies show that controlling methane emissions can reduce global ozone concentrations and climate change simultaneously , but controlling other shorter lived ozone precursors such as NOx, carbon monoxide, or non - methane VOC may have larger local health benefits from greater reductions in ozone concentrations (West and Fiore, 2005; West et al., 2006, 2007; Fiore et al. 2008; Dentener et al., 2005; Shindell et al., 2005, 2012; UNEP/WMO, 2011). VOC The health, welfare, and climate effects assoc iated with ozone are described in the preceding sections. Without air quality modeling, we are unable to estimate the effect that reducing methane will have on ozone concentrations at particular locations. **4.7.3 Combined m**  **ethane and ozone effects**  A recent Unite d Nations Environment Programme (UNEP) assessment provides the most comprehensive anal ys is to date of the health, climate, and agricultural benefits of measures to reduce methane, as well as black carbon, a component of fine particulate matter that absorbs radiation (UNEP/WMO, 2011; Shindell et al., 2012). The UNEP assessment found that while reducing longer - lived GHGs such as CO 2 is necessary to protect against long - term climate change, reducing global methane and black carbon emissions would have global health benefits by reducing exposure to ozone and PM 2.5 as well as potentially slowing the rate of climate change within the fir st half of this century . Relative to a business as usual reference scenario,4 - 35

implementing methane mitigation measures that achieve approximately 40% reductions in global methane emissions were estimated to avoid approximately 0.3° C globally

averaged warmi ng in 2050 (including the impacts of both methane itself and subsequentl y formed ozone) and 47,000 ozone - related premature deaths and 27 million metric tons of ozone - related crop yi eld losses globall y in 2030 (Shindell et al., 2012). These benefits, including global climate impacts of methane and resulting ozone changes, and global ozone - related health and agricultural impacts, were valued at $700 to $,5000 per metric ton 51
. The methane measures examined include extended methane recovery /utilization and redu ced fugitive emissions from oil and gas production, which contributed the greatest climate benefit of all methane mitigation measures in North America and Europe (UNEP, 2011). **4.8 References**  Anenberg, S.C., et al. 2009 . “Intercontinental impacts of ozone pollution on human mortality ,” Environ. Sci. & Technol ., 43, 6482 - 6487 . Dentener, F., D. Stevenson, J. Cofala, R. Mechler, M. Amann, P. Bergamaschi, F. Raes, and R. Derwent . 2005 . “The impact of air pollutant and methane emission controls on tropospheric ozone and radiative forcing: CTM calculations for the period 1990 - 2030,” Atmos. Chem. Phys ., 5, 1731 - 1755. Fankhauser, S. 199 4. “ The social costs of greenhouse gas emissions: an expected value approach. ” Energy Journal 1 5 (2):157

– 184. Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. “ The influence of location, source, and emission ty pe in estimates of the human health benefits of reducing a ton of air pollution. ” Air Qual Atmos Health 2:169 - 176. Fiore, A.M., J.J. West, L .W. Horowitz, V. Naik, and M.D. Schwarzkopf . 2008 . “Characterizing the tropospheric ozone response to methane emission controls and the benefits to climate and air quality,” J. Geophys. Res ., 113, D08307, doi:10.1029/2007JD009162

51 Benefit per ton values derived from Shindell et al. (2012) cannot be directly compared to, nor are they additive with, the ozone health benefit - per - ton estimates for the U.S. reported in Section 4.6.1, since they include climate and agricultural impacts, are calculated for global rather than U.S. impacts, and use different assumptions for the value of a statistical life. Similarly, these values cannot be compared to, nor are they additive with, the methane climate valuati on estimates in Section 4.7. 1 since they include health and agricultural benefits and use different assumptions for the Social Cost of Carbon.4 - 36

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. Avery t, M. Tignor and H.L . Miller (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA. Gwinn, M.R . , J . Craig , D.A . Axelrad , R . Cook , C . Dockins , N . Fann , R . Fegley , D.E . Guinnup , G . Helfand , B . Hubbell , S.L . Mazur , T . Palma , R.L . Smith , J . Vandenberg , and B . Sonawane. 2011. “Meeting report: Estimating the benefits of reducing hazardous air pollutants

— summary

of 2009 workshop and future considerations.” Environ Health Perspect . 119(1): p. 125 - 30. Hammitt , J.K. , A.K. Jain , J.L . Adams, and D.J. Wuebbles. 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 methane emissions. ” Climatic Change 68(1):21

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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 Qual ity , Department of Agriculture, 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 Department of Treasury . <http://www.epa.gov/otaq/climate/regulations.htm> Accessed March 30, 2011. Intergovernmental Panel on Climate Change ( IP CC ). 2007 . Climate Change 2007: Synthesis Report. Contribution of Working Groups I, I I and III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (AR4) [Core Writing Team, Pachauri, R.K and Reisinger, A. (eds.)]. IPCC, Geneva, Switzerland, 104 pp.4 - 37

<http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report _sy nthesis_report.htm>. Accessed March 30, 2011/ Intergovernmental Panel on Climate Change ( IP CC ). 2007. IP CC Fourth Assessment Report: Climate Change 2007. Working Group II, Chapter 20 ‘ Perspectives on Climate Change and Sustainabili ty .’ <http://www.ipcc.ch/publications_and_data/ar4/wg2/en/ch20s20 - 6 - 1.html > Accessed March 30, 2011. Kandlikar , M . 1995. “ The relative role of trace gas emissions in greenhouse abatement policies. ” Energy Policy 23(10): 879

– 883. 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 - 672. Landers DH; Simonich SL; Jaffe DA; Geiser LH; Campbell DH; Sc hwindt AR; Schreck CB; Kent ML ; Hafner WD; Taylor HE; Hageman 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. Nolte, C.G., A.B. Gilliland, C. Hogrefe, and L.J. Mickley . 2008 . “Linking global to regional models to assess future climate impacts on surface ozone levels in the United States,” J. Geophys. Res ., 113, D14307, doi:10.1029/2007JD008497 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 L ong - term E xposure to Fine Particulate Air Pollution.” Journal of the American Medical Association 287:1132 - 1141. 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 o f Changes in Ambient Fine Particulate Matter in the U.S.” Environ. Sci. Technol . 42(7):2268 - 2274. Shindell, D., J.C.I . Kuyl enstierna, E. Vignati, R. van Dingenen, M. Amann, Z. Klimont, S.C. Anenberg , N. Muller, G. Janssens - Maenhout, F. Raes, J. Schwartz, G. Faluvegi, L. Pozzoli, K. Kupiainen, L. Hoglund - Isakson, L. Emberson, D. Streets, V. Ramanathan, K. Hicks, K. Oanh, G. Mill y, M. Williams, V. Demkine, D. Fowler . 2012 . Simultaneously mitigating near - term climate change and improving human health and food security, Science , 335:183 - 189.4 - 38

Shindell, D.T., G. Faluvegi, N. Bell, and G.A. Schmidt . 2005 . “An emissions - based view of climate forcing b y methane and tropospheric ozone,” Geophys. Res. Lett ., 32, L 04803, doi:10.1029/2004GL 021900 Task Force on Hemispheric Transport of Air Pollution (HTAP). 2010. Hemispheric Transport of Air Pollution 2010 . Informal Document No.10. Convention on L ong - range Transboundary

Air Pollution Executive Body 28th Session. ECE/EB.AIR/2010/10 (Cor rected). Chap ter 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. L ammers. 2003. “ Methane emission reduction: An application of FUND. ” Climatic Change 57(1):71

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- Term Climate Change: An Integrated Assessment of Black Carbon and Tropospheric Ozone, and its Precursors , United Nations Environment Programme, Nairobi. Online at www.unep.org . Accessed February 9, 2012. United Nations Environment Programme (UNEP). 2011. Near - Term Climate Protection and Clean Air Benefits: Actions for Controlling Short - Li ved Climate Forcers, United Nations Environment Programme, Nairobi. Online at <http://www.unep.org/public ations/ebooks/SL CF/ >. Accessed February 9, 2012. 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/n cea/CFM/recordisplay .cfm?deid=149923 > . Accessed March 30, 2011. U.S. Environmental 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/regdata/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, 2011.4 - 39

U.S. Environmental Protection Agency (U.S. EPA). 2009 a. Integrated Science Assessment for Particulate Matter (Final Report). EPA - 600 - R - 08 - 139F. National Center for Environmental Assessment

—RTP Division. <http://cfpub.epa.gov/ncea/cfm/recordisplay .cfm?deid=216546>. Accessed March 30, 2011. U.S. Environmental Protection Agency (U.S. EPA). 2009b. Technical Support Document for Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act . <http://www.epa.gov/climatechange/endangerment/ downloads/Endangerment%20TSD.p d>. Accessed March 30, 2011. 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_anal ys is_full.pdf >. Accessed March 30, 2011. U.S. Environmental Protection Agency (U.S. EPA). 2010 b . Regulatory Impact Analysis for the SO2 NAAQS. Office of Air Quality Planning and Standards, Research Triangle Park, NC. < http://www.epa.gov/ttn/ecas/regdata/RIAs/fso2ria100602full.pdf >. Accessed March 30, 2011. U.S Environmental Protection Agency (U.S. EPA). 2011a. Draft Residual Risk Assessment for the Oil and Natural Gas Source Category. Office of Air Quality Planning and Standards. Office of Air and Radiation. U.S. Environmental Protection Agency (U.S. EPA). 2010e. 40 CFR Part 98 Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas S ys tems; Final Rule . Federal Register Vo l. 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 G as Tailoring Rule . Federal Register Vol. 75, No. 106 , June 3, 2010 . 31514 - 31608 <http://www.gpo.gov/fds ys /pkg/FR - 2010 - 06 - 03/pdf/2010 - 11974.pdf#page=1 > Accessed March 30, 2011. U.S. Environmental Protection Agency (U.S. EPA). 2011 a . 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 Analysi s **:** National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters. Office of Air Quality Planning and Standards, Research Triangle Park, NC. February . <http://www.epa.gov/ttn/ecas/regdat a/RIAs/boilersriafinal110221_psg.pdf >. Accessed March 30, 2011.4 - 40

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. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990
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21, 2011. U.S. Environmental Protection Agency (U.S. EPA). 2011g. Regulatory Impact Analysis for the Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States; Correction of SIP Approvals for 22 States. Office of Air Quality Planning and Standards, Research Triangle Park, NC. July . <http://www.epa.gov/airtransport/pdfs/FinalRIA.pdf>. Accessed February 10, 2012. U.S. Environmental Protection Agency (U.S. EPA). 2012. Residual Risk Assessment for the Oil and Gas Production and Natural Gas Transmission and Storage Source Categories . Office of Air Quality

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— Science Advisory

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- g.pdf>. Accessed March 30, 2011. U.S. Environmental Protection Agenc y — 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>. Acce ssed March 30, 2011. West et al. 2006. “Global health benefits of mitigating ozone pollution with methane emission controls.” PNAS 103:11:3988 - 3993. West, J.J., A.M. Fiore . 2005 . “ Management of tropospheric ozone by reducing methane emissions. ” Environ Sci Technol , 39:4685 - 4691. Wild, O., et al. 2011 . “Modelling future changes in surface ozone: a parameterized approach,” Atmos. Chem. Phys. Discuss ., 11, 27547

–27590.5 - 1 **5 STATUTORY AND EXECUT**  **IVE O RDER**  **REVIEWS 5.1**  **Executive Order 12866, Regulatory Pla nning and Review and Executive Order**  **13563, Improving Regulation and Regulatory Review** Under section 3(f)(1) Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an “economically

significant regulatory

action” because it is likel y to have an annual effect on the econom y of $100 million or more. Accordingly, the EPA submitted this action to the Office of Management and Budget ( OMB ) for review under Executive Orders 12866 and 13563 (76 FR 3821, January

21, 2011) and an y changes made in respon se to OMB recommendations have been documented in the docket for this action. In addition, the EPA prepared an anal ys is 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 anal ys is for these final rules.5 - 2

**Table 5**  **- 1**  **Summary of the Monetized Benefits, Costs, and Net Benefits for the Fi**  **nal Oil**  **and Natural Gas NSPS and NESHAP Amendments**  **in 2015 (millions of 2008$) 1**  **NSPS NESHAP**  **Am endm**  **ents NSPS and**  **NESHAP Am**  **endments Combined**  Total Monetized Benefits 2 N/A N/A N/A Total Costs 3 - $ 18 million4 $18 million - $ 61 ,000 Net Benefits N/A N/A N/A Non - monetized Benefits 19 ,000 tons of HAP 1,3 00 tons of HAP 20 ,000 tons of HAP 290 ,000 tons of VOC 9,0 00 tons of VOC 300 ,000 tons of VOC 1.7 million tons of methane 4,8 00 tons of methane 1.7 million tons of methane Health effects of HAP exposure 5 Health effects of HAP exposure Health effects of HAP exposure 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 HAP , ozone, and particulate matter (PM) as well as climate effects associated with methane, we have determined that quantification of those benefits and co - benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits or co - benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefi ts, including an increase of 1.2 mi llion tons of carbon dioxide (CO 2 ), 630 tons of nitrogen oxides NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as w ell as emission reductions associated with the energy system impacts. The specific control technologies for the NESHAP is anticipated to have minor secondary disbenefits, including an increase of 5,500 tons of 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 impact s. The net CO 2 - equivalent emission reductions are 31 million metric tons. 3 T he engineering compliance costs are annualized using a 7 percent discount rat e. 4 The negative cost for the NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the final NSPS. Possible explanations for why there appear to be negative cost control technologies are discussed in the engineering costs analysis section in the RIA. 5 For the NSPS, reduced exposure to HAP and climate effects are co - benefits. For the NESHAP, reduced VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co - benefits.5 - 3

**5.2 Paperwork Reduction Act**  The information collection requirements in this rule have been submitted for approval to OMB under the PRA , 44 U.S.C. 3501, et seq . The ICR document prepared by EPA has been assigned EPA I CR number 1716.07 . **[Note: The summary of the results of the ICR and supporting statement will be provided.]** An agency

may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When these I CRs are approved b y OMB, the agency will publish a technical amendment to 40 CFR part 9 in the Federal Register to display the OMB control numbers for the approved information collection requirements contained in the final rule. **5.3 Regulatory Flexibil**  **ity Act** The Regulatory

Flexibility

Act generally

requires an agency

to prepare a regulatory flexibility anal ys is of an y rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or an y other statute, unless the agen cy certifies that the rule will not have a significant economic impact on a substantial number of small entities (SI SNOSE). Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impact of this rule on small entities, a small entity is defined as: (1) A small business whose parent company has no more than 500 employees (or revenues of less than $7 million for firms that transport natural gas via pipeline); (2) a small governmental jurisdiction that is a government of a city , county, town, school district, or special district with a population of less than 50,000; and (3) a small organization that is any not - for profit enterprise which is independentl y owned and operated and is not dom inant in its field. For the final NSPS, the EPA performed an analy sis for impacts on a sample of expected affected small entities by comparing compliance costs to entity revenues. Based upon the anal ys is in the RIA, which is in the Docket, when revenue from additional natural gas product recovered is not included, we estimate that 120 of the 127 small firms anal yzed (94 percent) are likely to have impacts less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, seven firms (6 percent) are likely to have impacts greater than 1 percent.5 - 4

Three of these seven firms are likel y to have impacts greater than 3 percent. However, when revenue from additional natural gas product recovery is included, we estimate that none of the anal yz ed firms will have an impact greater than 1 percent. For the final NESHAP Amendments, we estimate that 54 of the 108 firms (50 percent) that own potentially

affected facilities are small entities. The EPA performed an analy sis for impacts on all expected affected small entities by comparing compliance costs to entity revenues. Among the small firms, 45 of the 54 (83 percent) are likel y to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, nine firms (17 percent) are likely

to have impacts greater than 1 percent. Three of these nine firms are likely to have impacts greater than 3 percent. While these nine firms might receive significant impacts from the final NESHAP amendments, they represe nt 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 NAI CS 211. After considering the economic impact of the combined NSPS and NESHAP amendments on small entities, Icertify this a ction will not have a SI SNOSE. While both the NSPS and NESHAP amendment would individually result in a no SISNOSE finding, the EPA performed an additional anal ys is in order to certify the rule in its entirety . This analy sis compared compliance costs to ent ity revenues for the total of all the entities affected by the NESHAP amendments and the sample of entities anal yz ed for the NSPS. When revenues from additional natural gas product sales are not included, 153 of the 169 small firms (91 percent) in the samp le are likely

to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, 16 firms (9 percent) are likely to have impacts greater than 1 percent. Six of these 16 firms are likely to have impacts great er than 3 percent. When revenues from additional natural gas product sales are included, 160 small firms (95 percent) in the sample are likely

to have impacts of less than 1 percent. Nine firms (5 percent) are likely to have impacts greater than 1 percent, while only three of these nine are likely to have impacts greater than 3 percent. Our determination is informed by the fact that many

affected firms are expected to receive revenues from the additional natural gas and condensate recovery engendered b y the implementation of the controls evaluated in this RIA. As much of the additional natural gas recovery is estimated to arise from completion - related activities, we expect the impact on well related compliance costs to be significantly mitigated. This conc lusion is enhanced because the5 - 5

returns to REC activities occur without a significant time lag between implementing the control and obtaining the recovered product, unlike many control options where the emissions reductions accumulate over long periods of t ime; the reduced emission completions and recompletions occur over a short span of time, during which the additional product recovery is also accomplished. Although this final rule will not impact a substantial number of small entities, the EPA, nonethele ss, 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 b y law. **5.4 Unfunded Mandates Reform Act**  This final action does not contain a federal mandate under the provisions of Title III of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531 - 1538 for state, local, and tribal governments, in the aggregate, or to the private sector. The action would not result in expenditures of $100 million or more for st ate, local, and tribal governments, in the aggregate, or to the private sector in any 1 year. Thus, this final rule is not subject to the requirements of sections 202 or 205 of UMRA. This final rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory

requirements that might significantly or uniquel y affect small governments because it contains no requirements that apply to such governments nor does it impose obligations upon them. **5.5 Executive Order 13132: Federali**  **sm** This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. These final rules primarily affect private industry , and do not impose significant economic costs on state or local governments. Thus, Executive Order 13132 does not apply

to this action.5 - 6

**5.6 Executive Or**  **der 13175: Consultation and Coordination with Indian Tribal Governments**  This action does have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000) because the growth of the oil and gas production industry in Indian c ountry . As a result, EPA conducted earl y outreach to the tribes, prior to proposal in 2010. We met with the Inter Tribal Environmental Council, which include many of the Region VI tribes, The Tribal leadership summit in Region X, and Tribal Energy Confer ence hosted by

Ft. Belknap, and the National Tribal Forum. After the Proposal was published letters were sent to all tribal leaders offering to consult on the rule. An outreach and consultation call was held on October 12, 2011. Tribes that participate d on this call were: Fond du Lac Band of Lake Superior Chippewa, Fort Belknap Indian Community , Forest County Potawatomi Community , Southern Ute Indian Tribe, and Pueblo of Santa Clara. All these tribes counted this as information only , not consultation. There were no issues raised during this call. The tribes were listening to the presentation and the call was ended without comment. In this meeting the tribes were presented the information in the proposal then asked general clarifying questions but did not provide specific comments. Comments on the proposal were received from an affiliate of the Southern Ute Indian Tribe. The commenter expressed concern about the impacts of the rule on natural gas and oil production operations on the Southern Ute Indian reservation and requested additional time to evaluate the impacts. In response to this and other requests, the comment period was extended. More specific comments can be found in the docket. **5.7 Executive Order 13045: Protection of Children from Environme**  **ntal Health Risks and Safety Risks**  This action is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it is not economically significant as defined in Executive Order 12866, and because the EPA does not believe the environmental heal th or safety risks addressed b y this action present a disproportionate risk to children. This action would not relax the control measures on existing regulated sources. The EPA’s risk assessments (i ncluded in the docket for this rule) demonstrate5 - 7

that the existing regulations are associated with an acceptable level of risk and provide an ample margin of safety

to protect public health. **5.8 Executive Order 13211: Actions Concerning Regulations That Significantly Affect**  **Energy Supp ly, Distribution, or Use**  This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28,355, May

22, 2001), because it is not likely to have a significant adverse effect on the supply , distribution, or use of energy . The se final rules will result in the addition of control equipment and monitoring s ys tems for existing and new sources within the oil and natural gas industry . The final NESHAP Amendments are unlikely to have a significant adverse effect on the supply , distribut ion, or use of energy . As such, the final NESHAP Amendments are not “significant energy

actions” as defined in Executive Order 13211, (66 FR 28355, May 22, 2001). The final NSPS is also unlikely to have a significant adverse effect on the supply , distribution, or use of energy . As such, the final NSPS is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001). The basis for the determination is as follows. W e use the NEMS to estimate the impacts of the final NSP S on the United States energy sy stem. The NEMS is a publically available model of the United States energy econom y developed and maintained by the Energy

Information Administration of the U.S. DOE and is used to produce the Annual Energy Outlook, a referen ce publication that provides detailed forecasts of the United States energy econom y. E mission 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 av erted methane emissions can be directed into natural gas production streams and sold. One pollution control requirement of the final NSPS also captures saleable condensates. The revenues from additional natural gas and condensate recovery are expected to offset the costs of implementing the final NSPS. The anal ys is of energy

impacts for the final NSPS that includes the additional product recovery shows that domestic natural gas produc tion is estimated to increase (about 60 billion cubic feet or 0.3 perce nt) and natural gas prices to decrease ($0.05/Mcf or 1.1 percent at the5 - 8

wellhead for producers in the lower 48 states) in 2015, the year of anal ys is. Domestic crude oil production is not estimated to change, while crude oil prices are estim ated to decrease slightl y ($0.01 /barrel or less than about 0.0 1 percent at the wellhead for producers in the lower 48 states) in 2015, the year of anal ysis. All prices are in 2008 dollars. Additionally , the NSPS establishes several performance standards that give regulated entities flexibility

in determining how to best comply with the regulation. In an industry that is geographically

and economically

heterogeneous, this flexibility is an important factor in reducing regulatory

burden. **5.9 National Technology Transfer**  **and Advancement Act** Section 12(d) of the NTTAA of 1995, Public Law 104

– 113, 12(d) (15 U.S.C. 272 note) directs the EPA to use VCS in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards ( e.g ., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted b y VCS bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the EPA decides not to use available and applicable VCS. This final action does not involve technical standards. Therefore, the EPA is not considering the use of any VCS. **5.10 Executive Order 12898: Federal Actions to Address Environmental Justice in**  **Minorit y Populations and Low**  **- Income Populations**  Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on EJ. Its main provision directs Federal agencies, to the greatest extent practicable and permitted by

law, to make EJ part of their mission by identifying and addressing, as appropriate, disproportionately

high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low income populations in the United States. The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low - income populations because it increases the level of environmental protection for all affected populatio ns without having any5 - 9

disproportionately

high and adverse human health or environmental effects on any population, including an y minority, low - income, or indigenous populations. To examine the potential for any environmental justice issues that might be associated with each source category, we evaluated the percentages of various social, demographic, and economic groups within the at - risk population living near the facilities where these source categories are located and compared them to national averages . The development of demographic anal ys es to inform the consideration of environmental justice issues in EPA rulemakings is an evolving science. The EPA conducted a demographic anal ys is, focusing on populations within 50 km of any facility in each of the source categories that are estimated to have HAP exposures which result in cancer risks of 1 - in - 1 million or greater or non - cancer hazard indices of 1 or greater based on estimates of current HAP emissions. The results of this anal ys is are documented in the technical report: Risk and Technology Review

– Analy sis of Socio - economic Factors for Populations L iving Near Oil & Natural Gas Production Facilities located in the docket for this rulemaking. As described in the preamble, our risk assessments demonstrate that the regulations for the oil and natural gas production and natural gas transmission and storage source categories, are associated with an acceptable level of risk and that the additional requirements will provide an ample margin of safety t o prot ect public health. Our anal ys es 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 dete rmined that, although there may be an existing disparity in HAP risks from these sources between some demographic groups, no demographic group is exposed to an unacceptable level of risk. EPA defines “Environmental Justice” to include meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and polices. To promote meaningful involvement, EPA conducted three public hearings on the proposal. The hearings were held in Pittsburgh, PA on September 27, 2011, Denver, CO on September 28, 2011 and Arlington, TX on September 29, 2011. A total of 261 people spoke at the three hearings and 735 people attended the hearings. The attendees at the hearings included private citizens, community-5 - 10

based and environmental organizations, industry representatives, associations representing industry and local and state government officials. **5.11 Congressional Review Act**  U.S.C. 801, et seq ., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally

provides that, before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a cop y of the rule, to each House of the Congress and to the C omptroller General of the United States. The EPA will submit a report containing this final rule and other required information to the United States Senate, the United States House of Representatives, and the Comptroller General of the United States prior to publication of the final rule in the Federal Register . A major rule cannot take effect until 60 day s after it is published in the Federal Register . This action is not a “major rule” as defined by 5 U.S.C. 804(2).6 - 1 **6 COMPARISON OF BENEFI**  **TS AND**  **C OSTS**  Because we are unable to estimate the monetary value of the emissions reductions from the rule, we have chosen to rely upon a break - even anal ys is to estimate what the monetary value benefits would need to attain in order to equal the costs estimated to be imposed by the rule. A break - even anal ys is 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 analy sis or even a net benefits analy sis , we feel the results are illustrative, particularl y in the context of previous ly modeled benefits . The total engineering cost of the final NSPS in the anal ys is year of 2015 when the additional natural gas and condensate recovery is included in the anal ys is is estimated at - $18 million . EPA anticipates that this rule would prevent 290,000 tons of VOC, 1.7 million tons of methane, and 19,000 tons of HAP in 2015 from new sources. In 2015, EPA estimates the costs for the NESHAP Amendments to be 18 million. 52 EPA anticipat es that this rule would reduce 9,0 00 tons of VOC , 4,8 00 tons of methane, and 1, 3 00 tons of HAP in 2015 from existing sources. For the NESHAP Amendments , a break - even analy sis suggests that HAP emissions would need to be valued at $14 ,000 per ton for the b enefits to exceed the costs if the health benefits , and ecos ys tem 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 wo uld need to be valued at $1,9 00 per ton or the methane emissions would need to be valued at $3,7 00 per ton for the benefits to exceed the costs. All estimates are in 2008 dollars. For the final NSPS, the revenue from additional natural gas recovery alrea dy exceeds the costs, which renders a break - even analy sis unnecessary . However, as discussed in Section 3.2.2., estimates of the annualized engineering costs that include revenues from natural gas product recovery depend heavil y upon assumptions about the price of natural gas and hydrocarbon condensates in anal ys is year 2015. Therefore, we have also conducted a break - even analy sis for the price of natural gas. For the NSPS, a break - even anal ys is suggests that the price of natural

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

gas would need to be at l east $3.7 9 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 $4.22 per Mcf in 2015. In addition to the revenue from product recovery , the NSPS would avert emissions of VOC, HAP , and methane, which all have value that could be incorporated into the break- even anal ys is. Figure 6 - 1 illustrates one method of analyzing the break - even point with alternate natural gas prices and VOC benefits. If, as an illustrative example, the price of natural gas was only $3.00 per Mcf, VOC would need to be valued at $220 per ton for the benefits to exceed the costs. All estimates are in 2008 dollars.

**Figure 6**  **- 1**  **Illustrative Break -**  **Even Diagram for Al ternate 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 benefits of VOC emissions are valued at $280 to $7,000 per ton across a range of eight urban areas. 53 In addition, ozone benefits have been previousl y valued at $240 to $1,000 per ton of VOC reduce d.

53 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.

$( 1,000) $( 900) $( 800) $( 700) $( 600) $( 500) $(400) $( 300) $(200) $( 100) $
- $100 $200 $300 $400 $500 $600

$
- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 **VOC Cos**  **t -**  **ef fe**  **ctiv en**  **ess ($**  **/to n**  **red uc**  **tio n)**  NaturalG as Pri ce ($ /Mcf) in 2 015

EIA Fore ca st Pri ce in 2 015 ($ 4.22/Mc f) RIA Assume d Pri ce in 2 015 ($ 4.00/Mc f

) Cost Ef fect iv en es s as Functi on of Natural Gas Pri ce Assum ptio n6 - 3

Using the GWP approach, the climate co - benefits range from approximately $110 to $1,400 per short ton of methane reduced depending upon the discount rate assumed with a per ton estimate of $760 at the 3 percent discount rate. These break - even benefit - p er - ton estimates assume that all other pollutants have zero value. Of course, it is inappropriate to assume that the value of reducing any of these pollutants is zero. Thus, the real break - even estimate is actually lower than the estimates provided above because the other pollutants each have non - zero benefits that should be considered. Furthermore, a single pollutant can h ave multiple effects (e.g., VOC contribute to both ozone and PM 2.5 formation that each have health and welfare effects) that would ne ed to be summed in order to develop a comprehensive estimate of the monetized benefits associated with reducing that pollutant. As previously

described, the revenue from additional natural gas recovery already exceeds the costs of the NSPS, but even if the price of natural gas was only $3.00 per Mcf, it is likely that the VOC benefits would exceed the costs, As a result, even if VOC emissions from oil and natural gas operations result in monetized benefits that are substantially below the average modeled benefits , there is a reasonable chance that the benefits of these rules would exceed the costs, especially if we were able to monetize all of the benefits associated with ozone formation, visibility , HAP , and methane. Table 6 - 1 and Table 6 - 2 present the summary of the benefits, costs, and net benefits for the NSPS and NESHAP Amendments , respectively. Table 6 - 3 provi des a summary of the direct and secondary emissions changes for each rule .6 - 4

**Table 6**  **- 1**  **Summary of**  **the Monetized Benefits, Costs, and Net Benefits for the**  **Fi nal**  **Oil and Natural Gas NSPS in 2015 (millions of 200**  **8$) 1**  **Final 4**  Total Monetized Benefits 2 N/A Total Costs 3 - $1 8 million Net Benefits N/A Non - monetized Benefits 19,000 tons of HAP 5 290,000 tons of VOC 1.7 million tons of methane Health effects of HAP exposure 5 Health effects of PM 2.5 and ozone exposure

Visibility impairment Vegetation effects 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 HAP , ozone, and particulate matter (PM) as well as climate effects associated with methane, we have determined that quantification of those benefits and co - benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits or co - benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefi ts, including an increase of 1.2 million to ns of carbon dioxide (CO 2 ), 630 tons of nitrogen oxides NOx, 19 tons of PM, 3,400 tons of CO, and 1,300 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO 2 - equivalent (CO 2 - e ) emission redu ctions are 31 million metric tons **.** 3 T he engineering compliance costs are annualized using a 7 percent discount rat e. 4 The negative cost for the NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the final NSPS. Possible explanations for why there appear to be negative cost control technologies are discussed in the engineering costs analysis section in the RIA. 5 Reduced exposure to HAP and climate effects are co - benefits.6 - 5

**Table 6**  **- 2**  **Summary of the Monetized Benefits,**  **Costs, and Net Benefits for the Fi**  **nal Oil**  **and Natural Gas NESHAP Amendments**  **in 2015 (millions of 2008$) 1**  **Final** Total Monetized Benefits 2 N/A Total Costs 3 $18 million Net Benefits N/A Non - monetized Benefits 1,3 00 tons of HAP 9,0 00 tons of VOC 4 4,8 00 tons of methane 4 Health effects of HAP exposure Health effects of PM 2.5 and ozone exposure 4

Visibility impairment4 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 HAP , ozone, and PM as well as climate effects associated with methane, we have determined that quantification of those benefits and co - benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefits or co - ben efits 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 specifi c control technologies for the 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 total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO 2 - equivalent emission reductions are 90,000 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 rat e . 4 Reduced exposure to VOC emissions, PM 2.5 and ozone exposure, visibility and vegetation effects, and climate effects are co - benefits.6 - 6

**Table 6**  **- 3**  **Summary of Emissions Changes for the Final**  **Oil and Gas NSPS and NESHAP in 2015**  **(short tons per year) Pollutant**  **NSPS NESHAP**  **Change in Direct Emissions** VOC - 290,000 - 9,000 Methane - 1,700,000 - 4,800 HAP - 19,000 - 1,300
**Change in Secondary Emissions (Producer -**  **Side) 1**  CO 2 1,200,000 5,500 NOx 630 2.9 PM 19.0 0.1 CO 3,400 16 THC 1,300 6.0 **Change in Secondary Emissions (Consumer -**  **Side)** CO 2 - e 600,000 N/A **Net Change in CO 2**  **- equivalent Emissions**  CO 2 - e - 34,000,000 ( ≈ 31,000,000 metric tons) - 95,000

( ≈ 90,000 metric tons)7 - 1

**7 ECONOMIC IMPACT ANAL**  **YSIS AND DISTRIBUTIONAL ASSES**  **SMENTS**
**7.1 Introduction**  This section include s three sets of anal ys es for both the NSPS and NESHAP Amendments :
 Energy

Sy stem Impacts

 Employ

ment Impacts

 Small Business Impacts Analy sis **7.2 Energy System Impacts**  **Analysis of Final**  **NSPS** We use the National Energy Modeling S ys tem (NEMS) to estimate the impacts of the final NSPS on the U.S. energy s ys tem. The impacts we estimate include changes in drilling activity , price and quantity changes in the production and consumption of crude oil and natural gas, and changes in international trade of crude oil and natural gas. We evaluate whether and to what extent the increased production costs imposed by the NSPS might alter the mix of fuels consumed at a national level. With this information w e 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 emissions from energy

sources and emissions co - redu ctions of methane from the engineering analy sis with NEMS analy sis to estimate the net change in CO 2 - equivalent greenhouse gas emissions from energy- related sources, but this analy sis is reserved for the secondary environmental impacts anal ys is within Sect ion 4. A brief conceptual discussion about our energy s ys tem impacts modeling approach is necessary before going into detail on NEMS, how we implemented the regulatory impacts, and results. Economicall y, it is possible to view the recovered natural gas as an explicit output or as contributing to an efficiency gain at the producer level. For example, the analy sis for the final NSPS shows that about 93 percent of the natural gas captured b y emissions controls suggested by the rule is captured by performing RECs on new and existing wells that are completed after7 - 2

being h ydraulicall y 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 well head, and producers are paid based upon this metered production. Depending on the situation, the gas captured by RECs is sent through a temporary or permanent meter. Pay ments for the gas are typically made within 30 days. To preview the energy

s ystems modeling using NEMS, results show that after economic adjustments to the new regulations are made b y producers, the captured natural gas represents both increased output (a slight increment in aggregate production) and increased efficiency (producing slightly

more for less). However, because of differing objectives for the regulatory anal ys is we treat the associated savings differentl y in the engineering cost analy sis (as an explicit output) and in NEMS (as an efficiency gain). In the engineering cost anal ys is, it is necessary to estimate the expected costs and revenues from implementing emissions controls at the unit level. Because of this, we estimate the net costs as expected costs minus expected revenues for representative units. On the other hand, NE MS 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 accordingl y. While in the regulatory case natural gas drilling has become more efficient because of the gas recovery , project developers still interact with markets for which supply and demand are simultaneously adjusting. C onsequently , project development adjusts to a new equilibrium. While we believe the cost savings as measured b y revenues from selling recovered gas (engineering costs) and measured b y cost savings from averted production through efficiency gains (energy

e conomic modeling) are approximately the same, it is important to note that the engineering cost anal ys is and the national - level cost estimates do not incorporate economic feedbacks such as suppl y and demand adjustments. **7.2.1 Description of the Department of En**  **ergy National Energy Modeling System** NEMS is a model of U.S. energy econom y developed and maintained b y the Energy In formation 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 energy7 - 3

econom y from the current year to 2035. DOE first developed NEMS in the 1980s, and the model has been undergone frequent updates and expansion since. DOE uses the modeling sy stem extensively

to produce issue repo rts, legislative anal ys es, and respond to Congressional inquiries. EIA is legally

required to make the NEMS s ys tem s ource code available and fully documented for the public. The source code and accompanyi ng 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 dy

n amics of energy

markets and their interactions with the broader U.S. economy . The s ys tem 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 el ectricity generation, and the quantity and prices for final consumption across sectors and regions. The dynamics of the energy s ys tem are governed b y assumptions about energy and environmental policies, technological developments, resource supplies, demograph y, and macroeconomic conditions. An overview of the model and complete documentation of NEMS can be found at <http://www.eia.doe.gov/oiaf/aeo/overview/index.html >.7 - 4

**Figure 7**  **- 1**  **Organization of NEMS Modules (source: U.S. Energy Information**  **Administration)** NEMS is a large - scale, deterministic mathematical programming model. NEMS iteratively

solves multiple models, linear and non - linear, usin g nonlinear Gauss - Seidel methods (Gabriel et al. 2001) . What this means is that NEMS solves a single module, holding all else constant at provisional solutions, then moves to the next model after establishing an updated provisional solution. NEMS provid es 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 analy sis focuses upon estimated impacts in the year 2015, with regulatory costs first imposed in 2011. For this RIA, we draw upon the same assumptions and model used in the Annual Energy

Outlook 2011. 54 The RIA baseline is consistent with that of the Annual Energy Outlook 2011 which is used extensively in Section 2 in the Indu stry Profile.

54 Assumptions for the 201 1 Annual Energy Outlook can be found at < http://www.eia.gov/forecasts/aeo/assumptions/index.cfm>.7 - 5

**7.2.2 Inputs to National Energy Modeling System**  To model potential impacts associated with the NSPS, we modified oil and gas production costs within the Oil and Gas Suppl y 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, Alaskan wells, as well as having a smaller - scale treatment of Canadian oil and gas production (U.S. EIA, 2010). Th e 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 is 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 govern finding and success rates and costs . The struc ture of the OGSM is amenable to anal yz ing potential impacts of the Oil and Natural Gas NSPS. We are able to target additional expenditures for environmental controls required b y the NSPS on new exploratory and developmental oil and gas production activiti es, as well as add additional costs to existing projects. We model the impacts of additional environmental costs, as well as the impacts of additional product recovery. We explicitly model the additional natural gas recovered when implementing the NSPS . However, we are unable to explicitly model the additional production of condensates expected to be recovered b y reduced emissions completions, although we incorporate expected revenues from the condensate recovery in the economic evaluation of new drillin g 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 transmission and distribution network captured in the NGTDM. The NGTDM balances gas supp lies and prices and “negotiates” supply

and consumption to determine a regional equilibrium between suppl y, demand and prices, including imports and exports via pipeline or LNG. Natural gas transmitted through a simplified arc - node representation of pipel ine infrastructure based upon pipeline economics .7 - 6

7.2.2.1 Compliance Costs for Oil and Gas Exploration and Production As the NSPS affects new emissions sources, we chose to estimate impacts on new exploration and development projects b y adding costs of environmental regulation to the algorithm that evaluates the profitability of new projects. Additional NSPS costs associated with reduced emission completions and future recompletions for new wells are added to drilling, completion, and stimulation costs, as these are, in effect, associated with activities that occur within a single time period, although they may be repeated periodicall y, as in the case of recompletions. Costs required for reduced emissions recompletions on existing wells are added to sti mulation expenses for existing wells exclusively. Other costs are operations and maintenance - ty

pe 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 additio nal product recovery . This approach is appropriate given the structure of the NEMS algorithm that estimates the net present value of drilling projects. One concern in basing the regulatory costs inputs into NEMS on the net cost of the compliance activity (estimated annualized cost of compliance minus estimated revenue from product recovery) is that potential barriers to obtaining capital may not be adequatel y incorporated in the model. However, i n general, potential barriers to obtaining additional capit al should be reflected in the annualized cost via these barriers increasing the cost of capital. With this in mind, assuming the estimates of capital costs and product recovery are valid, the NEMS results will reflect barriers to obtaining the retired cap ital. A caveat to this is that the estimated unit - level capital costs of controls which are newly required at a national - level as a result of the regulation

—RECs, for example

—

may not incorporate potential additional transitional costs as the supply

of control equipment adjusts to new demand. Table 7 - 1 shows the incremental O&M expenses that accrue to new drilling projects as a result of producers having to comp ly with the NSPS . We estimate those costs as a function of new wells expected to be drilled in a representative year. To arrive at estimates of the per well7 - 7

costs, we first identify

which emissions reductions will apply primaril y to crude oil wells, to natural gas wells, or to both crude oil and natural gas wells. Based on the baseline projections of successful completions in 2015, we used 19,097 new natural gas wells and 12,193 new oil wells as the basis of these calculations. We then divide the estimated co mpliance costs for the given emissions point (from Table 3 - 3 ) b y the appropriate number of expected new wells in the year of anal ys is. The result yields an approximation of a per well compliance costs. We assume this approximation is representative o f the incremental cost faced b y a producer when evaluating a prospective drilling project. Like the engineering analysis, we assume that hydraulicall y 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 anal ys is assumed that o ne in one hundred new wells drilled after the implementation of the promulgation and implementation of the NSPS are completed using h ydraulic fracturing will receive a recompletion in any given ye ar using h ydraulic fracturing. Meanwhile, within NEMS, wells are assumed to be stimulated every five years. We assume these more frequent stimulations are le ss intensive than stimulation using h ydraulic fracturing but add costs such that the recompletions costs reflect the same assumptions as the engineering anal ys is. In entering compliance costs into NEMS, we also account for reduced emissions completions, c ompletion combustion, and recompletions performed in absence of the regulation, using the same assumptions as the engineering costs analy sis ( Table 7 - 2 ) .7 - 8

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

**Emissions Sources/Points Emissions Control**  **Per Well Costs (2008$)**  **Wells Applied To in NEMS**  **Equipment Leaks** Well Pads Subpart VV Not in Final Oil and Gas Gathering and Boosting Stations Subpart VV Not in Final Gas Processing Plants Subpart VVa $ 14 None Transmission Compressor Stations Subpart VV Not in Final Gas **Reciprocating Com** **pressors** Well Pads Annual Monitoring/ Maintenance Not in Final None Gathering/Boosting Stations AMM $1 0 Gas Processing Plants AMM - $ 26 Gas Transmission Compressor Stations AMM Not in Final Gas Underground Storage Facilities AMM Not in Final Gas **Centrifugal Com pressors**  Processing Plants Dry Seals/Route to Process or Control - $ 37 Gas Transmission Compressor Stations Dry Seals/Route to Process or Control Not in Final Gas **Pneumatic Controllers -**  Oil and Gas Production Lo w Bleed/Route to Process - $69 5 Oil and Gas Natural Gas Transmission and Storage Lo w Bleed/Route to Process Not in Final Gas **Storage Vessels** High Throughput 95% control $1 97 Oil and Gas Lo w Throughput 95% control Not in Final None7 - 9

**Table 7**  **- 2**  **Summa ry of Additional**  **Per Completion/Recompletion Costs (2008$**  **) for Environmental Controls Entered into NEMS** 

**Emissions Sources/Points**  **Emissions Control Per Com** **pletion Costs (2008$)**  **Wells Applied To in NEMS**  **Well Completions** Hydraulically Fractured Gas Wells REC - $ 828 New Tight Sand/ Shale Gas/CBM Conventional Gas Wells Com bustion Not in Final None Oil Wells Com bustion Not in Final None **Well Recompletions** Hydraulically Fractured Gas Wells (post -NSPS wells) REC - $1, 036 Existing Tight Sand/ Shale Gas /Coalbed Methane Hydraulically Fractured Gas Wells (existing wells) REC - $ 1,036 Existing Tight Sand/ Shale Gas /Coalbed Methane Conventional Gas Wells Com bustion Not in Final None Oil Wells Com bustion Not in Final None
7.2.2.2 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 increas e in natural gas industry productivity , ensuring that, within the model, natural gas reservoirs are not decremented by production gains from methane capture. We add estimates of the quantities of methane captured (or otherwise not vented or combusted) to the base quantities that the OGSM model supplies to the NGTDM model. We subdivide the estimates of commercially valuable averted emissions by

region and well ty

pe in order to more accuratel y portray the economics of implementing the environmental technolo gy . Adding the averted methane emissions in this manner has the effect of moving the natural gas supply curve to the right an increment consistent with the technicall y achievable emissions transferred into the production stream as a result of the final NS PS. W ith the exception of recompletions on existing wells, we enter the increased natural gas recovery into NEMS on a per - well basis for new wells, following an estimation procedure7 - 10

similar to that of entering compliance costs into NEMS on a per well basi s for new wells. For the final NSPS , we estimate that natural gas recovery is 5,065 Mcf per well. We make a simplifying assumption that natural gas recovery accruing to new wells accrues to new wells in shale gas, tight sands, and CBM fields. We make th ese assumptions because new wells in these fields are more likel y to satisfy criteria such that RECs are required, which contributed that large majority of potential natural gas recovery . Note that these per well natural gas recovery is lower than the per well estimate when RECs are implemented. The estimate is lower because we account for emissions that are combusted, RECs that are implemented absent Federal regulation, as well as the likelihood that natural gas is used during processing and transmission or reinjected. We treat the potential natural gas recovery associated with recompletions of existing wells differently

in that we estimated the natural gas recovery b y natural gas resource type based on a combination of the engineering anal ys is and produ ction patterns from the 2011 Annual Energy Outlook . We estimate that additional natural gas product recovered by recompleting existing wells to be about 6.9 bcf, with 2.8 bcf accruing to shale gas, 3.4 bcf accruing to tight sands, and 0.8 bcf accruing to CBM, respectively (total may be different due to independent rounding) . This quantity is distributed within the NGTDM to reflect regional production by resource ty

pe. 7.2.2.3 Fixing Canadian Drilling Costs to Baseline Path Domestic drilling costs serve as a proxy for Canadian drilling costs in the Canadian oil and natural gas sub - model within the NGTDM. This implies that, without additional modification, additional costs imposed by a U.S. regulation will also impact drilling decisions in Canada. Changes in international oil and gas trade are important in the analy sis, as a large majority of natural gas imported into the U.S. originates in Canada. To avoid this problem, we fixed Canadian drilling costs using U.S. drilling costs from the baseline scenario. This solution enables a more accurate anal ys is of U.S. - Canada energy trade, as increased drilling costs in the U.S. as a result of environmental regulation serve to increase Canada’s comparative advantage.7 - 11

**7.2.3 Energy System Impacts**  As mentioned earlier, we estimate impacts to drilling activity , reserves, price and quantit y changes in the production and consumption of crude oil and natural gas, and changes in international trade of crude oil and natural gas, as well as whether and to what extent the NSPS might alter the mix of fuels consumed at a national level. In each of these estimates, we present estimates for the baseline year of 2015 and re sults for the NSPS . For context, we provide estimates of production activities in 2011. 7.2.3.1 Impacts on Dri lling Activities Because the potential costs of the NSPS are concentrated in production activities, we first report estimates of impacts on crude oil and natural gas drilling activities and production and price changes at the wellhead. Table 7 - 3 presents estimates of successful wells drilled in the U.S. in 2015, the analy sis year. **Table 7**  **- 3**  **Successful Oil and Gas Wells Dr illed**  **, NSPS Future Scenario, 2015**  **2011 Baseline**  **Under Final NSPS Successful Wells Drilled**  Natural Gas 16,373 19,097 19,139 Crude Oil 10,352 11,025 11,025 **Total 26,725**  **30,122 30,164**  **% Change in Successful Wells Drilled from Baseline**  Natural Gas 0.22% Crude Oil 0.00% **Total 0.14%**  We estimate that the number of successful natural gas wells drilled increases slightly for the final NSPS , while the number of successful crude oil wells drilled does not change. The number of successful natural gas wells drilled is estimated to increase about 0.22 %. Table 7 - 4 presents the forecast of successful wells by well ty pe, for onshore drilling in the lower 48 states. The results7 - 12

show that conventional well drilling is unaf fected by the NSPS , as reduced emission completion and completion combustion requirements are directed not toward wells in conventional reserves but toward wells that are hydraulicall y fractured, the wells in so - called unconventional reserves. The number of successful wells drilled increase in tight sands, shale gas, as well as coalbed methane . **Table 7**  **- 4**  **Successful Wells Drilled by Well**  **Type (Onshore, Lower 48 States )**  **, NSPS Future Scenario, 2015**  **2011 Baseline**  **Under Final NSPS Successful Wells Drilled**  Conventional Gas Wells 7,267 7,607 7,607 Tight Sands 2,441 2,772 2,788 Shale Gas 5,007 7,022 7,030 Coalbed Methane 1,593 1,609 1,627 **Total 16,308**  **19,010 19,052**  **% Change in Successful Wells Drilled from Baseline** Conventional Gas Wells 0.00% Tight Sands 0.58% Shale Gas 0.11% Coalbed Methane 1.12% **Total 0.22%**  Well drilling in tight sands is estimated to increase slightly , about 0.58 percent . Drilling in shale gas is forecast to increase from the base line by 0.11 percent. Wells in CBM reserves are also estimat ed to increase from the baseline by 1.12 percent . 7.2.3.2 Impa cts on Production, Prices, and Consumption Table 7 - 5 shows estimates of the changes in the domestic production of natural gas and crude oil under the NSPS , as of 2015 . Domestic crude oil production is not forecast to change under the NSPS , again because impacts on crude oil drilling of the NSPS are expected to be negligible.7 - 13

**Table 7**  **- 5**  **Annual Domestic Natural Gas and Crude Oil Production**  **, NSPS Future Scenario, 2015**  **2011 Baseline**  **Under Final NSPS Domestic Production**  Natural Gas (trillion cubic feet) 21.05 22.43 22.49 Crude Oil (million barrels/day) 5.46 5.81 5.81 Natural Gas 0.27% Crude Oil 0.00% Natural gas production, on the other hand, increases from the baseline under the NSPS. A main driver for this increase is the additional natural gas recovery engendered by

the control requirements. Another driver for the increases under the NSPS is the increase in natural gas well drilling. For the NSPS , the NEMS anal ys is shown in Table 7 - 5 estimates a 60 bcf increase in domestic natural gas production. This amount is less than the amount estimated in the engineering anal ys is to be captured by emissions controls implemented as a result of the NSPS (approximately 82 bcf). This difference is because NEMS models the adjustment of energy markets to the now relatively more efficient natural gas production sector. At the new natural gas suppl y and demand equilibrium in 2015, the modeling estimates 60 bcf more gas is produced at a relativel y lower wellhead price (which will be presented momentarily). However, at the new equilibrium, producers implementing emissions controls still capture and sell approximately 82 bcf of natural gas. For example, as shown in Table 7 - 4, about 11,400 new unconventional natural gas wells are completed under the final NSPS; using assumptions from the engineering cost anal ys is about RECs required under State regulation s and exploratory wells and relativel y low pressure wells exempted from REC requirements, about 8,750 NSPS - required RECs would be performed on new natural gas well completions, according to the NEMS analy sis , not including the recompletions of existing wel ls . This recovered natural gas substitutes for natural gas that would be produced from the ground absent the rule. In effect, then, about 20 bcf of natural gas that would have been extracted and emitted into the atmosphere is left in the formation for future extraction. As we showed for natural gas drilling, Table 7 - 6 shows natural gas production from onshore wells in the lower 48 states b y typ e of well, predicted for 2015, the anal ys is year.7 - 14

Production from all ty

pes of wells is estimated to increase under the NSPS, with CBM increasing the most at 0.89 percent . **Table 7**  **- 6**  **Natural Gas Production by Well Type (Onshore,**  **Lower 48 States )**  **, NSPS**  **Future Scenario, 2015 2011**  **Baseline Under Final NSPS**  **Natural Gas Production by Well Type (trillion cubic feet)** Conventional Gas Wells 4.06 3.74 3.75 Tight Sands 5.96 5.89 5.93 Shale Gas 5.21 7.20 7.22 Coalbed Methane 1.72 1.67 1.68 **Total 16.95**  **18.51 18.58**  **% Change in Natural Gas Production by Well Type from Baseline** Conventional Gas Wells 0.14% Tight Sands 0.54% Shale Gas 0.24% Coalbed Methane 0.89% **Total** 0.37% Note: Totals may not sum due to independent rounding . Table 7 - 7 presents estimates of national average wellhead natural gas and crude oil prices for onshore production in the lower 48 states, estimated for 2015, the ye ar of anal ys is. Wellhead natural gas and crude oil prices are forecast to decrease under the NSPS . The decrease in wellhead natural gas price form the baseline is attributable largel y to the increased productivity of natural gas wells as a result of capturing a portion o f completion and recompletio n emissions .7 - 15

**Table 7**  **- 7**  **L ower 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS**  **Future Scenario, 2015 2011**  **Baseline Under Final NSPS**  **Lower 48 Average Wellhead Price** Natural Gas (2008$ per Mcf) 4.07 4.22 4.17 Crude Oil (2008$ per barrel) 83.65 94.60 94.59 **% Change in Lower 48 Average Wellhead Price from Baseline** Natural Gas - 1.18% Crude Oil - 0.01%
Table 7 - 8 presents estimates of the price of natural gas to final consumers in 2008 dollars per million BTU. The production p rice decreases estimated as a result of the final NSPS are largel y passed o n 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 pri ce decreases.
**Table 7**  **- 8**  **Delivered Natural Gas Prices by Sector (2008$ per million BTU), 2015, NSPS Future Scenario, 2015**  **2011 Baseline**  **Under Final NSPS Delivered Prices (2008$ per million BTU)**  Residential 10.52 10.35 10.30 Commercial 9.26 8.56 8.51 Industrial 4.97 5.08 5.04 Electric Power 4.81 4.77 4.73 Transportation 12.30 12.24 12.19 **Average 6.76**  **6.59 6.55**  **% Change in Delivered Prices from Baseline** Residential - 0.48% Commercial - 0.58% Industrial - 0.59% Electric Power - 0.84% Transportation - 0.41% **Average -**  **0.61%**7 - 16

Final consumption of natural gas is also estimated to increase in 2015 from the baseline under the NSPS , as is shown on Table 7 - 9 . Like delivered price, the consumption shifts are distributed differentl y across sectors. **Table 7**  **- 9**  **Natural Gas Consumption by Sector, NSPS**  **Future Scenario, 2015 2011**  **Baseline Under Final NSPS**  **Consumption (trillion cubic feet)** Residential 4.76 4.81 4.82 Commercial 3.22 3.38 3.38 Industrial 6.95 8.05 8.06 Electric Power 7.00 6.98 7.00 Transportation 0.03 0.04 0.04 Pipeline Fuel 0.64 0.65 0.65 Lease and Plant Fuel 1.27 1.20 1.21 **Total 23.86**  **25.11 25.16**  **% Change in Consumption from Baseline** Residential 0.21% Commercial 0.00% Industrial 0.12% Electric Power 0.29% Transportation 0.00% Pipeline Fuel 0.00% Lease and Plant Fuel 0.83% **Total 0.20%**  Note: Totals may not sum due to independent rounding . 7.2.3.3 Impacts on Imports and National Fuel Mix The NEMS mode ling estimates that the impact from the NSPS is not sufficiently large to affect the trade balance of natural gas. As shown in Table 7 - 10 , estimates of crude oil imports do not vary from the baseline in 20 15 under the NSPS .7 - 17

**Table 7**  **- 10**  **Net Imports of Natural Gas and Crude Oil , NSPS**  **Future Scenario, 2015 2011**  **Baseline Under Final NSPS**  **Net Imports** Natural Gas (trillion cubic feet) 2.75 2.69 2.68 Crude Oil (million barrels/day) 9.13 8.70 8.70 **% Change in Net Imports** Natural Gas - 0.37% Crude Oil 0.00% Meanwhile, net imports of natural gas are estimated to decrease about 10 bcf (0.37 percent) under the NSPS, as the increased production substitutes for imported natural gas. Table 7 - 11 evaluates estimates of energy consumption by

energy ty pe at the national level for 2015, the ye ar of anal y s is. The NSPS is estimated to have small effects at the national level. W e estimate an increase in 0.03 quadrillion BTU in 2015, a 0.03 percent increase. The percent contribution of natural gas is projected to increase, while the percent contribution of liquid fuels and coal is expected to decrease under the NSPS .7 - 18

**Table 7**  **- 11**  **Total Energy Consumption by Energy Type (Quadrillion BTU) , NSPS**  **Future Scenario, 2015 2011**  **Baseline Under Final NSPS**  **Consumption (quadrillion BTU)** Liquid Fuels 37.41 39.10 39.09 Natural Gas 24.49 25.77 25.82 Coal 20.42 19.73 19.71 Nuclear Power 8.40 8.77 8.77 Hydropower 2.58 2.92 2.92 Biomass 2.98 3.27 3.27 Other Renewable Energy 1.72 2.14 2.14 Other 0.30 0.31 0.31 Total **98.29 102.02**  **102.05 % Change in Consumption from Baseline**  Liquid Fuels - 0.03% Natural Gas 0.19% Coal - 0.10% Nuclear Power 0.00% Hydropower 0.00% Biomass 0.00% Other Renewable Energy 0.00% Other 0.00% **Total 0.03%**  Note: Totals may not sum due to independent rounding . With the national profile of energy consumption estimat ed to change slightly under the NSPS in 2015, the year of anal ys is, 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 anal ys is in Section 4. Here, we present a single NEMS - based table showing estimated changes in energy- related “consumer - side” GHG emissions. We use the terms “consumer - side” emissions to distinguish emissions from the consumption of fuel fro m emissions specificall y associated with the extraction, processing, and transportation of fuels in the oil and natural gas sector under examination in this RIA. We term the emissions associated with extraction, processing, and transportation of fuels “producer - side” emissions.7 - 19

**Table 7**  **- 12**  **Modeled Change in Energy -**  **related "Consumer -**  **Side" CO 2**  **- equivalent GHG**  **Emissions Future Scenario, 2015**  **2011 Baseline**  **Under Final NSPS Energy**  **- related CO**  **2 -**  **equivalent GHG Emissions (million metric tons CO**  **2 -**  **equivalent)** Petroleum 2,359.59 2,433.60 2,433.16 Natural Gas 1,283.78 1,352.20 1,354.69 Coal 1,946.02 1,882.08 1,880.57 Other 11.99 11.99 11.99 **Total 5,601.39**  **5,679.87 5,680.41**  **% Change in Energy**  **- related CO**  **2 -**  **equivalent GHG Emissions from Baseline** Petroleum - 0.02% Natural Gas 0.18% Coal - 0.08% Other 0.00% **Total 0.01%**  Note: Excludes “producer - side” emissio ns and emissions reductions estimated to result from NSPS . Totals may not sum due to independent rounding . As is shown in Table 7 - 12 , the final NSPS is predicted to slightly increase consumer - side aggregate energy- related CO 2 - equi valent GHG e missions by about 540,000 metric tons ( 0.01 percent) , mainly

because consumer - side emissions from natural gas combustion increase slightly more than they

are offset by

reductions in petroleum and coal consumption . **7.3 Employment Impact**  **Analysis** While a standalone anal ysis of employ ment impacts is not included in a standard cost benefit anal ys is, such an anal ys is is of particular concern in the current economic climate of sustained high unemplo yment. Executive Order 13563, states, “ Our regulatory sy stem must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation ” (emphasis added). Therefore, we seek to inform the discussion of labor demand and job impacts by providing an estimate of the employ ment impacts of the regulations using labor re quirements for the installation, operation, and maintenance of control requirements , as well as reporting and recordkeeping requirements .7 - 20

Unlike several recent RIAs, however, we do not provide employ ment 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 mainte nance of control requirements . **7.3.1 Employment Impacts from Pollution Control Requirements**  Regulations set in motion new orders for pollution control equipment and services. New categories of emplo ym ent 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 employ ment in the environmental technology industry have grown steadily between 2000 and 2008, reaching an industry total of approximately

$300 billion in revenues and 1.7 million employees in 2008. 55 While these revenues and employ ment figures represent gains for the envi ronmental 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 employ ment as opposed to workers being shifted from the production of goods and services to environmental compliance activities. Once the equipment is installed, regulated firms hire workers to operate and maintain the pollution control equipment

– much like they hire workers to produce more output. Morgenstern et al. (200 2) examined how regulated industries respond to regulation. They found that environmental regulations can have three distinct effects; the demand effect, the cost effect, and the factor substitution effect ... The authors found that , on average for the industries they studied , employ ment increases in regulated firms . Of course, these firms may also r eassign existing employees to perform these activities.

55 In 2008, the industry totaled approximately $315 billion in revenues and 1.9 million employees including indirect em ployment effects, pollution abatement equipment production employed approximately 4.2 million workers in 2008. These indirect employment eff ects 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?OpenDocument7 - 21

Environmental regulations support employ ment in many

basic industries . In addition to the in crease in emplo ym ent in the environmental protection industry (via increased orders for pollution control equipment), environmental regulations also support employ ment in industries that provide intermediate goods to the environmental protection industry. The equipment manufacturers, in turn, order steel, tanks, vessels, blowers, pumps, and chemicals to manufacture and install the equipment. Bezdek et al. (2008) found that investments in environmental protection industries create jobs and displace jobs , but the net effect on employ ment is positive . T he focus of this part of the anal ys is 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 outsid e of the oil and natural gas sector. This anal ys is estimates the employ ment impacts due to the installation, operation, and maintenance of control equipment, as well as employ

ment associated with new reporting and recordkeeping requirements. It is important to highlight that unlike the ty pical case where to reduce a bad output (i.e., emissions) a firm often has to reduce production of the good output, many of the em ission controls required b y the final NSPS will simultaneously increase production of the good output and reduce production of bad outputs. That is, these controls jointly produce environmental improvements and increase output in the regulated sector . New labor associated with implementing these controls to comply with the new regulations can also be viewed as additional labor increasing output while reducing undesirable emissions . To the extent, however, that these rules require unprofitable investments for some operations, there is the possibility that they may cause fewer completions to be undertaken, and less gas production, thus creating downward pressure on labor demand, both i n the regulated sector and on those sectors using natural gas as an input. This RIA excludes these potential adverse effects on the labor market. No estimates of the labor used to manufacture or assemble pollution control equipment or to supply the materials for manufacture or assembly are included because U.S. EPA does not currentl y have this information. The employ ment analy sis uses a bottom - up engineering - based methodolog y to estimate employ ment impacts . The engineering cost anal ys is summarized in this RIA includes estimates of the labor requirements associated with implementing the regulations. Each of these labor changes may either be required as part of an initial effort to comply with the7 - 22

new regulation or required as a continuous or annual effort to maintain compliance. We estimate up - front and continual, annual labor requirements by estimating hours of labor required and converting this number to full - time equivalents (FTEs) by dividing by

2,080 (40 hours per week multiplied by

52 weeks). We not e that this ty pe of FTE estimate cannot be used to make assumptions about the specific number of people involved or whether new jobs are created for new emplo yees. In other emplo ym ent analy ses U.S. EPA distinguished between employ ment changes within the regulated industry and those changes outside the regulated industry (e.g. a contractor from outside the regulated facility is employed to install a control device). For this regulation however, the structure of the industry makes this difficult. The mix of in - house versus contracting services used by firms is very

case - specific in the oil and natural gas industry . For example, sometimes the owner of the well, processing plant, or transmission pipelines uses in

– house employees extensively in dail y operati ons, while in other cases the owner relies on outside contractors for man y of these services. For this reason, we make no distinction in the quantitative estimates between labor changes within and outside of the regulated sector. The results of this empl oym ent estimate are presented in Table 7 - 13 for the final NSPS and in Table 7 - 14 for the final NESHAP Amendments . The tables breaks down the installation, operation, and maintenance estimates b y type of pollution control evaluated in the RIA and present both the estimated hours required and the conversion of this estimate to FTE. For both the final NSPS and NESHAP Amendments , reporting and recordkeeping requirements were estimated for the entire rules rather than b y anticipated control requirements; the reporting and recordkeeping estimates are consistent with estimates EPA submitt ed as part of its Information Collection Request (I CR). The up - front labor requirement is estimated at 50 FTEs for the final NSPS and about 120 FTEs for the final NESHAP Amendments . These up - front FTE labor requirements can be viewed as short - term labor requirements required for affected entities to comply with the new regulation. Ongoing requirements are estimated at about 1,1 00 FTEs for the final NSPS and about 94 FTEs for the final NESHAP Amendments . These ongoing FTE labor requirements can7 - 23

be viewed as sustained labor requirements required for affected entities to continuously compl y with the new regulation . Two main categories contain the majority of the labor requirements for the final rules: implementing reduced emissions completions (RECs) and reporting and recordkeeping requirements for the final NSPS. Also, note that pneumatic controllers have no up - front or continuing labor requirements. While the controls do require labor for installation, operation, and maintenance, the required labo r is less than that of the controllers that would be used absent the regulation. In this instance, we assume the incremental labor requirements are zero. Implementing RECs are estimated to require about 1,000 FTE, about 88 percent of the total continuing labor requirements for the final NSPS. 56 We denote REC - related requirements as continuing, or annual, as the REC requirements will in fact recur annually, albeit at different wells each ye ar. The REC requirements are associated with certain new well compl etions or existing well recompletions, which while individual completions occur over a short period of time (day s to a few weeks), new wells and other existing wells are completed or recompleted annually . Because of these reasons, we assume the REC - rel ated labor requirements are annual. **7.3.2 Employment Impacts Primarily on the Regulated Industry**  In previous RIAs, we transferred parameters from a study by Morgenstern et al. (2002) to estimate employ

ment effects of new regulations. (See, for example, the Regu latory Impact Analy sis for the finalized Mercury and Air Toxics Standards , promulgated on December 16 , 2011). The fundamental insight of Morgenstern, et al. is that environmental regulations can be understood as requiring regulated firms to add a new outp ut (environmental quality) to their product mixes . Although legally compelled to satisfy

this new demand, regulated firms have to finance this additional production with the proceeds of sales of their other (market) products. Satisfying this new demand req uires additional inputs, including labor, and may alter the relative proportions of labor and capital used b y regulated firms in their production processes.

56 As shown on earlier in this section, we project that the number of successful natural gas wells drilled in 2015 will decline slightly from the baseline projection. Therefore, there may be small employment losses in drilling related employment that partly offset gains in employment from compliance - related activities.7 - 24

Using plant - level Census information between the years 1979 and 1991, Morgenstern et al. estimate the size of each effect for four polluting and regulated industries (petroleum refining , plastic material, pu lp and paper, and steel). On average across the four industries, each additional $1 million (1987$) spending on pollution abatement results in a (statistically insignificant) net increase of 1.5 5 (+/ - 2.24) jobs . As a result, the authors conclude that increases in pollution abatement expenditures d id not necessaril y cause economically s ignificant employ ment changes in those industries at that time . For this version of RIA for the final NSPS and NESHAP Amendments , however, we chose not to quantitatively estimate employ ment impacts using Morgenstern et al. because of reasons specific to the oil and natural gas industry and final rules. We believe the transfer of parameter estimates from the Morgenstern et al. study to the final NSPS and NESHAP Amendments is beyond the range of the study for two reasons.7 - 25

**Table 7**  **- 13**  **Labor -**  **based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and Maintain**  **ing Control Equipment Requirements, NSPS**  **, 2015** 

**Source/Emissions Point Emissions Control**  **Projected No. of**  **Affected Units**  **Per Unit**

**One**   ** tim** **e Labor**  **Estimate (hours)**  **Per Unit**

**Annual Labor**  **Estimate (hours)**  **Total**

**One**   ** Time** **Labor Estimate**  **(hours) Total** 

**Annual Labor**  **Estimate (hours)**  **One -**  **tim e** 

**Full -**  **Time Equivalent**  **Annual**

**Full -**  **Time Equivalent**  **Well Completions and Recompletions** New Hydraulically Fractured Gas Wells Reduced Emissions Com pletion (REC) 8,382 0 218 0 1,823,282 0.0 876.6 Existing Hydraulically Fractured Gas Wells REC 1,085 0 218 0 235,901 0.0 113.4 Hydraulically Fractured Gas Wells Com bustion 1,498 0 22 0 32,327 0.0 15.5 **Equipment Leaks** Processing Plants NSPS Subpart VVA 29 587 887 17,023 25,723 8.2 12.4 **Reciprocating Com pressors**  Gathering/Boosting Stations Annual Monitoring/ Maintenance (AMM) 210 1 1 210 210 0.1 0.1 Processing Plants AMM 209 1 1 209 209 0.1 0.1 **Centrifigal Com pressors**  Processing Plants Dry Seals/Route to Process or Control 13 355 0 4,615 0 2.2 0.0 **Pneumatic Controllers** Oil and Gas Production Lo w Bleed/Route to Process 13,632 0 0 0 0 0.0 0.0 **Storage Vessels** High Throughput 95% control 304 271 190 82,279 57,582 39.6 27.7 **Reporting and Recordkeeping for Complete NSPS** All N/A N/A 0 229,810 0.0 102.5 **TOTAL N/A**  **N/A N/A**  **104,336 2,405,045**  **50.2 1,148.3**  Note: Full - time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may

not sum due to independent rounding.7 - 26

**Table 7**  **- 14**  **Labor -**  **based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and**  **Maintaining Control Equipment Requirements, Final**  **NESHAP Amendments ,**  **2015**

**Source/Emissions Point Em** **issions Control Projected**  **No. of Affected**  **Units Per Unit** 

**One -**  **time Labor**  **Estimate (hours)**  **Per Unit**

**Annual Labor**  **Estimate (hours)**  **Total One**  

** Tim** **e Labor Estimate**  **(hours) Total** 

**Annual Labor**  **Estimate (hours)**  **One -**  **time**

**Full -**  **Time Equivalent**  **Annual**

**Full -**  **Time Equivalent**  **Sm all Glycol Dehydrators**  Production Com bustion devices, recovery devices, process modifications 74 27 285 2,000 21,120 1.0 10.2 Transmission Com bustion devices, recovery devices, process modifications 7 27 285 189 1,998 0.1 1.0 **Storage Vessels** Production Com bustion devices, recovery devices 674 311 198 209,753 133,231 100.8 64.1 **Reporting and Recordkeeping for Complete NESHAP Amendments**  N/A N/A N/A 36,462 39,923 17.5 19.2 **TOTAL 808**  **N/A N/A**  **248,404 196,272**  **119.4 94.4**  Note: Full - time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may

not sum due to independent rounding.7 - 27

First, the possibility

that the revenues producers are estimated to receive from additional natural gas recovery

as a result of the final NSPS might offset the costs of compl yi ng with the rule presents challenges to estimating employ ment effects (see Secti on 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 anal yz e the impact of environmental compliance expenditures on industry employ ment levels, and it may

not be appropriate to draw on their demand and net effect s when compliance costs are expected to be negative. Second, the final regulations primarily affect the natural gas produc tion, processing, and transmission segments of the industry . While the natural gas processing segment of the oil and natural gas industry

is similar to petroleum refining, which is examined in Morgenstern et al., the production side of the oil and natural gas (drilling and extraction, primarily) and natural gas pipeline transmission are not similar to petroleum refining. Because of the likelihood of negative compliance costs for the final NSPS and the segments of the oil and natural gas industry affected by the rules are not examined by Morgenstern et al., we decided not to use the parameters es timated by

Morgenstern et al. to estimate within - industry employ ment effects for the final oil and natural gas NESHAP Amendments and NSPS. That said, the likeliho od of additional natural gas recovery is an important component of the market response to the rule , as it is expected that this additional natural gas recovery will reduce the price of natural gas . Because of the estimated fall in prices in the natural ga s sector due to the final NSPS , prices in other sectors that consume natural gas are likely drop slightly due to the decrease in energy prices. This small production increase and price decrease may have a slight stimulative effect on emplo ym ent in industries that consume natural gas. **7.4 Small Business Impacts Analysis**  The Regulatory

Flexibility

Act as amended b y the Small Business Regulatory Enforcement Fairness Act (SBREFA) generall y requires an agency to prepare a regulatory flexibility analy sis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or an y other statute , unless the agency certifies that the rule will not have a7 - 28

significant economic impact on a substantial number of small entities. Smal l entities include small businesses, small governmental jurisdictions, and small not - for - profit enterprises. After considering the economic impact of the final rule s on small entities for both the NESHAP and NSPS, the anal ys is indicates that these rules wi ll not have a significant economic impact on a substantial number of small entities (or “SI SNOSE”). The supporting analy ses for these determinations are presented in this section of the RIA. As discussed in previous sections of the economic impact anal ys i s, under the final NSPS, some affected producers are likel y to be able to recover natural gas that would otherwise be vented to the atmosphere, as well as recover saleable condensates that would otherwise be emitted. EPA estimates that the revenues from this additional natural gas product recovery will offset the costs of implementing control options implemented as a result of the final NSPS. However, not all components of the final NSPS are estimated to have cost savings. Therefore, we anal yz e potential impacts to better understand the potential distribution of impacts across industry segments and firms. Unlike the controls for the final NSPS, the controls evaluated under the final NESHAP Amendments do not recover significant quantities of natural gas p roducts. **7.4.1 Small Business National Overview**  The industry

sectors covered b y the final rule were identified during the de velopment of the engineering cost analy sis. The U.S. Census Bureau’s Statistics of U.S. Businesses (SUSB) provide s national information on the distribution of economic variables b y industry and 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 anal ys es . 57 Statist ics include the total number of establishments , and receipts for all entities in an industry ; however, man y of these entities may not necessarily

be covered by

the final rule . SUSB also provides statistics by enterprise employ ment and receipt size ( Table 7 - 15 and Table 7 - 16 ) . The Census Bureau ’ s definitions used in the SUSB are as follows:

57 See http://www.census.gov/csd/susb/ and http://www.sba.gov/advocacy/ for additional details.7 - 29  E stablishmen t: A s ingle phy sical 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 emplo ym ent and annual pay roll 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 enterprise is a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single - establishment firms. Each multi - establishment co mpany forms one enterprise

—the enterprise emplo yment and annual pay

roll are summed from the associated establishments. Enterprise size designations are determined by the sum of employ

ment of all associated establishments. Because the SBA ’ s busin ess size d efinitions (SBA, 2008 ) appl y to an establishment ’ s “ultimate parent compan y, ” we assume d in this analy sis that the “firm” definition above is consistent with the concept of ultimate parent company that is ty pically used for SBREFA anal ys es , and the terms are used int erchangeabl y.7 - 30

**Table 7**  **- 15**  **Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007** Owned by Firms with:

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

Em ployees 20 - 99

Em ployees 100 - 499

Em ployees Total <

500 Em ployees > 500

Em ployees Total Firms **Number of Firms by Firm Size** 211111 Crude Petroleum and Natural Gas Extraction 500 5,759 455 115 6,329 95 6,424 211112 Natural Gas Liquid Extraction 500 77 9 12 98 41 139 213111 Drilling Oil and Gas Wells 500 1,580 333 97 2,010 49 2,059 486210 Pipeline Transportation of Natural Gas $7.0 million 63 12 9 84 42 126 **Total Employment by Firm Size**  211111 Crude Petroleum and Natural Gas Extraction 500 21,170 16,583 17,869 55,622 77,664 133,286 211112 Natural Gas Liquid Extraction 500 372 305 1,198 1,875 6,648 8,523 213111 Drilling Oil and Gas Wells 500 5,972 13,787 16,893 36,652 69,774 106,426 486210 Pipeline Transportation of Natural Gas $7.0 million 241 382 1,479 2,102 22,581 24,683 **Estimated Receipts by Firm Size ($1000)** 211111 Crude Petroleum and Natural Gas Extraction 500 12,488,688 15,025,443 17,451,805 44,965,936 149,141,316 194,107,252 211112 Natural Gas Liquid Extraction 500 209,640 217,982 1,736,706 2,164,328 37,813,413 39,977,741 213111 Drilling Oil and Gas Wells 500 1,101,481 2,460,301 3,735,652 7,297,434 16,550,804 23,848,238 486210 Pipeline Transportation of Natural Gas $7.0 million 332,177 518,341 1,448,020 2,298,538 18,498,143 20,796,681 Source: U.S. Census Bureau. 2010 . “Number of Firms, Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterprise Receipt Size for the

United States, All Industries: 2007 . ” <http://www.census.gov/econ/susb/>7 - 31

**Table 7**  **- 16**  **Distribution of Small and Large Firms by Number of Firms, Total**  **Employment, and Estimated Recei pts 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 While the SBA and Census Bureau statistics provide informative broad contextual information on the distribution of enterprises b y receipts and number of employees, it is als o useful to additionally contrast small and large enterprises (where large enterprises are defined as those that are not small, according to SBA criteria) in the oil and natural gas industry . The summary statistics presented in previous tables indicate that there are a large number of relativel y small firms and a small number of large firms. Given the majority of expected impacts of the final rules arises from well completion - related requirements, which impacts production activities, exclusively , some explanation of this particular market structure is warranted as it pertains to production and small entities. An important question to answer is whether there are particular roles that small entities serve in the production segment of the oil and natural gas industry that may be disprop ortionatel y affected by the final rules.7 - 32

The first important broad distinction among firms is whether they are independent or integrated. Independent firms concentrate on exploration and production (E&P) activities, while integrated firms are vertically integrated and often have operations in E&P, processing, refining, transportatio n, and retail. To our awareness, there are no small integrated firms. In dependent firms may

own and operate wells or provide E&P - related services to the oil and gas industry . Since we are focused on evaluating potential impacts to small firms owning and operating new and existing hydraulically fractured wells, we should narrow down on this sector. In our understanding, there is no single industry niche for small entities in the production segment of the industry

since small operators have different bus iness strategies and that small entities can own different ty pes of wells. The organization of firms in oil and natural gas industry also varies greatly

from firm to firm. Additionally , oil and natural gas resources vary widely geographically

and can vary significantly within a single field. Among man y important roles, independent small operators historicall y pioneered exploration in new areas, as well as developed new technologies. By taking on these relativel y large risks, these small entrepreneurs (w ildcatters) have been critical sources of industrial innovation and opened up critical new energy supplies for the U.S. (IHS Global Insight). In recent decades, as the oil and gas industry has concentrated via mergers, many of these smaller firms have bee n absorbed into large firms. Another critical role, which provides an interesting contrast to small firms pioneering new territory , is that smaller independents maintain and operate a large proportion of th e Nation’s low producing wells, which are also k nown as marginal or stripper wells (Duda et al. 2005) . While marginal wells represent about 80 percent of the population of producing wells, they produce about 15 perc ent of domestic production, according to EIA ( Table 7 - 17 ) .7 - 33

**Table 7**  **- 17**  **Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009** Ty pe 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. M any of these wells were likely drilled and initially operated b y major firms (although the data are not available to quantify the percentage of wells initially drilled by

small versus large producers). Well productivity levels typically follow a steep dec line curve; high production in earlier ye ars but sustained low production for decades. Because of relativel y low overhead of maintaining and operating few relatively co - located wells, some small operators with a particular business strategy purchase low p roducing wells from the majors, who concentrate on new opportunities. As small operators have provided important technical innovation in exploration, small operators have also been sources of innovation in extending the productivity

and lifespan of exist ing wells (Duda et al. 2005) . **7.4.2 Small Entity Economic Impact Measures**  The final Oil and N atural Gas NSPS and NESHAP Amendments will affect the owners of the facilities that will incur compliance costs to control their regulated emissions. The owners, either firms or individuals, are the entities that will bear the financial impacts associated with these additional operating costs. The final rule has the potential to impact all firms owning affected facilities, both large and smal l.7 - 34

The anal ys is provides EPA with an estimate of the magnitude of impacts the final NSPS and NESHAP Amendments may have on the ultimate domestic parent companies th at own facilities EPA expects might be impacted by the rules. The anal ys is focuses on small firms because they

may have more difficulty compl yi ng with a new regulation or affording the costs associated with meeting the new stand ard. This section presents the data sources used in the anal ys is, the methodology we applied to develop estimates of impacts, the results of the anal ys is, and conclusions drawn from the results. The small business impacts anal ys is 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 li kely to be associated with NAI CS codes listed in Table 7 - 15 . For both the NSPS and NESHAP Amendments , we obtained firm - level emplo ym ent, revenues, and production leve ls using various sources, including the American Business Directory , the Oil and Gas Journal , corporate websites, and publicall y- available financial reports. Using these data, we estimated firm - level compliance cost impacts and calculated cost - to - revenue ratios to identify small firms that might be significantly

impacts by

the rules. The approaches taken for the NSPS and NESHAP Amendments differed; more detail on approaches for each set of rules is presented in the following sections. For the sales test, we divided the estimates 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 employ s in anal yz ing 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 normall y made available are often not the true profit earned b y firms because of accounting and tax considerations. Revenues as ty pically 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 b y EPA on compliance with SBREFA 58 and is consistent with guidance published b y the U.S. SBA’s Office of Advocacy that suggests that cost as a percentage

58 The SBREFA compliance guidance to EPA rulewriters regarding the types of small business analysis that should be considered can be f

ound at < http://www.epa.gov/sbrefa/documents/r faguidance11 - 00 - 06.pdf>7 - 35

of total revenues is a metric for evaluating cost increases on small entities in relation to increases on large entities (U.S. SBA, 2010) . 59 8 **7.4.3 Small**  **Entity Economic Impact Analysis, Final NSPS** 7.4.3.1 Overview of Sample Data and Methods The fi nal NSPS covers emissions points within various stages of the oil and natural gas production process. We expect that firms within multiple NAI CS codes will be affected, namel y the NAICS categories presented in Table 7 - 15 . Because of the diversity of the firms potentially affected, we decided to analyze three distinct groups of firms within the oil and natural gas industry , while accounting for overlap across the group s. We anal yz e firms that are involved in oil and natural gas extraction that are likely to drill and operate wells, while a subset are integrated firms involved in multiple segments of production, as well as retailing products. We also anal yz e firms that primarily operate natural gas processing plants. A third set of firms we anal yz ed 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 reasonabl y representative of the larger population of public and priv ate firms operating in this segment of the industry . While the proportion of small firm in the OGJ 150 is smaller than the proportion evaluated b y the Census SUSB, the OGJ 150 provides detailed information on the production activities and financial return s of the firms within the list, which are critical ingredients to the small business impacts anal ys is. We drew upon the OGJ 150 lists published for the ye ars 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 relativel y high level of drilling activity because of high fuel prices. Combined, we believe these two ye ars of data are representative.

59 U.S. SBA, Office of Advocacy. A Guide for Government Agencies, How to Com ply with the Regulatory Flexibility Act, Implementing the President’s Small Business Agenda and Executive Order 13272, June 2010 .7 - 36

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 proces sing facilities 60 and other resources, such as the American Business Directory and company

websites, to best identify the parent compan y of the facilities. To identify firms that compress and transport natural gas via pipelines, we examined the periodic OG J 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 . 61 For these firms, we also used the American Business Directory and corporate websites to best ide ntify

the ultimate owner of the facilities or companies. After combining the information for exploration and production firms, natural gas processing firms, and natural gas pipeline transmission firms in order to identify overlaps across the list, the approach yi elded a sample of 274 firms that would potentially be affected b y the final NSPS in 2015 assuming their 2015 production activities were similar to those in 2008 and 2009. We estimate that 127 (46 percent) of these firms are small according to SBA c riteria. We estimate 119 firms (43 percent) are not small firms according to SBA criteria. We are unable to classify the remaining 28 firms (10 percent) because of a lack of required information on employee counts or revenue estimates. Table 7 - 18 shows the estimated revenues for 246 firms for which we have sufficient data that would be potentially

affected by

the final NSPS based upon their activities in 2008 and 2009. We segmented the sample into four groups, production and integrated firms, processing firms, pipeline firms, and pipelines/processing firms. For the firms in the pipelines/processing group, we were unable to determine the firms’ primary line of business, so we opted to group together as a fourth group.

60 Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010. 61 Oil and Gas Journal. “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow .” November 1, 2010.7 - 37

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

Number of Firms Estimated Revenues (millions, 2008 dollars) Firm Type/Size Total Average Median Minimum Maximum Production and Integrated Small 7 7 18, 451.9 23 9 . 6 76.3 0.1 1,116.9 Large 4 7 1,34 5,292 .0 2 8623 .2 1,788.3 12.9 310,586.0 Subtotal 12 4 1,36 3,743.9 10, 997.9 344.6 0.1 310,586.0 Pipeline Small 11 694.5 63.1 4.6 0.5 367.0 Large 36 166,290.2 4,619.2 212.9 7.1 112,493.0 Subtotal 47 166,984.6 3,552.9 108.0 0.5 112,493.0 Processing Small 39 4,972.1 127.5 26.9 1.9 1,459.1 Large 23 177,632.1 8,881.6 2,349.4 10.4 90,000.0 Subtotal 62 182,604.2 3,095.0 41.3 1.9 90,000.0 Pipelines/Processing Small 0 N/A N/A N/A N/A N/A Large 13 175,128.5 13,471.4 6,649.4 858.6 71,852.0 Subtotal 13 175,128.5 13,471.4 6,649.4 858.6 71,852.0 **Total Sm**  **all 12**  **7 24,**  **118.5 18**  **9 .**  **9 34.9**  **0.1 1,459.1**  **Large 1**  **19 1,86**  **4,342.8 16,071.9**  **1,672.1 7.1**  **310,586.0 Total**  **2 46**  **1,8 88**  **, 461.3**  **7, 771.4**  **16 4**  **.9 0.1**  **310,586.0** Sources: Oil and Gas Journal . “OGJ150.” September 21, 2009; Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. Oil and Gas Journal . “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010, with additional analysis to determine ultimate ownership of plants. Oil and Gas Journal . “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow .” November 1, 2010. American Business Directory was used to determine number of employees.
As shown in Table 7 - 18 , there is a wide variety of revenue levels across firm size, as well as across industry

segments. The estimated revenues within the sample are concentrated on integrated firms and firms enga ged in production activities (the E&P firms mentioned earlier).7 - 38

The oil and natural gas industry is capital - intensive. To provide more context on the potential impacts of new regulatory requirements, Table 7 - 19 presents descriptive statistics for small and large integrated and production firms from the sample of firms (117 of the 124 integrated and production firms listed in the Oil and Gas Journal ; capital and exploration expenditures for 7 firms were not reported in the Oil and Gas Journal). **Table 7**  **- 19**  **Descriptive Statistics of Capital and Exploration Expenditures, Small and Large Firms in Sample, 2008**  **and 2009 (million 2008 dollars)** Capital and Exploration Expenditures (millions, 2008 dollars) Firm Size Number Total Average Median Minimum Maximum Small 74 13,262.9 179.2 60.4 0.1 2,401.9 Large 43 127,505.6 2,965.2 982.7 0.1 22,518.7 **Total 117**  **140,768.5 1,203.1**  **192.8 0.1**  **22,518.7** Sources: Oil and Gas Journal . “OGJ150.” September 21, 2009; Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. American Business Directory was used to determine number of employees. The average 2008 and 2009 total capital and exploration expenditures for the sample of 117 firms were approximately $140 billion in 2008 dollars). About 9 percent of this total was spent by small firms. Average capital and explorations expenditures for small firms are about 6 percent of large firms; median expenditures of small firms are about 6 percent of large firms’ expenditures. For small firms, c apital and exploration expenditures are high relative to revenue, which appears to hold true more generall y for independent E&P firms compared to integrated major firms. This would seem to indicate the capital - intensive nature of E&P activities. As expected, this would drive up ratios comparing estimated engineering costs to revenues and capital and exploration expenditures. Table 7 - 20 breaks down the estimated number of natural gas and crude o il wells drilled by the 121 firms in the sample for which the Oil and Gas Journal information reported well drilling estimates. Note the fractions on the minimum and maximum statistics; the fractions reported are due to our assumptions to estimate oil and natural gas wells drilled from the total wells drilled reported b y the Oil and Gas Journal . The OGJ150 lists new wells drilled by firm in 2008 and 2009, but the drilling counts are not specific to crude oil or natural gas wells. We7 - 39

apportion the wells drilled to natural gas and crude oil wells using the distribution of well drilling in 2009 (63 percent natural gas and 37 percent oil). **Table 7**  **- 20**  **Descriptive Statistics of Estimated Wells Drilled, Small and Large Firms in**  **Sample, 2008 and 2009 (million 2008 dollars)** Estimated Average Wells Natural Gas and Crude Oil Wells Drilled (2008 and 2009) Well Type Firm Size Number of Firms Total Average Median Minimum Maximum Natural Gas

Small 7 7 2, 049.5 26.6 5.7 0.2 259.3 Large 4 4 9, 723.1 221.0 153.2 0.6 868.3 Subtotal 121 11,7 72.5 97. 3 28.3 0.2 868.3 Crude Oil Small 7 7 1179.6 15.3 3. 3 0.1 149.2

Large 4 4 5596.3 127.2 8 8.1 0.4 499.7 Subtotal 121 6,775.9 56.0 16.3 0.1 499.7 **Total Sm**  **all 7**  **3, 229.1**  **4 1.9**  **9. 0**  **0. 3**  **408.5**

**Large 4**  **4 1**  **5,319. 4**  **3 48.2**  **2 41.3**  **1 .0**  **1,368.0 Total**  **121 18,**  **548. 4**  **153.3 44.6**  **0. 3**  **1,368.0** Sources: Oil and Gas Journal . “OGJ150.” September 21, 2009; Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. American Business Directory was used to determine number of employees. This table highlights the fact that many firms drill relativel y few wells; the median for small firms is approximately

6 natural gas wells compared to 153 for large firms. L ater in this section, we examine whether this distribution has implications for the engineering costs estimates, as well as the estimates of expected natural product recovery from controls such as RECs. Unlike the anal ys is that follows for the anal ys is of impacts on small business from the NESHAP Amendments , we have no specific data on potentially affected facilities under the NSPS. The NSPS will apply to new and modified sources, for which data are not full y available i n advance, particularl y i n the case of new and modified sources such as well completions and recompletions which are spatially diffuse and potentially

large in number. The engineering cost analy sis estimated compliance costs in a top - down fashion, projec ting the number of new sources at an annual level and multiplying these estimates by7 - 40

model unit - level costs to estimate national impacts. To estimate per- firm compliance costs in this analy sis, we followed a procedure similar to that of entering estimate compliance costs in NEMS on a per well basis. We first use the OGJ150 - based list to estimate engineering compliance costs for integrated and production companies that may operate facilities in more than one segment of the oil and natural gas industry. We then estimate the compliance costs per crude oil and natural gas well by totaling all compliance costs estimates in the engineering cost estimates for the final NSPS and dividing that cost by the total number of crude oil and natural gas wells forecast as of 2015, the year of anal ys is. These compliance costs include the expected revenue from natural gas and condensate recovery that result from implementation of some controls. This estimation procedure yielded an estimate of crude oil well compliance cos ts of $225 per drilled well and natural gas well compliance costs of $17,500 without considering estimated revenues from product recovery and $225 and
- $1070 per drilled crude oil and natural gas well, respectivel y, with estimated revenues from product recovery included. Note that the divergence of estimated per well costs between crude oil and natural gas wells is because the final NSPS requirements are primary directed toward natural gas wells. Also note that the per well cost savings estimate for n atural gas wells is different than the estimated cost of implementing a REC; this difference is because this estimate is picking up savings from other control options. We then estimate a single - year, firm - level compliance cost for this subset of firms by multiplying the per well cost estimates with the well count estimates. The OGJ reports plant processing capacity in terms of MMcf/day. In the energy s ys tem impacts anal ys is, the NEMS model estimates a 6.5 percent increase (from 21.05 tcf in 2011 to 22.43 tcf in 2015) in domestic natural gas production from 2011 to 2015, the anal ys is 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 ye ar. We assume that the engineering compliance costs estimates associated with processing are distributed according to the proportion of the increased national processing capacity contributed b y each processing plant. These costs are estimated at $7.2 million without estimated revenues from product recovery and $6.2 with estimated revenues7 - 41

from product recovery , respectivel y, in 2008 dollars, or about $21/MMcf without revenues and $17/MMcf with revenues. The OGJ report on pipeline companies has the advantage that it reports expenditures on plant additions. We assume that the firm - level compression and transmission - related NSPS compliance costs are proportional to the expenditures on plant additions and that these additions reflect a representative year or this analysis. We estimate the annual compression and transmission - related NSPS compliance costs at $5.5 million without estimated revenues from product recovery

and $3.7 million with es timated revenues from product recovery, respectivel y, in 2008 dollars. 7.4.3.2 Small Entity Impact Analysis, Final NSPS, Results Summing estimated annualized engineering compliance costs across industry segment and individual firms in our sample, we estimate firm s in the OGJ - based sample will face about 220 million in 2008 dollars, about 64 percent of the estimated annualized costs of the final NSPS without including revenues from additional product recovery $327 million). When including revenues from additional product recovery , the estimated compliance costs for the firms in the sample is about - $720,000. Table 7 - 21 presents the d istribution of estimated final NSPS complianc e costs across firm s ize for the firms within our sample. Evident from this table, about 96 percent of the estimated engineering compliance costs accrue to the integrated and production segment of the industry , again explained by

the fact that completion - related requirements contribute the bulk of the estimated engineering compliance costs (as well as estimated emissions reductions). About 16 percent of the total estimated engineering compliance costs (and about 17 percent of the costs accruing the integrated and production segment) are focused on small firms.7 - 42

**Table 7**  **- 21**  **Distribution of Estimated Final**  **NSPS Compliance Costs Without Revenues from Additional Natural Gas Product Recovery across Firm Size in Sam**  **ple of Firms**

Number of Firms Estimated Engineering Compliance Costs Without Estimated Revenues from Natural Gas Product Recovery (2008 dollars) Firm Type/Size Total Average Median Minimum Maximum Production and Integrated Small 77 35,182,059 456,910 95,299 1,463 4,552,593 Large 47 175,543,216 3,734,962 2,631,873 15,433 15,255,379 Subtotal 124 210,725,275 1,699,397 438,547 1,463 15,255,379 Pipeline Small 11 3,738 340 123 20 1,264 Large 36 1,641,771 45,605 4,218 41 994,491 Subtotal 47 1,645,509 35,011 2,498 20 994,491 Processing Small 39 482,232 12,365 1,906 191 279,864 Large 23 870,458 37,846 8,236 38 429,043 Subtotal 62 1,352,690 21,818 2,764 38 429,043 Pipelines/Processing Small 0 --- --- --- --- --- Large 13 5,828,374 448,336 159,519 2,040 2,892,799 Subtotal 13 5,828,374 448,336 159,519 2,040 2,892,799 **Total Sm**  **all 127**  **35,668,029 280,851**  **22,511 20**  **4,552,593 Large**  **119 183,883,819**  **1,545,242 48,054**  **38 15,255,379**  **Total 246**  **219,551,848 892,487**  **33,520 20**  **15,255,379** These distributions are similar when the revenues from expected natural gas recovery are included ( Table 7 - 22 ). About 9 percent of the total savings from the final NSPS is expected to accrue to small firms (about 23 percent of the savings to the integrated and production segment accrue to small firm s). Note also in Table 7 - 22 that the pipeline and processing segments (and the pipeline/processing firms) are not expected to experience net cost savings (negative c osts) from the final NSPS.7 - 43

**Table 7**  **- 22**  **Distribution of Estimated Final**  **NSPS Compliance Costs With Revenues from Additional Natural Gas Product Recovery across Firm Size in Sample of Firms** 

Number of Firm s Estimated Engineering Compliance Costs With Estimated Revenues from Natural Gas Product Recovery (millions, 2008 dollars) Firm Type/Size Total Average Median Minimum Maximum Production and Integrated Small 77 - 1,930,670 - 25,074 - 5,341 - 255,773 22,919 Large 47 - 6,565,092 - 139,683 - 126,073 - 847,055 924,574 Subtotal 124 - 8,495,763 - 68,514 - 15,463 - 847,055 924,574 Pipeline Small 11 3,629 330 119 19 1,226 Large 36 1,593,661 44,268 4,095 40 965,348 Subtotal 47 1,597,289 33,985 2,425 19 965,348 Processing Small 39 349,635 8,965 1,382 138 202,911 Large 23 631,112 27,440 5,971 28 311,071 Subtotal 62 980,747 15,819 2,004 28 311,071 Pipelines/Processing Small 0 --- --- --- --- --- Large 13 5,198,212 399,862 143,446 1,511 2,777,165 Subtotal 13 5,198,212 399,862 143,446 1,511 2,777,165 **Total Sm**  **all 127**  **- 1,577,407**  **- 12,421**  **- 902**  **- 255,773**  **202,911 Large**  **119 857,892**  **7,209 2,419**  **- 847,055**  **2,777,165 Total**  **246 -**  **719,514 -**  **2,925 103**  **- 847,055**  **2,777,165**7 - 44

**Table 7**  **- 23**  **Summary of Sales Test Ratios, Without Revenues from Additional Natural Gas Product Recovery for Firms Affected by**  **Final NSPS** 

Number of Firms Descriptive Statistics for Sales Test Ratio Without Estimated

Revenues from Natural Gas Product Recovery (%) Firm Type/Size Average Median Minimum Maximum Production and Integrated Small 77 0.97% 0.22% 0.01% 23.17% Large 47 0.19% 0.14% 0.00% 1.28% Subtotal 124 0.67% 0.18% 0.00% 23.17% Pipeline Small 11 0.00% 0.00% 0.00% 0.01% Large 36 0.01% 0.00% 0.00% 0.06% Subtotal 47 0.01% 0.00% 0.00% 0.06% Processing Small 39 0.02% 0.01% 0.00% 0.15% Large 23 0.01% 0.00% 0.00% 0.16% Subtotal 62 0.02% 0.01% 0.00% 0.16% Pipelines/Processing Small 0 --- --- --- --- Large 13 0.00% 0.00% 0.00% 0.01% Subtotal 13 0.00% 0.00% 0.00% 0.01% **Total Sm**  **all 127**  **0.59% 0.07%**  **0.00% 23.17%**  **Large 119**  **0.08% 0.00%**  **0.00% 1.28%**  **Total 246**  **0.35% 0.02%**  **0.00% 23.17%** 

The mean cost - sales ratio for all businesses when estimated product recovery is excluded from the anal ys is of the sample data is 0.35 percent, with a median ratio of 0.02 percent, a minimum of less than 0.01 percent, and a max imum of over 23 percent ( Table 7 - 23 ). For small firms in the sample, the mean and median cost - sales ratios are 0.59 percent and 0.07 percent, respectivel y , with a minimum of less than 0.01 pe rcent and a maximum of over 23 percent ( Table 7 - 23 ). Each of these statistics indicates that, when considered in the aggregate, impacts are relativel y higher on smal l firms than large firms when the estimated revenue from additional natural gas product recovery is ex cluded . However, as the next table shows, the reverse is true when these revenues are included .7 - 45

**Table 7**  **- 24**  **Summary of Sales Test Ratios**  **, With Revenues from Additional Natural Gas Product Recovery**  **for Firms Affected by Final**  **NSPS**

Number of Firms Descriptive Statistics for Sales Test Ratio With Estimated Revenues from Natural Gas Product Recovery (%) Firm Ty pe/Size Average Median Minimum Maximum Production and Integrated Small 77 - 0.05% - 0.01% - 1.06% 0.01% Large 47 - 0.01% - 0.01% - 0.07% 0.14% Subtotal 124 - 0.03% - 0.01% - 1.06% 0.14% Pipeline Small 11 0.00% 0.00% 0.00% 0.01% Large 36 0.01% 0.00% 0.00% 0.06% Subtotal 47 0.01% 0.00% 0.00% 0.06% Processing Small 39 0.01% 0.01% 0.00% 0.11% Large 23 0.01% 0.00% 0.00% 0.11% Subtotal 62 0.01% 0.00% 0.00% 0.11% Pipelines/Processing Small 0 --- --- --- --- Large 13 0.00% 0.00% 0.00% 0.01% Subtotal 13 0.00% 0.00% 0.00% 0.01% **Total Sm**  **all 127**  **- 0.03%**  **0.00% -**  **1.06% 0.11%**  **Large 119**  **0.00% 0.00%**  **- 0.07%**  **0.14%** Total **246 -**  **0.01% 0.00%**  **- 1.06%**  **0.14%** The mean cost - sales ratio for all businesses when estimated product recovery is included is in the sample is - 0.01 percent, with a median ratio of less than 0.01 percent, a minimum of

- 1.06 percent, and a maximum of 0.14 percent ( Table 7 - 24 ). For small firms in the sample, the mean and median cost - sales ratios are - 0.03 percent and less than 0.01 percent, respectively , with a minimum of - 1.06 percent and a maximum of 0.11 percent ( Table 7 - 24 ). Each of these statistics indicates that, when considered in the aggregate, impacts are small on small business when the estimated revenue from additional natural gas product recovery are included , the reverse of the conclusion found when these revenues are excluded . Meanwhile, Table 7 - 25 presents the distribution of estimated cost - sales ratios for the small firms in our sample with and without including estimates of the expected natural gas product recover from implementing controls. When revenues estimates are included, all 1277 - 46

firms (100 percent) have estimated cos t - sales ratios less than 1 percent. While less than 1 percent, the highest cost - sales ratios for small firms in the sample experiencing impacts are largel y driven b y costs accruing to processing and pipeline firms. That said, the incremental costs imposed on firms that process natural gas or transport natural gas via pipelines are not estimated to create significant impacts on a cost - sales ratio basis at the firm - level. **Table 7**  **- 25**  **Impact Levels of Final NSPS o n**  **Small Firms as a P ercent of Small Firms in**  **Sample, With and Without Revenues from Additional Natural Gas Product Recovery**  Without Estimated Revenues from Natural

Gas Product Recovery With Estimated Revenues from Natural Gas Product Recovery

Im pact Level Number of Small

Firms in Sample Estimated to be Affected % of Small Firms in

Sam ple Estimated to be Affected Number of Small

Firms in Sample Estimated to be Affected % of Small Firms in

Sam ple Estimated to be Affected C/S Ratio less than 1% 120 94.5 % 12 7 100.00% C/S Ratio 1 - 3% 4 3.1 % 0 0.00% CS Ratio greater than 3% 3 2.4 % 0 0.00% When the estimated revenues from product recovery are not included in the anal ys is, four firms (about 3 percent) are estimated to have sales test ratios between 1 and 3 percent. Three firms (about 2 percent) are estimated to have sales test ratios greater than 3 percent. These results noted, the exclusion of product recovery is somewhat artificial. While the mean engineering compliance costs and revenues estimate s are valid, drawing on the means ignores the distribution around the mean estimates, which risks masking effects. Because of this risk, the following section offers a qualitative discussion of small entities with regard to obtaining REC services, the val idity of the cost and performance of RECs for small firms, as well as offers a discussion about whether older equipment, which may be disproportionately

owned and operated be smaller producers, would be affected b y the final NSPS.7 - 47

7.4.3.3 Small Entity Impact Ana lysis, Final NSPS, Additional Qualitative Discussion 3.5.3.3.1 Small Entities and Reduced Emissions Completions Because REC requirements of the final NSPS are expected to contribute the large majority of engineering compliance costs, it is important to examine these requirements more closely in the context small entities. Important issues to resolve are the scale of REC costs within a drilling project, how the pay ment s ys tem for recovered natural gas functions, whether small entities pursue particular “niche” strategies that may influence the costs or performance in a way that makes the estimates costs and revenues invalid. A ccording to th e most recent natural gas well cost data from EIA, the average cost of drilling and completing a producing natural ga s well in 2007 was about $4.8 million (adjusted to 2008 dollars). This average includes lower cost wells that may be relatively

shallow or are not hydraulicall y fractured. Hydraulicall y fractured wells in deep formations may cost up to $10 million. RECs contracted from a service provider are estimated to cost $3 3,200 (in 2008 dollars) or roughly 0.3% - 0.7% of the ty pical cost of a drilling and completing a natural gas well. As this range does not include revenues expected from natural gas and hydrocarbon condensate recovery expected to offset REC implementation costs, REC costs likely represent a small increment of the overall burden of a drilling project. To implement an REC, a service provider , which may itself be a small entity , is ty pically contracted to bring a set of equipment to the well pad temporaril y to capture the stream that would otherwise be vented to the atmosphere. Ty pically , service providers are engaged in a long term drilling program in a particular basin covering multiple wells on mult iple well pads. For gas captured and sold to the gathering s ys tem, Lease Automatic Custody Transfer (LACT) meters are normall y read daily automatically, and sales transactions are typ ically settled at the end of the month. Invoices from service providers are generally delivered in 30 - day

increments during the well development time period, as well as at the end of the working contract for that well pad. The conclusion from the information, b ased on the available information, in most cases, the owner/operator incurs the REC cost within the same 30 day period that the owner/operator receives revenue as a result of the REC.7 - 48

We assume small firms are performing RECs in CO and WY, as in many instances RECs are required under state regulation. In addition to S tate regulations, some companies are implementing RECs voluntarily such as through participation in the EPA Natural Gas STAR Program and the focus of recent press reports. As described in more detail below, many small independent E&P companies often do n ot conduct an y of the actual field work. These firms will ty picall y contract the drilling, completion, testing, well design, environmental assessment, and maintenance. Therefore, we believe it is likely that small independent E&P firms will contract for RECs from service providers if required to perform RECs. An important reminder is that performing a REC is a straightforward and inexpensive extension of drilling, completion, and testing activities. To the extent that very

small firms may

specialize in o perating relatively few low producing stripper wells, it is important to ask whether low - producing wells are likel y candidates for re - fracturing/re - completion and, if so, whether the expected costs and revenues would be valid. These marginal gas wells are likel y to be older and in conventional formations, and as such are unlikel y to be good candidates for re - fracturing/completion. To the extent the marginal wells may

be good candidates for re - fracturing/co mpletion, the REC costs are valid estimates . The average REC cost is valid for RECs performed on any well, regardless of the operator size. The reason for this is that the REC service is contracted out to specialty service providers who charge daily

rates for the REC equipment and workers. The cost is not related to any well characteristic. Large operators may

receive a discount for offering larger contracts which help a service provider guarantee that REC equipment will be utilized. However, we should note that the existence of a potential discount for larger contracts is based on a strong assumption; we do not have evidence to support this assumption. Since contracting REC equipment is analogous to contracting for drilling equipment, completion equipment, etc., the premium would likely be in the same range as other equipment contracted b y s mall operators. Since the REC cost is a small portion of the overall well drilling and completion cost, the effect of any bulk discount disparity between large and small operators will be small, if in fact it doe s exist.7 - 49

Although small operators may own the majority

of marginal and stripper wells, they will make decisions based on economics just as any sized compan y would. For developing a new well, an y sized compan y will expect a return on their investment meaning the potential for sufficient gas, condensate, and/or oil production to pay back their investment and generate a return that exceeds alternative investment opportunities. Therefore, small or large operators that are performing h ydraulic fracture complet ions will experience the same distribution of REC performance. For refracturing an existing well, the well must be a good candidate to respond to the re - fracture/completion with a production increase that merits the investment in the re fracture/completio n. Plugging and abandoning wells is complex and costly , so sustaining the productivity of wells is important for maximizing the exploitation of proven dom estic resources. However, many marginal gas wells are likel y to be older and in conventional formati ons, and as such are unlikely to be good candidates for re - fracturing/completion, which means they are likel y unaffected b y the final NSPS . 3.5.3.3.2 Age of Equipment and Final Regulations Given a large fraction of domestic oil and natural gas production is produced from older and generally

low productivity

wells, it is important to examine whether the requirements of these rules might present impediments to owners and operators of older equ ipment. The NSPS is a standard that applies to new or modified sources. Because of this, NSPS requirements target new or modified affected facilities or equipment, such as processing plants and compressors. While the requirements may apply to modificati ons of existing facilities, it is important to discuss well completion - related requirements aside from other requirements in the NSPS distinctly . Excluding well completion requirements from the cost estimates, the non - completion NSPS requirements (relate d to equipment leaks at processing plants, reciprocating and centrifugal compressors, pneumatic controllers, and storage vessels) are estimated to require about $15 million in annualized engineering costs. EPA also estimates that the annualized costs of these requirements will be mostly if not fully

offset by revenues expected from natural gas recovery . EPA does not expect these requirements to disproportionately affect producers with7 - 50

older equipment. Meanwhile, the REC and emissions combustion requireme nts in the final NSPS relate to well completion activities at new hydraulicall y fractured natural gas wells and existing wells which are recompleted after being fractured or re - fractured. These requirements constitute the bulk of the expected engineering compliance expenditures (about $320 million in annualized costs) and expected revenues from natural gas product recovery (about $330 million in revenues, annuall y). While age of the well and equipment may be an important factor for small and large produce rs in determining whether it is economical to fracture or re - fracture an existing well, this equipment is unlikely

to be subject to the NSPS. To comply with completion - related requirements, producers are likel y to rel y heavily on portable and temporary co mpletion equipment brought to the wellpad over a short period of time (a few day s to a few weeks) to capture and combust emissions that are otherwise vented. The equipment at the wellhead

— newly installed in the case of new well completions or already in p lace and operating in the case of existing wells

—is not likely to be subject to the NSPS requirement. **7.4.4 Small**  **Entity Economic Impact Analysis, Final NESHAP Amendments**  The Final NESHAP Amendments will affect facilities operating three typ es of equipment: gl yc ol deh ydrators at production facilities, gl ycol deh ydrators 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 b y the NESHAP Amendments for each facility . We then used available data sources to best identify the ultimate owner of the equipment that would likely require new controls and linked facility- level compliance cost estimates to firm - level employ ment and revenue data. These data were then used to calculate an estimated compliance costs to revenues ratio to identify small businesses that might be significantly impacted b y the NESHAP. While we were able to identify the owners all but 14 facilities likely to be affected, we could not obtain employment and revenue levels for all of these firms. Overall, we expect about 381 facilities to be affected, and these facilities are owned b y an estimated 155 firms. We were unabl e to obtain financial information on 47 (30 percent) of these firms due to inadequate data.7 - 51

In some instances, firms are private, and financial data is not available. In other instance, firms may no longer exist, since NEI data are not updated continuous ly . From the ownership information and compliance cost estimates from the engineering anal ys is, we estimated total compliance cost per firm. Of the 108 firms for which we have financial information, we identified 54 small firms and 54 large firms that w ould be affected b y the NESHAP Amendments . Annual compliance costs for small firms are estimated at $2.6 million (17 percent of the total compliance costs), and annual compliance costs for large firms are estimated at $10 million (66 percent of the total compliance costs). The facilities for which we were unable to identify the ultimate owners, employ ment, and revenue levels would have an estimated annual compliance cost of $2.6 million (17percent of the total). All figures are in 2008 dollars. The avera ge estimated annualized compliance cost for the 54 small firms identified in the dataset is $48,000, while the mean annual revenue figure for the same firms is over $1 09 million, or less than 1 percent for a average sales - test ratio for all 54 firms ( Table 7 - 26 ). The median sale - test ratio for these firms is smaller at 0.1 7 percent. Large firms are likely to see an average of $183,000 in annual compliance costs, where as average revenue for these firms exceeds $30 billion since this set of firms includes many of the very

large, integrated energy

firms. For large firms, the average sales - test ratio is about 0.01 percent, and the median sales - test ratio is less than 0.01 percent ( Table 7 - 26 ). **Table 7**  **- 26**  **Summary of Sales Test Ratios for Firms Affected by Final**  **NESHAP Am**  **endments** Firm Size No. of Known

Affected Firms % of Total Known

Affected Firms Mean C/S Ratio Median C/S Ratio Min. C/S Ratio Max.

C/S Ratio Small 54 50% 0.72% 0.17% < 0.01% 8.5% Large 54 50% 0.01% < 0.01% < 0.01% 0.3% All 108 100% 0.37% 0.02% < 0.01% 8.5% Among the small firms, 45 of the 54 (83 percent) are likel y to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile nine firms (17 percent) are likel y to have impacts greater than 1 percent ( Table 7 - 27 ). Three of the se nine firms are likel y to have impacts greater than 3 percent ( Table 7 - 27 ) While these nine firms might7 - 52

receive significant impacts from the final NESHAP Amendments , they represent a very

small slice of the oil and gas industry in its entirety, less than 0.2 percent of the estimated 6,427 small firms in NAI CS 211 ( Table 7 - 27 ). **Table 7**  **- 27**  **Affected Small Firms as a Percent of Small Firms Nationwide, Final**  **NESHAP Amendments**

Firm Size Number of Small Firms Affected Nationwide % of Small Firms

Affected Nationwide Affected Firms

as a % of National Firms (6,427) C/S Ratio less than 1% 45 83. 3 % 0. 70 % C/S Ratio 1 - 3% 6 11.1 % 0.09% CS Ratio greater than 3% 3 5. 6% 0.0 5 % **7.4.5 Conclusions for NSPS and**  **NESHAP Amendments** While both the NSPS and NESHAP amendment would individually result in a no SI SNOSE finding, the EPA performed an additional anal ys is in order to certify the rule in its entirety . This anal ys is compared compliance costs to entity revenues for the total of all the entities affected b y the NESHAP Amendments and the sample of entities analyzed for the NSPS. When revenues from additional natural gas product sales are not included, 153 of the 169 small firms (91 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues ( Table 7 - 28 ) . Meanwhile, 16 firms ( 9 percent) are likely to have impacts greater than 1 percent. Six of these 16 firms are likely to have impacts greater than 3 percent. When revenues from additional natural gas product sales are included, 160 small firms (95 percent) are likely to have imp acts of less than 1 percent. Nine firms (5 percent) are likely

to have impacts greater than 1 percent, while onl y three of these nine are likely to have impacts greater than 3 percent. **Table 7**  **- 28**  **Affected Small Firms as a Percent of Small Firms Nationwide, Final**  **NSPS and**  **NESHAP Amendments** Without Estimated Revenues from Natural

Gas Product Recovery With Estimated Revenues from Natural Gas Product Recovery

Im pact Level Number of Small

Firms in Sample Estimated to be Affected % of Small Firms in

Sam ple Estimated to be Affected Number of Small

Firms in Sample Estimated to be Affected % of Small Firms in

Sam ple Estimated to be Affected C/S Ratio less than 1% 153 90.5 % 160 94.7 % C/S Ratio 1 - 3% 10 5.9 % 6 3.6 %7 - 53

CS Ratio greater than 3% 6 3.6 % 3 1.8 % The number of significantly impacted small businesses is unlikely to be sufficiently

large to declare a SI SNOSE. Our judgment in this determination is informed by the fact that man y affected firms are expected to receive revenues from the additional natural gas and condensate recovery engendered by

the implementation of the controls evaluated in this RIA. As much of the additional natural gas recovery is estimated to arise from completion - related a ctivities, we expect the impact on well - related compliance costs to be significantl y mitigated. This conclusion is enhanced because the returns to reduced emissions completion activities occur without a significant time lag between implementing the control and obtaining the recovered product unlike many

control options where the emissions reductions accumulate over long periods of time; the reduced emission completions and recompletions occur over a short span of time, during which the additional product re covery is also accomplished. **7.5 References**  Bezdek, R.H., R.M. Wendling, and P. DiPern **a** . 2008. “ Environmental protection, the econom y, and jobs: national and regional anal ys es .” Journal of Environmental Management 86(1):63
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