# 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 ACKGROU

ND ................................ ................................ ................................ ................................ .............. 1 - 1 1.2 S UMMARY OF RESULTS ................................ ................................ ................................ ................................ 1 - 3 1.2.1 NSPS Results ................................ ................................ ................................ ................................ ..... 1 - 3 1.2.2 NESHAP Amendments Results ................................ ................................ ................................ ......... 1 - 6 1.2.3 Results of Energy System Impacts Analysis of the NSPS and NESHAP Amendments .................... 1 - 8 1.2.4 Results for Combined Small Entity Analysis for the NSPS and NESHAP Amendments ................. 1 - 8 1.3 S UMMARY OF NSPS I MPACTS C HANGES FROM THE P ROPOSAL RIA ................................ ............................ 1 - 8 1.4 S UMMARY OF NESHAP AMENDMENTS I MPACTS C HANGES FROM THE P ROPOSAL RIA ............................ 1 - 10 1.5 O RGANIZATION OF THIS REPORT ................................ ................................ ................................ ................ 1 - 11 **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 Transmission 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 - 1iv

3.2 E MI SSI ONS P OINTS , C ONTROLS , AND ENGINEERI NG C OSTS A

NALYSIS ................................ ........................ 3 - 1 3.2.1 Emission Points and Pollution Controls assessed in the RIA ................................ ............................ 3 - 2 3.2.1.1 NSPS Emission Points and Pollution Controls ................................ ................................ ........ 3 - 2 3.2.1.2 NESHAP Emission Points and Pollution Controls ................................ ................................ ... 3 - 6 3.2.2 Engineering Cost Analysis ................................ ................................ ................................ ................. 3 - 8 3.2.2.1 NSPS Sources ................................ ................................ ................................ ........................... 3 - 8 3.2.2.2 NESHAP Sources ................................ ................................ ................................ ................... 3 - 33 3.3 REFERENCES ................................ ................................ ................................ ................................ .............. 3 - 35 **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 ENEFI TS ................................ ................................ .......................... 4 - 8 4.4.1 Benzene ................................ ................................ ................................ ................................ ........... 4 - 14 4.4.2 Toluene ................................ ................................ ................................ ................................ ............ 4 - 16 4.4.3 Carbonyl s ulfide ................................ ................................ ................................ ............................... 4 - 16 4.4.4 Ethylbenzene ................................ ................................ ................................ ................................ .... 4 - 17 4.4.5 Mixed xylenes ................................ ................................ ................................ ................................ .. 4 - 18 4.4.6 n - Hexane ................................ ................................ ................................ ................................ .......... 4 - 18 4.4.7 Other Air Toxics ................................ ................................ ................................ .............................. 4 - 19 4.5 VOC ................................ ................................ ................................ ................................ .......................... 4 - 19 4.5.1 VOC as a PM 2.5 precursor ................................ ................................ ................................ ................ 4 - 19 4.5.2 PM 2.5 health effects and valuation ................................ ................................ ................................ .... 4 - 20 4.5.3 Organic PM welfare effects ................................ ................................ ................................ ............. 4 - 24 4.5.4 Visibility Effects ................................ ................................ ................................ .............................. 4 - 25 4.6 VOC AS AN O ZONE P RECURSOR ................................ ................................ ................................ ................ 4 - 25 4.6.1 Ozone health effects and valuation ................................ ................................ ................................ .. 4 - 26 4.6.2 Ozone vegetation effects ................................ ................................ ................................ .................. 4 - 27 4.6.3 Ozone climate effects ................................ ................................ ................................ ....................... 4 - 27 4.7 M ETHANE (CH 4 ) ................................ ................................ ................................ ................................ ........ 4 - 28 4.7.1 Methane climate effects and valuation ................................ ................................ ............................. 4 - 28 4.7.2 Methane as an ozone precursor ................................ ................................ ................................ ........ 4 - 35 4.7.3 Com

bined methane and ozone effects ................................ ................................ ............................. 4 - 35 4.8 REFERENCES ................................ ................................ ................................ ................................ .............. 4 - 36 **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 MPRO VING REG

ULATION AND REGULATORY REVIEW ................................ ................................ .......................... 5 - 1 5.2 P APERWORK REDUCTION A CT ................................ ................................ ................................ ..................... 5 - 2 5.3 REGULATORY F LE XIBILITY A CT ................................ ................................ ................................ .................. 5 - 5 5.4 UNFUNDED M ANDATES REF ORM A CT ................................ ................................ ................................ ......... 5 - 7 5.5 E XECUTI

VE O RDER 13132: F EDERALISM ................................ ................................ ................................ .... 5 - 8 5.6 E XECUTI

VE O RDER 13175: C ONSULTATION AND C OORDINATION WITH INDIAN T RIBAL G OVERNMENTS ... 5 - 8 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 - 9 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 - 9 5.9 NATIONAL T ECHNOLOGY T RANSFER AND A DVANCEMENT A CT ................................ ................................ 5 - 11 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 - 11 5. 11 C ONGRESSIONAL REVIEW A CT ................................ ................................ ................................ .............. 5 - 13 **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 AND NESHAP AMENDMENTS ................................ 7 - 1 7.2.1 Description of the Department of Energy National Energy Modeli ng 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 - 8 7.2.2.3 Fixing Canadian Drilling Costs to Baseline Path ................................ ................................ ... 7 - 10 7.2.3 Energy System Impacts ................................ ................................ ................................ ................... 7 - 10 7.2.3.1 Im

pacts on Drilling Activities ................................ ................................ ................................ 7 - 10 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 - 24 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 - 43 7.4.3.3 Small Entity Impact Analysis, Final NSPS, Additional Qualitative Discussion .................... 7 - 49 7.4.4 Small Entity Economic Impact Analysis, Final NESHAP Amendments ................................ ........ 7 - 52 7.4.5 Conclusions for NSPS and NESHAP Amendments ................................ ................................ ........ 7 - 54 7.5 REFERENCES ................................ ................................ ................................ ................................ .............. 7 - 55vi **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 1

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

NESHAP in 2015 1

................................ ................................ ................................ .............................. 1 - 7 Table 2
- 1 Technically Recoverable Crude Oil and Natural Gas Resource Estimates, 2007 ............................. 2 - 10 Table 2
- 2 Crude Oil and Natural Gas Cumulative Domestic Production, Proved Reserves, and Proved Ultimate

Recovery, 1977 - 2008 ................................ ................................ ................................ ....................... 2 - 11 Table 2
- 3 Crude Oil and Dry Natura l 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 Fore cast of Total Successful Wells Drilled, Lower 48 States, 2010
- 2035 ................................ ....... 2 - 27 Table 2
- 14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2010
- 2035 ................................ ..... 2 - 29 Table 2
- 15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price ................................ ...... 2 - 31 Table 2
- 16 SBA Size Standards and Size Distribution of Oil and Natural Gas Firms ................................ ....... 2 - 38 Table 2
- 17 Oil and Natural Gas Industry Employment by NAICS, 1990
- 09 ................................ ..................... 2 - 39 Table 2
- 18 Oil and Natural Gas Industry Average Wages by NAICS, 1990
- 2009 (2008 dollars) ..................... 2 - 43 Table 2
- 19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2010 ................................ .......... 2 - 47 Table 2
- 20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009 ................................ .............. 2 - 48 Tabl e 2 - 21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2009 ............................. 2 - 49 Table 2
- 22 Selected Financial Items from 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 Evaluated at Proposal for the NSPS ................................ .. 3 - 9 Table 3
- 2 Summary of Projected No. of Affected Units Under Primary and Alternative Regulatory Baselines

and Capital and Annualized Costs per Unit for Final NSPS Emissions Sources and Points ............ 3 - 12 Table 3
- 3 Estimated New Hydraulically Fractured and Refractured Natural Gas Well Completions Affected by NSPS, 2015 ................................ ................................ ................................ ................................ ...... 3 - 16 Table 3
- 4 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost
Effectiveness by NSPS Emissions Sources an d Points, Primary Baseline, 2015 ............................. 3 - 20 Table 3
- 5 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost
Effectiveness by NSPS Emissions Sources and Points, Alternative Regulatory Baseline, 2015 ..... 3 - 21 Table 3
- 6 Engineering Compliance Costs, Emission Reductions, and Cost
- Effectiveness, Primary Baseline,

NSPS (2008$)
................................ ................................ ................................ ................................ ... 3 - 22 Table 3
- 7 Estimates of Control Unit
- level an d National
- level Natural Gas and Condensate Recovery, Sources

and Emissions Points, Primary Baseline, NSPS, 2015 ................................ ................................ ..... 3 - 29 Table 3
- 8 Simp le Rate of Return Estimate for Final NSPS Controls, Primary Baseline ................................ .. 3 - 30 Table 3
- 9 Summary of Estimated Capital and Annual Costs, E mi ssions Reductions, and HAP Reduction Cost
Effectiveness for Final NESHAP Amendments ................................ ................................ ............... 3 - 35 Table 4
- 1 Direct Emission Reductions Associated with the Oil and Natural Gas NSPS and NESHAP

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

Primary Baseline (“Producer
- Side”) (short 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 and NESHAP Amendments in 2015 (million metric tonnes) ("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 and NESHAP Amendments in 2015 (million metric tonnes) ................................ .................. 4 - 7vii

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

(short tons per year) ................................ ................................ ................................ ............................ 4 - 8 Table 4
- 6 Monetized Benefits
- per - Ton Estimates for VOC (2008$)
................................ ............................... 4 - 23 Table 4
- 7 Climate Methane Benefits Using ‘GWP’ Approach ................................ ................................ ......... 4 - 33 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 1

................................ ................................ ................................ . 5 - 2 Table 6
- 1 Summary of the Monetiz ed Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS

in 2015 1

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

NESHAP Amendments in 2015 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 - 8 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 - 14 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 - 39 Table 7
- 19 Descriptive Statistics of Capital and Exploration Expenditures, Small and Large Firms in Sample,

2008 and 2009 (million 2008 dollars) ................................ ................................ .............................. 7 - 40 Table 7
- 20 Descriptive Statistics of Estimated Wells Drilled, Small and Large Firms in Sample, 2008 and 2009 7 -

41 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 - 44 Table 7
- 22 Distribution of Estimated Final NSPS Compliance Costs With Revenues from Additional Natural Gas

Product Recovery across Firm Size i n Sample of Firms ................................ ................................ .. 7 - 45 Table 7
- 23 Summary of Sales Test Ratios, Without Revenues from Additional Natural Gas Product Recovery for

Firms Affected by Final NSPS ................................ ................................ ................................ ......... 7 - 46 Table 7
- 24 Summary of Sales Test Ratios, With Revenues from Additional Natural Gas Product Recovery for

Firms Affected by Final NSPS ................................ ................................ ................................ ......... 7 - 47 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 - 48 Table 7
- 26 Summary of Sales Test Ratios for Firms Affe cted by Final NESHAP Amendments ...................... 7 - 53 Table 7
- 27 Affected Small Firms as a Percent of Small Firms Nationwide, Final NESHAP Amendments ...... 7 - 54 Table 7
- 28 Affected Small Firms as a Percent of Small Firms Nationwide, Final NSPS and NESHAP

Amendments ................................ ................................ ................................ ................................ ..... 7 - 55viii **LIST OF FIGURES** Figure 2
- 1 A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990
- 2008. B) Domestic

Natural Gas Proved Reserves and Cumulative Production, 1990
- 2008 ................................ ........... 2 - 12 Figure 2
- 2 A) Total Producing Crude Oil Wells and Average Well Productivity, 1990
- 2009. B) Total Producing

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

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

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

2 - 36 Figure 2
- 13 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
- 2009 ................................ ................................ ................. 2 - 41 Figure 2
- 15 Em

ployment in Natural Gas Liquid Extraction (NAICS 211112), Employment in Pipeline Transportation of Natural Gas (NAIC S 486210), and Total Natural Gas Production, 1990
- 2009 ... 2 - 42 Figure 2
- 16 Oil and Natural Gas Industry Average Wages by NAICS, 1990
- 20 09 ($2008)
............................... 2 - 44 Figure 3
- 1 Sensitivity of Final NSPS Annualized Costs to Natural Gas Prices and REC Costs ........................ 3 - 24 Figure 3
- 2 Sensitivity of Final NSPS Annualized Costs to Natural Gas Prices and Emissions Factor for

Hydraulically Fractured Natural Gas Well Completions ................................ ................................ .. 3 - 26 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 - 11 Figure 4
- 3 Estimated Chronic Census Tract Noncancer (Respiratory) Risk from HAP exposure from outdoor

sources (2005 NATA) ................................ ................................ ................................ ...................... 4 - 12 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 Protection Agency (EPA) reviewed the New Source Performance Standards (NSPS) for volatile organic compound and sulfur dioxide emissions from Natural Gas Processing Plant s. 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 org anic compounds ( VOC ) from Natural Gas Processing Plants, and finalizes the NSPS for stationary sources 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 f

or two source categories in the Oil and Natural Ga s sector regulated by separate National Emission Standards for Hazardous Air P ollutants (NESHAP) . It also 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 provisions in these NESHAP related to emissions during periods of startup, shutdown, and malfunction. As part of the regulatory

process, EPA is required to develop a regulatory impact anal ys is (RIA) for rules that have costs or benefits that exceed $100 million annually . 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 o f human health and climate impacts anticipated from the final NSPS and NESHAP Amendments . We also estimate potential impacts of the final rules on the national energy econom y using the U.S. Energy In formation Administration’s National Energy Modeling S ys tem (NEMS). The engineering compliance costs are annualized using a 7 percent discount rate . This anal ysis assumes an anal ys is year of 2015. The final NSPS contains provisions related to reduced emissions completions, pneumatic controllers, and storage vessels that phase
- in emissions control requirements over time. As a result of these provisions, 2015 is the first year that the full1 - 2

requirements of the NSPS ar e in effect. Because of the phase
- in provisions of the NSPS, the RIA does not present an accurate assessment of the period between promulgation and the end of 2014, but is accurate for 2015. Several emission controls for the NSPS , such as reduced emission s completions (RECs) of hydraulicall y fractured natural gas wells, 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. RECs also recover saleable h ydrocarbon condensates that 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 ad ditional product recovery and the revenues we expect producers to gain from the additional product recovery. The primary

basel ine used for the impacts analy sis of our NSPS for completions of hydraulicall y fractured natural gas wells takes into account RECs conducted pursuant to state regulations covering these operations and estimates of RECs performed voluntarily . To account fo r RECs performed in regulated states, EPA subsumed emissions reductions and compliance costs in states where these completion
- related emissions are already controlled into the baseline. Additionally , based on public comments and reports to EPA's Natural G as STAR program, EPA recognizes that some producers conduct well completions using REC techniques voluntarily for economic and/or environmental objectives as a normal part of business. To account for emissions reductions and costs arising from voluntary implementation of pollution controls EPA used information on total emissions reductions reported to the EPA by partners of the EPA Natural Gas STAR. This estimate of this voluntary REC activity

in the absence of regulation i s also included in the baseline . 1 More detailed discussion on the derivation of the baseline is presented in a technical memorandum in the docket, as well as in Section 3 of this RIA.

1 Voluntary short
- term actions (such as REC) are challenging to capture accurately in a prospective analysis, as such reductions are not guaranteed to continue. However, Natural Gas STAR represents a nearly 20 year voluntary initiative with participation from 124 natural gas companies operating in the U.S., including 28 producers, over a wide historical range of natural gas prices. This unique program and dataset, the significant impact of voluntary REC on the projected cost and emissions reductions (due to significant REC activity), an d the fact that RECs can actually increase natural gas recovered from natural gas wells (offering a clear incentive to c ontinue the practice), led the A gency to conclude that it was appropriate to estimate these particular voluntary actions in the baseline for this rule.1 - 3

Additionally , we provide summary
- level estimates of emissions reductions and engineering compliance cos ts for a case where no voluntary RECs are assumed to occur. This alternative case is presented in order to show impacts if conditions were such that RECs were no longer performed on a voluntary basis, but rather were compelled by the regulation, and serve s in part to capture the inherent uncertainty in projecting voluntary activity into the future . As such, this alternative case establishes the full universe of emissions reductions that are guaranteed b y this NSPS (those that are required to occur under th e rule, including those that would likely occur voluntaril y). While the primary baseline may better represent actual costs (and emissions reductions) beyond those already expected under business as usual, the alternative case better captures the full amount of emissions reductions where the NSPS acts as a backstop to ensure that emission reduction practices occur (practices covered b y this rule). **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 190,000 tons of VOC, as well as from 11,000 tons of hazardous air pollutants (HAP) and 1.0 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 . 2 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 indire ct 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, ecos ys tem effects, as well as additional natural gas recovery . Th e methane emissions reductions associated with the final NSPS are likely to result in climate co
benefits. 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 ), 550 tons of nitrogen oxides (N O x ) , 19 tons of PM, 3,000 tons of CO, and 1,100 tons of total

2 Previous studies have estimated the monetized benefits
- per - ton of reducing VOC emissions associated with the 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). While these ranges of benefit
- per - ton estimates provide useful context for the break
even analysis, the geographic distribution of VOC emissions from the oil and gas sector are not consistent with emissions modeled in Fann, Fulcher, an d Hubbell (2009). In addition, the benefit
- per - ton estimates for VOC emission reductions in that study are derived from total VOC emissions across all sectors. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 an d the highly localized nature of air quality responses associated with VOC reductions, these factors lead us to conclude that the available VOC benefit
- per - ton estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding exercise.1 - 4

hydrocarbons (THC) as well as emission reductions associated with the energy s ys tem impacts. The net CO 2 - equivalent (CO 2 - e ) emission reduc tions are 18 million metric tons . I f the EPA's estimate of voluntary action is not included in the NSPS baseline (only REC under state regulations are assumed to occur absent the NSPS) , the emissions reductions achieved by the final NSPS in HAP, methane and VOC are estimated at about 19,000 tons, 1.7 million tons and 290,000 tons, respectively .  **Engineering Cost Analysis:** EPA estimates the total capital cost of the final NSPS will be $ 25 million , regardless of baseline assumptions . T he estimate of total annualized engineering costs of the final NSPS is $170 million
. When estimated revenues from additional natural gas and condensate recovery are included, the annualized engineering costs of the final NSPS are estimated to be
- $15 million , assuming a wellh ead natural gas price of $4/thousand cubic feet (Mcf) and condensate price of $70/barrel. Possible explanations for why there appear to be negative cost control technologies are discussed in the engineering costs anal ys is section in the RIA. The estimate d 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 $ 43 million , given EPA estimates that 43 billion cubic feet of natural gas will be recovered by imple menting the NSPS . If voluntary action is n ot deducted from the baseline, capital costs for the NSPS under the alternative regulatory

baseline are estimated at $25 million, and annualized costs without revenues from product recovery

for the NSPS are estimated at $330 million. In this scenario, giv en the assumptions about product prices, estimated revenues from product recovery are $350 million, yielding an estimated cost of savings of about $22 million. All estimates are in 2008 dollars.  **Small Entity Analyses:** For the final NSPS, EPA performed a s creening analy sis 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 123 of the 127 small firms analyzed (96.9 percent) are likely to have impacts less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, four firms (3.1 percent) are likely to have impacts greater than 1 percent. Three of these four firms are likely to have impacts greater than 3 percent. However, when revenue from additional natural gas product recovery is included, we estimate that none of the anal yz ed firms will have an impact greater than 1 percent.

 **Employment Impacts Analysis:** EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipment, as well as labor associated with new reporting and recordkeeping requirements. We estimate up
- front and continual, annual labor requirements b y estimating hours of lab or 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 th e final NSPS is estimated at 50 full
- time
- equivalent emp loyees. The annual labor requirement to comply with final NSPS is estimated at about 570 full
- 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 create d for new employe es , versus displacing jobs from other sectors of the econom y .1 - 5

**Table 1**  **- 1**  **Summary of the Monetized Benefits, Costs, and Net Benefits for the Final Oil and Natural Gas NSPS in 2015**  **1 Final**  **4** Total Monetized Benefits 2 N/A Total Costs 3 - $1 5 million Net Benefits N/A Non - monetized Benefits 6 190,000 tons of VOC 11,000 tons of HAP 5 1. 0 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. 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 The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefi ts, including an increase of 1.1 million tons of carbon dioxide (CO 2 ), 550 tons of nitrogen oxides (N O x ) , 19 tons of PM, 3,000 tons of CO, and 1,100 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO 2 - equi valent (CO 2 - e ) emission reductions are 18 million metric tons.1 - 6

**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 670 tons of HAP , as well as 1,200 tons of VOC and 4 20 tons of methane. While we expect that these avoided emissions will result in improvements in ambient air quality and reductions in health effects associated with exposure to HAP , ozone, and PM , we have determined that quantification of those benefits cannot be accomplished for this rule. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currentl y available. 3 In addition to health improvements, there will be improvements in visibility effects, ecosy stem effects, and climate effects . The specific control technologies for the NESHAP are anticipated to have minor secondary disbenefits, but EPA was unable to estimate these secondary disbenefits . The net CO 2 - equivalent emission reductions are about 8 ,000 metric tons.

 **Engineering Cost Analysis:** EPA estimates the total capital costs of the final NESHAP Amendments to be $2.8 million. Tota l annualized engineering costs, which includes annualized capital costs and operating and maintenance costs, of the final NESHAP Amendments are estimated to be $3.5 m i llion. All estimates are in 2008 dollars.

 **Small Entity Analyses:** For the final NESHAP Amendments, EPA estimates that 11 of the 35 firms ( 31 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, none of the 11 ( zero percent) are likely

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

 **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 req uired 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 4 full
- time
- equivale nt employees. The annual labor requirement to comply

with final NESHAP Amendments is estimated at about 30 full
- time
- equivalent employees. We note that this ty pe of FTE estimate cannot be used to identify the specific
3 Previous studies have estimated the monetized benefits
- per - ton of reducing VOC emissions associated with the 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). While these ranges of benefit
- per - ton estimates provide useful context for the break
even analysis, the geographic distribution of VOC emissions from the oil and gas sector are not consistent with emissions modeled in Fann, Fulcher, and Hub bell (2009). In addition, the benefit
- per - ton estimates for VOC emission reductions in that study are derived from total VOC emissions across all sectors. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 and the highly localized nature of air quality responses associated with VOC reductions, these factors lead us to conclude that the available VOC benefit
- per - ton estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding exercise.1 - 7

number of people involved or whether n ew jobs are created for new employees, versus displacing jobs from other sectors of the econom y.
 **Break -**  **E ven Analysis:**  A break
- even anal ys is suggests that HAP emissions would need to be valued at $5,200 per ton for the benefits to exceed the costs if the he alth 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 $2,900 per ton o r the methane emissions would need to be valued **a** t $8,300 per ton for the benefits to exceed the costs. Previous assessments have shown that the PM 2.5 benefits associated with reducing VOC emissions were valued at $280 to $7,000 per ton of VOC emissions r educed 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 1**  **Final** Total Monetized Benefits 2 N/A Total Costs 3 $ 3.5 million Net Benefits N/A Non - monetized Benefits 5 670 tons of HAP 1,200 tons of VOC 4 420 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 quantificatio n 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 i mp acts of the reductions in emissions for this industrial sector with the data currently available. 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 climate effects are co
- benefits. 5 The specific control technologies for the NESHAP are anticipated to have minor secondary disbenefits, but EPA wa s unable to estimate these secondary disbenefits . The net CO 2 - equivalent emission reductions are 8 ,000 metric1 - 8

tons. **1.2.3 Results of**  **Energy System Impacts Analysis**  **of the NSPS and NESHAP Amendments** The anal ys is of energy

s ystem impacts using NEMS for the final NSPS shows that domestic natural gas production is not like ly to change in 2015, the year used in the RIA to anal yz e impacts. Average natural gas prices are also not estimated to change in re s ponse to the final rules. Domestic crude oil production is not expected to change, while average crude oil prices are est imated to decrease slightl y (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. **1.2.4 Results for Combined Small Entity Analysis for the NSPS and NESHAP Amendments**  After consi dering the economic impact of the combined NSPS and NESHAP Amendments on small entities, EPA certifies this action will not have a significant economic impact on a substantial number of small entities (SI SNOSE). While both the NSPS and NESHAP amendment wou ld individually result in a no SI SNOSE finding, EPA performed an additional screening 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 analy zed for the NSPS. When revenues from additional natural gas pro duct sales are not included, 132 of the 136 small firms (97 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, four firms (3 percent) are likely to have impacts greater than 1 percent. Three of these four firms are likely to have impacts greater than 3 percent. When revenues from additional natural gas product sales ar e included, all 136 small firms ( 100 percent) in the sample are likely to have impacts of less than 1 percent. **1.3 Summary of NSPS Impacts Changes from the Proposal RIA**  This section summarizes major changes from the proposal version of the RIA. These changes were a result of revised assumptions and technical factors, as well as changes in the rule itself from proposal.

 **Revised baseline to include voluntary REC s**  **:** T he NSPS analy sis used a baseline that accounted for emission controls required b y state regulation, but did not include1 - 9

voluntary actions. In the final RIA, t o account for emissions reductions and costs arising in the baseline from voluntary implementation of pollution controls, EPA used information on total emissions reductions reported by partners of the EPA Natural Gas STAR. Additionally , we provide summary
- level estimates of emissions reductions and engineering compliance costs for a case where no voluntary reduced emission completions ( REC ) are assumed to occur. This alternative case is presented in order to show impacts if conditions were such that RECs were no longer performed on a voluntary basis, but rather were compelled by the regulation.  **Change d estimate of number of recompleted**  **natural gas wells:**  The NSPS proposal estimated that 12, 050 REC s for existing natural gas well recompletions would be required in addition to those already required b y s tate regulations. EPA has reevaluated the assumptio n based on data submitted to the Agency . Based on this information, EPA has estimated the recompletion frequency to be 1 percent of fractured gas wells per year , rather than 10 percent . More detailed discussion is presented in a technical memorandum on th is subject in the docket. **4**  **Recompletions of existing natural gas wells that are hydraulically refractured:** In the final rule, recompletions of existing natural gas wells that are hydraulically refractured are only

subject to the NSPS if emissions from these completions are uncontrolled.  **New hydraulically fractured natural gas w ell completions**  **with insufficient pressure to implement**  **REC required to combust completions emissions:**  Using the formula estimated to identify

hydraulicall y fractured natural gas well completions that would not have sufficient pressure to perform a REC, ap proximately 10 percent of well completions would be required to combust emissions rather than implement a REC. More detailed discu ssion is presented in a technical memorandum on this subject in the docket. **5**  **Revised natural gas emissions factor for well completions and recompletions of hydraulically fractured wells:**  The EPA received several comments regarding the emission s factor sele cted to calculate whole gas emissions (and the associated VOC emissions) from hydraulically fractured well completions. Comments focused on the data behind the emission s factor, what the emissions factor is intended to represent, and the procedures used to develop the emission s factor from the selected data sets. We reviewed all information received and have decided to retain the data set and the anal ys is conducted to develop the emission s factor , but rounded from 9,175 Mcf per completion

4 “ Gas Well Refr acture Frequency” in U.S. Environmental Protection Agency Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Support Document for the Final New Source Performance Standards. EPA
- 453/R
- 11 - 002. April 2012. 5 “NSPS Low Pressure Completion Threshold” in U.S. E nvironmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Produc tion, Transmission, and Distribution: Background Supplemental Technical Support Document for the Final New Source Performance Standards. EPA
453/R
- 11 - 002. April 2012.1 - 10

to 9,000 Mcf per completion. More detailed discussion is presented in a technical memorandum on this subject in the docket. 6  **Change d**  **estimate of REC and completion emission combustion capital costs:** The requirements related to completions of hydraulically fractured natural gas wells (combustion and REC) are essentiall y one - shot events that ty picall y occur over a few day s to a couple of weeks and are generally performed by

independent contractors. 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 . Given that we base our REC costs estimates on the average cost for contracting the REC as a service, we expect contractors’ operation and maintenance costs, depreciations, and potential salv age value of the equipment to be reflected in the total contracting costs. Because of these factors, we decided to treat the hydraulicall y fractured natural gas well completion requirem ents solel y as annualized costs, which differed from our anal ys is at p roposal, which equated capital and annualized costs.  **Removal of compressors and pneumatic devices in the natural gas transmission**  **segment from NSPS:** In the final rule, proposed requirements relating to reciprocating and centrifugal compressors and pneumati c devices in the transmission segment are removed. G iven the large number of sour ces, and the relativel y low level of VOCs emitted from these sources, we have concluded that additional evaluation of these compliance and burden issues is appropriate prior to taking final action on compressors and pneumatic controllers in the transmission and storage segment. Requirements pertaining to storage vessels in the transmission segment remain.  **Reporting and recordkeeping costs** : EPA identified several way s to stream line reporting and recordkeeping requirements. As a result, the estimated annual cost of reporting and recordkeeping decreased from $19 million per year to $ 2.6 million per ye ar. **1.4 Summary of**  **NESHAP Amendments Im**  **pacts Changes from the Proposal RIA** The cost and emissions reduction estimates for the NESHAP Amendments are reduced from proposal because proposed provisions related to storage vessels were not finalized from proposal, as well as because of changes to the proposed provisions for small gycol deh ydrat ors. The estimated capital costs of the NESHAP Amendments decreased by about $ 49 million (from $52 to about $ 3 million), while estimated total annualized compliance costs decreased b y about $ 12.5 million per year (from $16 to $ 3.5 million per year) . As a result, e stimated HAP reductions decreased b y about 710 tons per year from proposal (from 1,380 to 670 tons per year).

6 “E valuation of the Emissions factor for Hydraulically Fractured Gas Well Completions” in U.S. E nvironmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Su pport Document for the Final New Source Performance Standards. EPA
- 453/R
- 11 - 002. April 2012.1 - 11

Also, b ecause of changes in emissions limits from proposal, fewer gl ycol dehydrators are affected, which reduces capital and annualized costs , as well as emissions reductions for these emissions points. **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 . Section 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 prese nts 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 mark eting. 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. Mo st 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 NSPS and NESHAP Amendments . The outputs of the oil and natural gas ind ustry are inputs for larger production processes of gas, energy , and petroleum products. As of 2009, the Energy Information Administration ( EIA ) estimates that about 526,000 producing oil wells and 493,000 producing natural gas wells operated in the United States. Domestic dry natural gas production was 20.5 trillion cubic feet (tcf) in 2009, the highest production level since 1970. The leading five natural gas producing states are Texas, Alas ka, 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 N otebook 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 use d in the manufacture 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 concentration 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 gravit y in the range of the high 30's to the low 40's. Crude oils recovered in the produ ction phase of the petroleum industry may be referred to as live crudes. Live crudes contain entrained or dissolved gases which may be released during processing or storage . D ead crudes are those that have gone through various separation and storage phas es 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 natura l2 - 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 produc ed 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 are 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 treating. 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 so ur gases. A majority of total onshore natural gas production and nearl y all 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 wel lbore 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 ydrocarbons 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 oper ation s . **2.3 Oil and Natural Gas Production Processes**  **2.3.1 Ex** 

**ploration and Drilling** Exploration involves the search for rock 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 su fficient quantities. After the site of a well has been located, drilling commences. A well bore is created b y 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 bor e is cased in with telescoping steel piping during drilling to avoid its collapse and to prevent water infiltration into the well and to prevent crude oil and natural gas from contaminating the water table. The steel pipe is cemented by filling the gap between the steel casing and the wellbore with cement . Horizontal drilling technology has been available since the 1950s. Horizontal drilling facilitates the construction of horizontal wells by allowing for the well bore to run horizont ally underground, increasing the surface area of contact between the reservoir and the well bore so that more oil or natural gas can move into the well. Horizontal wells are 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 trajecto ry . Hydraulic fracturing (also referred to as “fracking”) has been performed since the 1940s (U.S. DOE, 2009) . Hydraulic fracturing involves pumping fluids into the well under very high pressures in order to fracture the formation containing the resource. Proppant is a mix of sand and other materials that is pumped down to hold the fractures open to secure gas flow from the formation (U.S. EPA, 2004) . **2.3.2 Production**  Production is the process of extracting the h ydrocarbons and separating the mixture of liqui d hydrocarbons, gas, water, and solids, removing the constituents that are non
- saleable, and selling the liquid hydrocarbons and gas. The major activities of crude oil and natural gas production are bringing the fluid to the surface, separating the liquid and gas components, and removing impurities. Oil and natural gas are found in the pores of rock s and sand (H yn e, 2001) . I n a conventional source, the oil and natural gas have been pus hed out of these pores by water and moved until an impermeable surfac e 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 associ ated 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 pro duced from the same reservoir. As wells deplete the reservoirs into which they are drilled, the gas to oil ratio increases (as does the ratio of water to hydrocarbons). This increase of gas over oil occurs because natural gas usually is in the top of the oil formation, while the well usually is drilled into the bottom portion to recover most of the liquid. Production sites often handle crude oil and natural gas from more than one well (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 resource 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** or **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 trapped in rock or sand or, in the case of oil, are found in rock as a chemical substance that requires a further chemical transform ation 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 l ow 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:** Reservoirs are composed of low
- porosit y 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 i n the coal or from alterations of the coal through temperature changes. Horizontal drilling2 - 7

is used but given that coalbed methane reservoirs are frequentl y associated with underground water reservoirs, hydraulic fracturing is often restricted (Andrews, 2 009) . **2.3.3 Natural Gas Processing**  Natural gas conditioning is the process of removing impurities from the gas stream so that it is of sufficient quality to pass through transportation sy stems and used by final consumers. Conditioning is not always required. N atural 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 co nditioning process. Another concern is that posed by water vapor. At high pressures, water can react with components in the gas to form gas h ydrates, 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 from the methane prior to sale. High vapor pressure hydrocarbons that are liquids at surface temperature and pressure (benzene, toluene, eth ylbenzene, 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 point of water. Finally , particularl y for gas extracted from deep, hot wells, simply cooling the gas to a temperatur e 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 sometime s 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 solution, 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 market exists, sending it to a sulfur
- recovery

facility to generate elemental sulfur as a salable product. **2.3.4 Natural Gas**  **Trans mission and Distribution**  After processing, natural gas enters a network of compressor stations, high
- pressure transmission pipelines, and often
- underground storage sites. Compressor stations are any facility which supplies energy

to move natural gas at increased pressure in transmission pipelines or into underground storage. Typically , compressor stations are located at intervals along a transmission pipeline to maintain desired pressure for natural gas transport. These stations will use either large internal combustion engines or gas turbines as prime movers to provide the necessary horsepower to maintain system pressure. Underground storage facilities are subsurface facilities utilized for storing natural gas which has been transferred from its o riginal 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 R**  **eserves 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 clo se to where it is produced. However, 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, con sumption, and foreign trade of crude oil and natural gas .2 - 9

**2.4.1 Domestic Proved Reserves**  Table 2 - 1 shows crude oil and dry natural gas proved reserves, inferred reserves, undiscovered technicall y recoverable resources and total technically recoverable resources as of 2007. According to EIA 7 , 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 rec overable 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. According to EIA, dry

natural gas is consumer
- grade natural gas . Th e dry natural gas volumes reported in Table 2
- 1 reflect the amount of gas remaining after liquefiable portion has been removed from the natural gas, as well as any non - hydrocarbon gases that render the natural gas unmarketable have been removed. The sum of proved reserves, inferred reserves, and undiscovered technicall y recoverable 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

technically

recoverable crude oil resources.

7 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 .0 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 technic all y recoverable natural gas resources. Significant proportions of these reserves exist in Alaska and offshore areas. While the dry

natural gas proved reserves in 2007 were estimated at 237.7 tcf, wet natural gas reserves were estimated at 247.8 tcf. Of this difference , about 9.1 tcf is accounted for by natural gas liquids. Of the 247.8 tcf, 215.1 tcf (about 87 percent) is considered to be wet non
associated natural gas, while 32.7 tcf (about 13 percent) is considered to be wet associated
dissolved natural gas. Associated
- dissolved natural gas, according to EIA, is natural gas which occurs in crude oil reservoirs as free natural gas or in solution with crude oil. Table 2 - 2 and Figure 2 - 1 show trends in crude oil and natural gas production and reserves from 1990 to 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 become2 - 11

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. F or example, when oil prices are high there is more of an incentive to use secondary and tertiary recovery , as well as to develop unconventional sources.

**Table 2**  **- 2**  **Crude Oil and Natural Gas Cumulative Domestic Production, Proved**  **Reserves, and Proved Ultimate Recovery, 1977 -**  **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 and Cumulative Production, 1990 -**  **2008. B**  **) Domestic**  **Natural Gas Proved Reserves and Cumulative Production, 1990 -**  **2008** Table 2 - 3 presents the U.S. proved reserves o f crude oil and natural gas 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 Wyom ing 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 generally increasing tr end . The exceptio n to this general trend occurred in 2008 and 2009 when the real price increased up to 86 dollars per barrel and production in 2009 increased to almost 2 million bbl of oil. Annual production of natural gas from natural gas well s has increased nearl y 3000 bcf from the 1990 to 2009 ( Table 2 - 5 ) . Natural gas extracted from crude oil wells (associated natural gas) has remained more or less constant for the last twenty years . Coalbed methane has become a 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 199 0 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 Well s 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 showed significant increases, although the 1992
- 2001 period showed relativel y l ow 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 pe riod . 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 frac turing activities ( ANL 2009 ) .2 - 18

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

State Crude Oil

(1000 bbl) Total Gas

(bcf) Produced Wate r

(1000 bbl) Total Oil and

Natural G as (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 Wyom ing 54,052 2,253 2,355,671 455,086 5.18 **State Total 1,273,759**  **21,290 20,258,560**  **5,063,379 4.00**  Federal Offshore 467,180 2,787 587,353 963,266 0.61 Tribal Lands 9,513 297 149,261 62,379 2.39 **Federal Total 476,693**  **3,084 736,614**  **1,025,645 0.72**  **U.S. Total 1,750,452**  **24,374 20,995,174**  **6,089,024 3.45**  Source: Argonne National Laboratory and Department of Energy (2009). Natural gas production converted to barrels oil equivalent to facilitate comparison using the conversion of 0.178 barrels of crude oil equals 1000 cubic feet natural gas. Totals may not sum due to independent rounding .2 - 19

As can be seen in Table 2 - 7 , the amount of water produced is not necessarily correlated with the ratio of water produced to the volume of oil or natural gas produced. Texas, Alaska and Wyoming were the three largest producers in barrels of oil equivalent (boe) terms , but had 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 - injecte d to enhance resource recovery through maintaining reservoir pressure or h ydraulically 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 movement of cru de 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 l ow - volume pipelines that gather natural gas from production sites to deliver directly to gas processing plants or compression stations that connect numerous gathering lines to transport gas primarily to processing plants. Transmission pipelines move large volumes of gas to or from processing plants to distribution points. From these distribution points, the gas enters a distribution sy stem that delivers the gas to final consumers. Table 2 - 8 shows gathering lines decr easing from 1990 from above 30,000 miles from 1990 to 1995 to around 20,000 miles in 2007 and 2008. Transmission pipelines 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 , driving an increase in total natural gas pipeline mileage ( Figure 2 - 1 ) . The growth in distribution is likely driven by expandi ng production as well as expanding gas markets in growing U.S. towns and cities. **2.4.3 Domestic Consumption**  Historical crude oil sector - level consumption trends for 1990 through 2009 are shown in Table 2 - 9 and Figure 2 - 4 . Total consumption rose 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 to 71 percent in 2009.

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

(million bbl) Residential Commercial Industrial Transportation Sector Electric

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

**Figure 2**  **- 4**  **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 c onsumption 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 92 19 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 have 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), 1990 -**  **2009** Year Crude Oil Petroleum Products Total Petroleum 1990 2,151 775 2,926 1991 2,111 673 2,784 1992 2,226 661 2,887 1993 2,477 669 3,146 1994 2,578 706 3,284 1995 2,639 586 3,225 1996 2,748 721 3,469 1997 3,002 707 3,709 1998 3,178 731 3,908 1999 3,187 774 3,961 2000 3,320 874 4,194 2001 3,405 928 4,333 2002 3,336 872 4,209 2003 3,528 949 4,477 2004 3,692 1,119 4,811 2005 3,696 1,310 5,006 2006 3,693 1,310 5,003 2007 3,661 1,255 4,916 2008 3,581 1,146 4,727 2009 3,307 973 4,280 Source: U.S. Energy Information Administration, **Annual Energy Review 2010**  **.** * 2009 Imports are preliminary. Natural gas imports also increased steadil y from 1990 to 2007 in volume and percentage terms ( Table 2 - 12 ). The years 2007 and 2008 saw imported natura l gas constituting a lower percentage of domestic natural gas consumption. In 2009, the U.S exported 700 bcf natural gas to Canada, 338 bcf to Mexico via pipeline, and 33 bcf to Japan in L NG - form. In 2009, the U.S. primarily imported natural gas from Can ada (3268 bcf, 87 percent) via pipeline, although a growing percentage of natural gas imports are in LNG
- form shipped from countries such as Trinidad and Tobago and 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 detail 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 successful offshore crude oil wells shows a variable but generally

increasing trend.2 - 27

**Table 2**  **- 13**  **Forecast of Total Successful Wells Drilled , Lower 48 States**  **, 2010 -**  **2035** 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 in crease significantly , 61 percent and 13 8 percent, respectively . 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 wel ls 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 to 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 Domesti c 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 declining trend. Meanwhile, imports of natural gas via pipeline are expected to decline dur ing the forecast perio d 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 suppl 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 oil and natural gas. These costs include exploration and development costs, as well as costs associated with the purchase or leasing of real property . EIA publishes finding costs as running three
- 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. Interestingl y, 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 pre sent similar trends overall. **2.5.2 Lifting Costs**  Lifting costs are the costs to produce crude oil or natural gas once the resource has been found and accessed. EIA’s definition of lifting costs includes costs of operating and maintaining wells and associated p roduction 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 bas is . 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 fo r 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 ffs ho 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 diverge d 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 Operat ing Costs 1994 through 2009 ” 8 , contains indices and estimated costs for domestic oil and natural gas equipment and production operations. The indices and cost trends track costs for representative operations in

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

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 generally decreased from about 1980 until the late 19 9 0s.

**Figure 2**  **- 11**  **Cru de Oil Operating Costs and Equipment Costs Indices**  **(1976=100) and Crude Oil Price**  **(in 1976 dollars) , 1976**  **- 2009**  Oil costs and prices again 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 ga s 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 decre ased from about 1980 until the mid 1990 s. The 2009 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 different 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 me nt 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 o f 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 direc ted 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 Fi** **rm s in Affected**  As of 2007, there were 6,563 firms within the 211 111 and 211112 NAICS codes, of which 6427 (98 percent) were considered small businesses ( Table 2 - 16 ). Within NAI CS 2111 11 and 211112 , large firms compose about 2 percent of the firms, but a ccount for 59 percent of employ ment and generate about 80 percent of estimated receipts 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 Gas We 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**  **- 1**  **5 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 - 1 5 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 io n (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) Su ppor 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 public oil and natural gas companies with domestic reser ves and headquarters in the U.S . In the past, th e survey reported information on the top 300 companies, now the top 150. In 2010, all 137 public companies are listed . 9 Table 2 - 19 lists selected

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

st atistics for 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). Meanwhile, the 13 7 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 d omestic 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 OGJ also re leases 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 resource s, 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 day and throughout of 45,472 million cubic feet per day

( Table 2 - 20 ). The overall trend in U.S. gas processing capacity is showing fewer, but larger facilities. For example, in 1995, there were 727 facilities with a capacity of 60,533 million cubic feet per day (U.S. DOE, 2006). Trends in gas processing facility ownership are also showing a degree of concentration, as large firms own multiple facilities, which also tend to be 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

**Table 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 pipelines is mostly

independent from ownership of oil and gas production companies, as is seen from the lack of overlap between the OGJ list of pipeline companies and the OGJ150. This observation shows that the pipeline industry is still largel y based upon firms serving regional market. The top 20 companies maintain about 63 percent of the total pipeline mileage and transport about 54 percent of the volume of the industry ( Table 2 - 21 ) . Operating revenues of 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 inco me of 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 10 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 .

10 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., Equi table Resources, Inc., Exxon Mobil Corporation, Hess Corporation, Hovensa, Lyondell Chemical Corporation, Marathon Oil Corporation, Motiva Enterprises, L.L.C., Occidental Petroleum Corporation, Shell Oil Company, Sunoco, Inc., Tesoro Petroleum Corporation, The Williams Companies, Inc., Total Holdings USA, Inc., Valero Energy Corp., WRB Refining LLC, and XTO Energy, Inc.2 - 51

Table 2 - 23 shows in percentage terms the estimated return on investments for a variety of business lines, in 1998, 2003, and 2008, for FRS companies. For U.S. petroleum
- related business activities, oil and natural gas production has remained the most profitable line of business relative to refining/marketing and pipelines, sustaining a return on investment greater than 10 percent for the three ye ars evaluated. Returns to foreign oil and natural gas production rose above domestic production in 2008. Electric power generation and sales emerged in 2008 as a 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 Investment Tax Credit ($198 million in 2008) and the effect of the Alter

n ative Minimum Tax ($34 million in 2008). Income taxes paid to state and 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 excee ds domestic taxes paid. Other non
- income production taxes p aid , which have risen almost three
- fold between 1990 and 2008, include windfall profit and severance taxes, as well as other production
- related taxes.2 - 5 3

**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. Non technical 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 Marc h 30, 2011. Manning , F.S. and R.E. Thompson. 1991. Oil Field Processing of Petroleum

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

Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial Link between Natural Gas Production and 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/oi l
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_publications/crude_oil_natural_gas_re serves/cr.html > Accessed March 30, 2011. U.S. Energy

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

Information Administration (U.S. EIA) . 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 Industry . EPA/310
- R - 99 - 006. <http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/oil. html > Accessed March 30, 2011.3 - 1 **3 EMISSIONS AND 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 fo r 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 memoran da 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 sm all business 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 fi nal rules . To estimate VOC emissions from the oil and gas sector, we modified the emissions estimate for the crude oil and natural gas sector in the 2008 National Emissions Inventory (NE I). During this review, EPA identified VOC emissions from natural ga s sources that 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 about 21 thousand tons emitted from natural gas well completion processes. We substituted the estimates of VOC emissions from natural gas well completions estimated as part of the engineering anal ys is ( 1 32 ,000 tons, which is discussed in more d etail in the next section), bringing the total estimated VOC emissions from the crude oil and natural gas sector to about 1. 87 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 sign ificant 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 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 emissions sources and the controls evaluated for each source to facilitate the reader’s understanding of the economic impact and benefit analy ses. T he 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 proposal Technical Support Document (TSD) and Background Supplemental Technical Support Document for the Final New Source Performance Standards, which are published in the Docket. Technical memos that also discuss revisions to the proposal TSD are noted in the relevant sections. **Centrifugal and r e**  **c iprocating**  **compressors** 11 **:** 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 by

compressors powered b y combustion turbines, reciprocating inter nal combustion engines, or electric motors. Turbine
- powered compressors use a small portion of the natural gas that they

compress to fuel the turbine. The turbine operates a centrifugal compressor, which compresses and pumps the natural gas through the p ipeline. Sometimes an electric motor is used to turn a centrifugal compressor. This type of compression does not require the use of

11 “Centrifugal Compressor Impacts” in U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Support Document fo r the Final New Source Performance Standards. EPA
- 453/R
- 11 - 002. April 2012.3 - 3

any of the natural gas from the pipeline, but it does require a source of electricity . Reciprocating spark ignition engin es are also used to power many compressors, referred to as reciprocating compressors, since they

compress gas using pistons that are driven b y the engine. Like combustion turbines, these engines are fueled b y natural gas from the pipeline. Both centrifu gal and reciprocating compressors are sources of VOC emissions, and EPA evaluated compressors for coverage under the NSPS. Centrifugal compressors require seals around the rotating shaft to prevent gases from escaping where the shaft exits the compressor casing. The seals in some compressors use oil, which is circulated under high pressure between three rings around the compressor shaft, forming a barrier against the compressed gas leakage. Very little gas escapes through the oil barrier, but considerable gas is absorbed by the oil. Seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated, and the gas is commonly vented to the atmosphere. These are commonly called “wet” seals. An alternative to a wet seal sy stem is the mechanical 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 aro und the compressor shaft. The use of dry gas seals substantially

reduces emissions. In addition, they

significantly

reduce operating costs and enhance compressor efficiency . Reciprocating compressors in the natural gas industry leak natural gas during no rmal 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 move freely . Monitoring and replacing compressor rod packing s ys tems on a regular basis can greatl y reduce VOC emissions. **Equipment leaks:** Equipment leaks are fugitive emissions emanating from valves, pump seals, flanges, comp ressor 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 compr essors 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 of3 - 4

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 significant . Natural gas processing plants, especially those using refrigerated absorption, and transmission stations tend to have a large number of components. These types of equipment also exist at production sites and gas transmission/compressor stations. While the number of components at individual transmission/compressor stations is relatively smaller than at processing plants, collectively there are many

components that can result in significant emissions. Therefore, EPA evaluated the 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** : Pneumatic controllers are automated instruments used for maintaining a process condition such as liquid level, pressure, delta
- pressure, and temperature. Pneumatic controllers are widel y used in the oil and natural gas sector. In many situations, the pneumatic controllers us ed in the oil and gas sector make use of the available high
- pressure natural gas to regulate temperature, pressure, liquid level, and flow rate across all areas of the industry . In these “gas
- driven” pneumatic controllers, natural gas may be released with every

valve movement or continuously from the valve control pilot. Not all pneumatic controllers are gas driven. These “non
- gas driven” pneumatic controllers use sources of power other than pressurized natural gas. Examples include solar, electric, and instrument air. At oil and gas locations with electrical service, non gas
- driven controllers are typically used. Gas
- driven pneumatic controllers are ty picall y characterized as “high
- bleed” or “low
- bleed”, where a high
bleed device releases at least 6 c ubic feet of gas per hour. EPA evaluated the impact of requiring low
- bleed controllers. **Storage vessels 12**  : Crude oil, condensate, and produced water are typicall y stored in fixed
- roof storage vessels. Some vessels used for storing produced water may be o pen - top tanks. These

12 “Update to Technical Support Document for Proposed Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution
- Equipment Leaks” in U.S. E nvironmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Support Document for the Final New Source Performance Standard s. EPA - 453/R
- 11 - 002. April 2012.3 - 5

vessels, which are operated at or near atmospheric pressure conditions, are ty picall y located at tank batteries. A tank battery refers to the collection of process equipment used to separate, treat, and store crude oil, condensate, n atural gas, and produced water. The extracted products from production wells enter the tank battery through the production header, which may collect product from man y wells. Emissions from storage vessels are a result of working, breathing, and flash los ses. Working losses occur due to the emptying and filling of storage tanks. Breathing losses are the release of gas associated with daily temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid with entrained gases is tr ansferred 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 conde nsates 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 s will occur in the storage stage. The two way s of controlling tanks with significant emissions wou ld 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** : In the oil and natural gas sector, well completions contain multi
- phase processes with various sources of emissions. One specific emission source during completion activities is the venting of natural gas to the atmosphere during flowback. Flowback emissions are short
- term in nature and occur as a specific event during completion of a new well or during activities that involve re
- drilling or re
- fracturing an existing well. Well completions include multiple steps after the well bore hole has reached the target depth. These steps include inserting and cementing
- in well casing, perforating the casing at one or more producing horizons, and often hydraulically

fracturing one or more zones in the reservoir to stimulate production. Hydraulic fracturing is one completion step for improving natural gas production where the reservoir rock is fractured with very high pressure fluid, ty

picall y water emulsion with proppant (generall y sand) that “props open” the fractures after fluid pressure is reduced. Emissions are a result of the backflow of the fracture fluids and reservoir gas at high velocity ne cessary 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 the3 - 6

collection of water, sand, and hydrocarbon liquids. As the fracture f luids are depleted, the backflow eventuall y contains more volume of natural gas from the formation. Thus, we estimate natural gas c ompletions involving hydraulic fracturing vent substantiall y m ore natural gas , approximately

23 0 times more, than natural ga s completions not involving hydraulic fracturing. Specificall y, we estimate that uncontrolled natural gas well completion emissions for a hydraulicall y fractured natural gas well are about 23 tons of VOC, where emissions for a conventional natural ga s wel l completion are around 0.1 ton of VOC. Our data indicate that hydraulicall y fractured natural gas wells have higher emissions but we believe some natural gas wells that are not h ydraulically fractured may have higher emissions than our data show , or in s ome cases, h ydraulically fractured natural gas wells could have lower emissions than our data show. Reduced emission completions, which are sometimes referred to as “green completions” or “flareless completions,” use equipment at the well site to capture and treat natural gas so it can be directed into the sales line and avoid emissions from venting. Equipment required to conduct a reduced emissions completion at a natural gas well may include tankage, special gas
- liquid
sand separator traps, and gas de hydration. Equipment costs associated with reduced emission completions of natural gas wells will vary from well to well. Based on information provided to the EPA Natural Gas STAR program, 90 percent of natural gas potentiall y 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 emiss ions and the controls intended for each to facilitate the reader’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 r eferred to the relevant technical memos , which are published in the Docket. The memos are also referenced below.3 - 7

**Glycol dehydrators** 13 : Once natural gas has been separated from any liquid materials or products (e.g., crude oil, condensate, or produced wate r), residual entrained water is removed from the natural gas b y dehydration. Deh ydration 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 g as dehydration processes are gl yc ol deh ydration and solid desiccant dehydration. Solid desiccant dehydration , which is ty picall y onl y used for lower throughputs, 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, directl 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 (1) to 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 g lycol (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 a lso 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 n ot only reduce emissions, but also recover condensable h ydrocarbon 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, i ncinerator, 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 recovered 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

13 Memorandum from Brown, H., EC/R Incorporated to Moore, B., and Nizich, G., EPA/OAQPS/SPPD/FIG. Im pacts of Final MACT Standards for Glycol Dehydration Units

– Oil and Natural Gas Production and Natural Gas Transmission and St orage Source Categories. April 17 , 2012 .3 - 8

emi ssion reduction efficiency by reducing the concentration of non
- condensable gases present in the stream prior to being introduced into the condenser. **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 impacts is presented in a series of memos published in the Docket as part of the TSD. 3.2.2.1 NSPS Sources Table 3 - 1 shows the emissions sources, points, and controls anal yz ed in the anal ys is supporting the proposed and final rule s . The final NSPS contains reduced emission completion (REC) and completion c ombustion requirements for a subset of newl y drilled natural gas wells that are h ydraulicall y fractured. The NSPS also requires a subset of natural gas wells that are recompleted using h ydraulic fracturing to implement a REC and emissions combustion . The NSPS requires emissions reductions from reciprocating compressors at gathering and boosting stations and processing plants . The NSPS also requires emissions reductions from centrifugal compressors at processing plants . Finally , the NSPS requires emission s reductions from pneumatic controllers at oil and gas production facilities and reductions from storage vessels that emit at least six tons of VOC per year .3 - 9

**Table 3**  **- 1**  **Emissions Sources,**  **Points ,**  **and Controls Evaluated**  **at Proposal for the NSPS**  Emissions Sources and Point s Emissions Control Covered by Final NSPS **Crude Oil and Natural Gas Well Completions**  Hydraulically Fractured Gas Wells that Meet Criteria for Reduced Emissions Completion (REC) REC /Com bustion **X** Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC Com bustion **X** Conventional Gas Wells Com bustion Oil Wells Com bustion **Crude Oil and Natural Gas Well**  **Rec om**  **pletions** Hydraulically Ref

ractured Gas Wells that Meet Criteria for Reduced Emissions Completion (REC) REC/Combustion **X** Hydraulically Refractured Gas Wells that Do Not Meet Criteria for REC Com bustion **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 Compressor Stations NSPS Subpart VV **Reciprocating Com pressors**  Well Pads Annual Monitoring/ Maintenance (AMM) Gathering and Boosting Stations AMM **X** Processing Plants AMM **X** Transmission Compressor Stations AMM Underground Storage Facilities AMM **Centrifugal Com pressors**  Processing Plants Route to c ontrol **X** Transmission Compressor Stations Route to c ontrol **Pneumatic Controllers**  **-** Oil and Gas Production Emissions limit **X** Natural Gas Transmission and Storage Emissions limit Processing Plants Emissions limit **X Storage Vessels**  Emissions at least 6 tons per year 95% control **X** Emissions less than 6 tons per year 95% control3 - 10

As discussed in the Executive Summary , several emission controls for the NSPS, such as reduced emissions completions (RECs) of hydraulically fractured natural gas wells, 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. RECs also recover saleable h ydrocarbon condensates that 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 th e ad ditional product recovery and the revenues we expect producers to gain from the additional product recovery . The primary

baseline used for the impacts analy sis of our NSPS for completions of hydraulicall y fractured natural gas wells takes into account RECs conducted pursuant to state regulations covering these operations and estimates of RECs performed voluntarily . To account for RECs performed in regulated states, EPA subsumed emissions reductions and compliance costs in states where these completion
- related emissions are already controlled into the baseline. Additionally , based on public comments and reports to EPA's Natural Gas STAR program, EPA recognizes that some producers conduct well completions using REC techniques voluntarily for economic and

/or environmental objectives as a normal part of business. To account for emissions reductions and costs arising from voluntary implementation of pollution controls EPA used information on total emissions reductions reported to the EPA by partners of the E PA Natural Gas STAR. This estimate of this voluntary REC activity

in the absence of regulation i s therefore also in the baseline . 14 More detailed discussion on the derivation of the baseline is presented in a technical memorandum in the docket, as well as in the RIA.

14 Voluntary short
- term actions (such as REC) are challenging to capture accurately in a prospective analysis, as such reductions are not guaranteed to continue. However, Natural Gas STAR represents a nearly 20 year voluntary initiative with participation from 124 natural gas companies operating in the U.S., including 28 producers, over a wide historical range of natural gas prices. This unique program and dataset, the significant impact of voluntary REC on the p rojected cost and emissions reductions (due to significant REC activity), and the fact that RECs can actually increase natural gas recovered from natural gas wells (offering a clear incentive to c ontinue the practice), led the A gency to conclude that it wa s appropriate to estimate these particular voluntary actions in the baseline for this rule.3 - 11

Additionally , in the RIA, we provide summary
- level estimates of emissions reductions and engineering compliance costs for a case where no voluntary RECs are assumed to occur. This alternative case is presented in order to show impacts if conditions were such that RECs were no longer performed on a voluntary basis, but rather were compelled by the regulation, and serves in part to capture the inherent uncertainty i n projecting voluntary activity into the future . As such, this alternative case e stablishes the full universe of emissions reductions that are guaranteed b y this NSPS (those that are required to occur under the rule, including those that would likely

occur voluntarily). While the primary baseline may

better represent actual costs (and emissions reductions) beyond those already expected under business as usual, the alternative case better captures the full amount of emissions reductions where the NSPS acts as a backstop to ensure that emission reduction practices occur (practices covere d by this rule). Table 3 - 2 summarizes the unit level capital and annualized costs for the evaluated NSPS emissions sources and points. The detailed description of costs estimates is provided in the series of technical memos inc luded in the TSD in the Docket , as referenced in Section 3.2.1 of this RIA. The table also includes the number of affected units projected under the primary baseline and the alternative regulatory baseline . Four issues are important to note regarding engineering compliance cos t estimates: the approach to annualizing costs, the projection of affected units in the baseline; that estimate rental costs are used for REC s ; and additional natural gas and h ydrocarbon condensate s that would otherwise be emitted to the environment are re covered from several control options evaluated in the NSPS review.3 - 12

**Table 3**  **- 2**  **Summary of Projected No. of Affected Units Under Primary and Alternative**  **Regulatory Baselines and Capital and Annual**  **ized Costs**  **per Unit**  **for F**  **inal NSPS Em**  **issions Sources and**  **Point s** 

**Source/Emissions Point Projected No. of Affected**  **Units Annualized Cost (2008$)** 

**Prim ary**  **Baseline Alternative** 

**Regulatory Baseline**  **Capital**

**Costs (2008$)**  **Without**

**Rev. from Addl.**  **Product Recovery**  **With Rev.**

**from Addl.**  **Product Recovery**  **Hydraulically Fractured Natural Gas Well Co mpletions**  Hydraulically Fractured Gas Wells that Meet Criteria for REC 4,107 8,382 $0 $33,237
- $1,543 Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Completion Com bustion) 1,377 1,377 $0 $3,523 $3,523 **Hydraulically Refractured Natural Gas Well Completions** Hydraulically Ref

ractured Gas Wells that Meet Criteria for REC 532 1,085 $0 $33,237
- $1,543 Hydraulically Re f

ractured Gas Wells that Do Not Meet Criteria for REC (Completion Com bustion) 121 121 $ 0 $3,523 $3,523 **Equipment Leaks** Processing Plants 29 29 $8,041 $12,273 $8,474 **Reciprocating Com pressors**  Gathering and Boosting Stations 210 210 $5,346 $2,456 $870 Processing Plants 209 209 $4,050 $2,090
- $2,227 **Centrif u**  **gal Com pressors**  Processing Plants 13 13 $22,000 $3,132
- $46,974 **Pneumatic Controllers** Oil and Gas Production 13,632 13,632 $165 $23
- $1,519 Processing Plants 15 15 $16,972 $11,090 $7,606 **Storage Vessels** Emissions at least 6 tons per year 304 304 $65,243 $19,864 $19,281
3.2.2.1.1 Approach to Annualizing Engineering Compliance Costs Engineering capital costs were annualized using a 7 percent interest rate. However, different emissions control options were annualized using expected lifetimes that were3 - 13

determined to be most appropriate for individual options. For control options evalu ated 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)  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 establishing an overall, representative project time horizon and annualizing costs after consideration of control options that would need to be replaced peri odicall 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. 3.2.2.1.2 Projection of Affected Units The projected number of affected units is the number of units that our analysis 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 estimated emissions reductions and engineering compliance c osts, it is worthwhile to go into some detail on the projected number of REC s within the RIA. We use EIA projections consistent with the Annual Energy Outlook 2011 to estimate the number of natural gas well completions with hydraulic fracturing in 2015, assuming that successful wells drilled in coal bed methane, shale, and tight sands used hydraulic fracturing . In the National Energy

Modeling S ys tem (NEMS) used by the EIA to produce the Annual Energy3 - 14

Outlook identifies wells as being either a natural ga s well or oil well. No criteria, such as a gas
oil ratio, for example, are applied within the model to a well to determine whether it is a natural gas well or an oil well. Additionally , EIA uses historical information as data for the NEMS. To collect th ese data, EIA relies upon States to submit information. States submit information about natural gas wells and oil wells based upon state
- level approaches to classification, which varies greatl y across States. In most instances, no national
- level criteria are applied to reclassify the State - submitted information. To the extent that EPA’s definition of a natural gas well differs from the various definitions used by States, potential difference s in definition s may explain some difference between forecast impacts of the NSPS and the true costs incurred once the NSPS is implemented. To approximate the number of natural gas wells that would not be required to combust emissions rather than perform a REC because they are wildcat (exploratory) and delineation wel ls , we draw upon the distinction in the EIA ’s analy sis between exploratory and developmental wells. EIA defines an exploratory well as a “hole drilled a) to find and produce oil or gas in an area previously considered unproductive area; b) to find a new reservoir in a known field, i.e., one previously producing oil and gas from another reservoir, or c) to extend the limit of a known oil or gas reservoir.” According to EIA, a “development well is a well drilled within the proved area of an oil or gas reser voir to the depth of a stratigraphic horizon known to be productive.” 15 The definitions of exploratory and developmental wells do not take into account whether the wells primarily produce crude oil or natural gas. For the impacts anal ys is, w e assume explo ratory

wells as defined and estimated by EIA are equivalent to the NSPS
affected wildcat (exploratory) and delineation wells described in the NSPS as requiring to combust completion emissions rather than perform a REC. The number of h ydraulically fractur ed recompletions of existing wells was approximated using assumptions found in Subpart W’s TSD 16 and applied to well count data found in the proprietary HPDI ® database. The underl yi ng assumption is that wells found in coal bed

15 Source: 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. 16 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 - 15

methane, shale, and tight san d 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 absence of a Federal regulation was estimated based on e xisting S tate regulations that require applicable control measures for completions and workovers in specific geographic locations , as well as information reported to the EPA’s Natural Gas STAR program . Based on th e criterion relating to State regulations , 1 5 percent of natural gas completions w ith hydraulic fracturing and 1 5 percent of recompletions of existing natural gas workovers with hydraulic fracturing are estimated to be controlled by

either flare or REC in absence of Federal regulations. EPA does not have comprehensive information on th e number of h ydraulically fractured natural gas well completions that might be required b y state or local regulations to combust completion emissions, which upon promulgation of this rule will be required to perform a REC. Based on th e criterion relating to voluntary REC implementation, 51 percent of the c ompletions and recompletions outside of regulated States are assumed to have been performed using a REC . However, because the pressure level for some wells may be insufficient to successfull y perform a REC, these wells will be required to combust emissions, rather than implement a REC. EPA anal ys is shows about 10 percent of the wells that otherwise would be required by the NSPS to perform a REC will combust emissions.3 - 16

**Table 3**  **- 3**  **Estimated New Hydraulically Fractured and Refractured Natural Gas Well Completions Affected by NSPS, 2015**  Hydraulically Fractured Natural Gas Well Com pletions of New Wells Hydraulically

Refractured Natural Gas Well Com plet ions of Existing Wells Nationwide Hydraulically Fractured Natural Gas Well Completions 11,403 1 1,417 2 Com pletions Exempt from NSPS REC Requirement Wi ldcat (Exploration Wells) and Delineation 1 446 0 Low Pressure 3 931 121 RECs Performed Absent Federal Regulation REC A lready R equired by States 1,644 212 Voluntarily Performed RECs Outside of Regulated States 4 4,275 553 **Total RECs Incrementally Req uired**  **by NSPS 4,107**  **532 Total Com** **pletion Combustion Incrementally Req uired**  **by NSPS 1,377**  **121** Note: sums may not total because of independent rounding. 1 Annual Energy Outlook 2011 Reference Case (successful completions in tight sands, shale, coalbed methane formations in 2015) 2 U.S. Environmental Protection Agency (U.S. EPA). 2010. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Background Technical Support Document. Climate Change Division. Washington, DC. Also reflects revised assumptions regarding refracture frequency. 3 “NSPS Low Pressure Complet ion Threshold” in U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Support Document for the Final New Sou rce Performance Standards. EPA - 453/R
- 11 - 002. April 2012. 4 “Voluntary Reductions from Gas Well Completions with Hydraulic Fracturing” in U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Support Document for the Final Ne w Source Performance Standards. EPA
- 453/R
- 11 - 002. April 2012. Table 3
- 3 presents the accounting used for the estimate of the number of hy draulicall y fractured natural gas completions incrementally affected by

the NSPS, after accounting for State regulation and voluntary

action. In summary , we estimate 4,107 completions of new hydraulicall y fractured natural gas wells and 531 existing hydra ulically refractured natural gas wells will incrementally

be required to perform a REC in 2015. Additionally , we estimate 1,377 completions of new h ydraulically fractured natural gas wells and 121 existing h ydraulicall y3 - 17

refractured natural gas wells will be incrementall y required to combust emissions in 2015. The metho ds to derive these figures are detailed in a technical memo in the Docket. 17 It also should be noted that natural gas prices are stochastic and, historically, there have been periods where p rices 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 REC that capture emissions over short periods of time. 3.2.2.1.3 REC Unit Rental Costs The completion requirements (combustion and REC) are essentially one
- shot events and are generally

performed by

independent contractors. The emissions controls are applied over the course of a well completion, which will typicall y range over a few days to a couple of weeks. After this relativel y short period of time, there is no continuing control requirement, unless the well is again completed at a later date, sometimes years later, if at all. After the completion is con cluded, the REC equipment is ty picall y moved by contractors to be reused during other well completions. Given that we base our REC costs on the average cost for contracting the REC as a service, we expect contractors’ operation and maintenance costs, depreciations, and potential salvage value of the equipment to be reflected in the total contracting costs. Because of these factors, we decided to treat the hydraulicall y fractured natural gas well completion requirements solely as annualized costs. 3.2.2.1. 4 Revenues from Natural Gas Product Recovery For annualized cost, we present two figures, the annualized costs with revenues from additional natural gas and condensate recovery and annualized costs without additional revenues from 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

17 ”N ational Impacts of the NSPS OOOO Requirements on Gas Well Completions” in U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Support Document for the Final Ne w Source Performance Standards. EPA
- 453/R
- 11 - 002. April 2012.3 - 18

and sold. When including the additional natural gas recovery in the cost analy sis, 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 l ost to the environment. The engineering anal ys is assumes a REC will capture 34 barrels of condensate per REC and that the value of this condensate is $70/barrel. For the RIA, in the case of a REC, the revenues from captured and sold natural gas products are assumed to accrue in the same year as the REC is performed and onl y that year. For other environmental controls that avert the emission of saleable natural gas, such as pneumatic controllers, we base the estimated revenues from averted natural gas emis sions on an estimate of the amount of natural gas that would not be emitted during one year for the control. As natural gas prices can increase or decrease rapidly , the estimated engineering compliance costs can vary when revenue from additional natural g as recovery is included. There is also geographic variability in wellhead prices, which can also influence estimated engineering costs. A $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $43 million i n 2008 dollars. As will be seen in subsequent anal ys is, the estimate of revenues 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 insight into why , if it is profitable to capture natural gas emissions that are otherwise vented, producers may not already

be doing so. Table 3 - 4 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 evaluated in the NSPS analy sis. The annual reporting and recordkeeping costs for the final NSPS are estimated at $2.6 million per year and are included in Table 3 - 4 . As can be seen from Table 3 - 4 , which presents estimates, under the primary baseline, of nationwide compliance costs, emissions r eductions, and VOC reduction c ost - e ffectiveness from controls associated with well completion s and recompletions, hydraulically fractured natural gas wells provide the largest potential for emissions reductions from evaluated emissions sources and3 - 19

points. Controlling equipment leaks at processing plants presents the most significant compliance co sts if revenue from additional natural gas recovery is not included. Table 3
- 5 presents the same set of information under the alternative regulatory baseline. Several evaluated emissions sources and points are estimated to have net financi al savings when including the revenue from additional natural gas recovery . Table 3 - 6 presents the estimated engineering costs, emissions reductions, and VOC reduction cost
- effectiveness for the final NSPS under the primary baseline . The resulting total national annualized cost impact of the final NSPS rule is estimated at $170 million per year without considering revenues from additional natural gas recovery . Total national annual ized costs for the final NSPS are estimated at - $15 million when revenue from additional natural gas recovery is included. All figures are in 2008 dollars.3 - 20

**Table 3**  **- 4**  **Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction**  **Cost -**  **Effectiveness by NSPS**  **Em issions Sources and Points**  **, Primary Baseline,**  **2015**

**Source/Emissions Point 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 Hydraulically Fractured Natural Gas Well Co**  **mpletions** Hydraulically Fractured Gas Wells that Meet Criteria for REC $136,511,391
- $6,336,330 88,305 605,244 6,416 $1,546
- $72 Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Com pletion Combustion) $4,850,956 $4,850,956 29,606 202,918 2,151 $164 $164 **Hydraulically Refractured Natural Gas Well Completions**  Hydraulically Refractured Gas Wells that Meet Criteria for REC $17,682,220
- $820,740 11,438 78,397 831 $1,546
- $72 Hydraulically Refractured Gas Wells that Do Not Meet Criteria for REC (Com pletion Combustion) $426,264 $426,264 2,602 17,831 189 $164 $164 **Equipment Leaks** Processing Plants $355,917 $245,746 132 475 5 $2,693 $1,860 **Reciprocating Com pressors**  Gathering and Boosting Stations 515,764 182,597 400 1,437 15 $1,291 $457 Processing Plants 436,806 - 465,354 1,082 3,892 41 $404
- $430 **Centrifugal Com pressors**  Processing Plants $40,720
- $610,657 254 2,810 9 $161
- $2,408 **Pneumatic Controllers** Oil and Gas Production $320,071
- $20,699,918 25,210 90,685 952 $13
- $821 Processing Plants $166,351 $114,094 63 225 2 $2,659 $1,824 **Storage Vessels** Emissions at least 6 tons per year $6,031,787 $5,855,032 29,654 6,490 876 $203 $197 **Reporting and Recordkeeping** 2,576,065 2,576,065 N/A N/A N/A N/A N/A **TOTAL $169,914,312**  **- $14,682,245**  **188,744 1,010,405**  **11,487 $900**  **- $78** 3 - 21

**Table 3**  **- 5**  **Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction**  **Cost -**  **Effectiveness by NSPS**  **Em issions**  **Sources and Points , Alternative Regulatory Baseline, 2015** 

**Source/Emissions Point 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 Hydraulically Fractured Natural Gas Well Co**  **mpletions** Hydraulically Fractured Gas Wells that Meet Criteria for REC $278,594,675
- $12,931,285 180,214 1,235,192 13,093 $1,546
- $72 Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Com pletion Combustion) $4,850,956 $4,850,956 29,606 202,918 2,151 $164 $164 **Hydraulically Refractured Natural Gas Well Completions** Hydraulically Refractured Gas Wells that Meet Criteria for REC $36,062,422
- $1,673,878 $23,328 $159,888 $1,695 $1,546
- $72 Hydraulically Refractured Gas Wells that Do Not Meet Criteria for REC (Com pletion Combustion) $426,264 $426,264 $2,602 $17,831 $189 $164 $164 **Equipment Leaks** Processing Plants $355,917 $245,746 $132 $475 $5 $2,693 $1,860 **Reciprocating Com pressors**  Gathering and Boosting Stations $515,764 $182,597 $400 $1,437 $15 $1,291 $457 Processing Plants $436,806
- $465,354 $1,082 $3,892 $41 $404
- $430 **Centrifugal Com pressors**  Processing Plants $40,720
- $610,657 $254 $2,810 $9 $161
- $2,408 **Pneumatic Controllers** Oil and Gas Production $320,071
- $20,699,918 $25,210 $90,685 $952 $13
- $821 Processing Plants $166,351 $114,094 $63 $225 $2 $2,659 $1,824 **Storage Vessels** Emissions at least 6 tons per year $6,031,787 $5,855,032 $29,654 $6,490 $876 $203 $197 **Reporting and Recordkeeping** $2,576,065 $2,576,065 N/A N/A N/A N/A N/A **TOTAL $330,377,798**  **- $22,130,338**  **292,543 1,721,844**  **19,029 $1,129**  **- $76** 3 - 22

**Table 3**  **- 6**  **Engineering Compliance Costs, Em**  **ission Reductions, and Cost**   ** Effectiveness,** **Primary Baseline, NSPS (2008$)**  **Final NSPS** Capital Costs $ 24,803,968 Annualized Costs Without Revenues from Additional Natural Gas Product Recovery $ 169,914,312 With Revenues from Additional Natural Gas Product Recovery - $ 1 4,682,245 VOC Reductions (tons per year) 188,744 Methane Reduction (tons per year) 1, 010,405 HAP Reductions (tons per year) 1 1,487 VOC Reduction Cost
- Effectiveness ($/ton without additional product revenues) $ 900 VOC Reduction Cost
- Effectiveness ($/ton with additional product revenues) - $ 78 Note: T he 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 $ 43 mi llion in 2008 dollars. The annualized cost estimates also include reporting and recordkeeping costs of $ 2.6 million . As shown in Table 3
- 5, i f voluntary action is not subsumed into the NSPS baseline, the emissions reductions achieved b y the final NSPS are estimated at about 290,000 tons VOC , 19,000 tons HAP , and 1.7 million tons methane, and annualized costs without revenues from product recovery

are estimated at $330 m illion. In this scenario, given the assumptions about product prices, estimated revenues from product recovery are $350 million, yielding an estimated cost of savings of about $22 million
. As assumptions about natural gas prices, REC costs, and the potential emissions from hydraulicall y fractured natural gas well completions are influential on estimated impacts, we performed a pair of simple sensitivity anal ys es of the influence of these factors on the engineering costs estimate of the final NSPS. To perf orm this anal ys is, we vary the national average wellhead natural gas price from $2/Mcf to $7/Mcf while, first, varying REC costs and, second, varying the natural gas emissions that are captured by implementing a REC.3 - 23

To characterize variation in REC cost s, we use the data reported in the proposal TSD that were used to estimate the national average cost of performing a REC. On the low end of the range, we assume a REC costs $806 per day . This represents completion and recompletion costs where key

pieces of equipment, such as a deh ydrator or three phase separator, are already found on site and are of suitable design and capacity for use during flowback. On the upper end of the range, we use $7,486 per day , which represents the cost in situations where ke y pieces of equipment, such as a dehydrator or three
- phase separator, are temporaril y brought on site and then relocated after the completion. Li ke the primary anal ys is of the NSPS cost impacts, we use the average of these two values, $4,146 per day , to r epresent a mid
- range case. Also like the primary NSPS impacts analy sis, each REC also incurs include transportation and setup costs of $691 and completion combustion costs of $3,52 3 and assume an average flowback period of seven day s. In sum, the low, av erage, and high REC costs are estimated at $9,856, $33,237, and $56,616, respectivel y. For the mean estimate of the potential emissions from hydraulically fractured natural gas well completions, we use the 9,000 Mcf per completion which is used in the prim ary impacts anal ys is. To characterize the variation in potential natural gas emissions, we use the low and high ends of the 95 confidence interval around this mean estimate presented in a supporting technical memo. 18 The low
- end estimate of potential emis sions from hydraulically fractured natural gas well completions is estimated at 6,100 Mcf per completion and the high end at 11,700 Mcf per completion. It is important to note two caveats to the anal ys is. First, while the gas price is largely a national
- l evel parameter (producers will face similar wellhead prices across different regions), the REC costs and potential natural gas emissions may be highl y variable across the country . Extrapolating what may

be high or low end costs or potential natural gas em issions whose variation is driven b y local or regional factors to a national
- level estimate may overestimate or underestimate potential cost or emissions impacts. Second, this analy sis holds the number of hydraulicall y fractured natural gas well completio ns constant regardless of economic conditions.
18 “Statistical Analysis Memo: Development of a Bayesian Posterior Interval for the Emission Factor for Hydraulically Fractured Well Completions” in U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Annex to the Background Supplemental Technical Support Document for the Final New Source Performance Standards. EPA
45 3/R
- 11 - 002. April 2012.3 - 24

It is likel y that the decision to perform a REC without a regulatory requirement is conditioned on the producer having already decided to drill and hydraulicall y fracture a natural gas well. If economic and technical conditions are conducive to drilling and hydraulically fracturing a natural gas well, it is also possible that conditions are such that RECs are more likely to be profitable if performed. Conversel y, if gas prices were low, we would expect fewer completions, and hence fewer RECs. Consequently , the assumption of a fixed number of completions will tend to overstate total compliance cost estimates. Figure 3
- 1 plots the annualized costs after revenues from natural gas product recovery have been inco rporated (in millions of 2008 dollars) as a function of the assumed price of natural gas paid to producers at the wellhead for the recovered natural gas (represented by the s loped line s ), as well as a function of the low, average, or high REC costs assumed faced b y all producers nationally . The vertical solid lines in the figure represent the natural gas price assumed in the RIA ($4.00/Mcf) for 2015 and the 2015 forecast by EIA in the 2011 Annual Energy Outlook ($4.22/Mcf) in 2008 dollars.

**Figure 3**  **- 1**  **Sensitivity of Final NSPS Annualized Costs to Natural Gas Prices and REC Costs** 3 - 25

As also shown in Table 3
- 6, at $4/Mcf and average REC costs, the annualized costs are estimated at
- $ 15 million. At $4.22/Mc f, the price forecast reported in the 2011 Annual Energy Outlook, the annualized costs are estimated at about
- $24 million. As indicated b y this difference, EPA has chosen a relatively conservative assumption (leading to an estimate of lower savings and h igher net costs) for the engineering costs analy sis. The natural gas price at which the final NSPS breaks
- even is around $3.66/Mcf. As mentioned earlier, a $1/Mcf change in the wellhead natural gas price leads to about a $43 million change in the annuali zed engineering costs of the final NSPS. Consequently , annualized engineering costs estimates would increase to about $29 million under a $3/Mcf price or decrease to about
- $58 million under a $5/Mcf price. Meanwhile, varying the REC costs shifts the li ne representing annualized costs downward in the low REC cost scenario and upward in the high REC cost scenario. At the $4/Mcf assumed wellhead natural gas prices, the annualized costs in the low REC cost scenario would be about
- $120 million. At the $4/Mcf assumed wellhead natural gas prices, the annualized costs in the high REC cost scenario would be about $94 million. Figure 3
- 2 similarl y plots the annualized costs as function of the assumed price of natural gas paid to producers, but also depicts how the annualized costs might change when the potentials emissions might differ from our estimate of the national average well.3 - 26

**Figure 3**  **- 2**  **Sensitivity of Final NSPS Annualized Costs to Natural Gas Prices and Emissions Factor for Hydraulically Fractured Natural Gas Well Completions**  A s with the average REC costs, factor the annualized costs are estimated at
- $15 million when using the average emissions . V aryi ng the emissions factor shifts the line representing annualized costs up ward in the low emissions factor scenario and downward in the high emissions factor cost scenario. At the $4/Mcf assumed wellhead natural gas prices, the annualized costs in the low emissions factor scenario would be about $33 million. At the $4/Mcf assumed wellhead natural gas prices, the annualized costs in the high emissions factor cost scenario would be about

- $60 million. The models used to forecast natural gas prices in the Annual Energy Outlook, also the source of our $4/Mcf wellhead natural gas price assumption, are deterministic. A deterministic model does not incorporate stochastic influences and produces the same result for each mod el run using the same inputs and parameters. While the Annual Energy Outlook is a commonly referenced publication that provides longer term forecast s , the U.S. EIA also produces the Short
Term Energy

Outlook (STEO) which provides information about the pro bability distribution of energy prices over a shorter time frame. To better understand the uncertainty associated with the 2015 natural gas price assumed in this analy sis, EPA reviewed the March 2012 STEO (U.S. EIA,3 - 27

2012 ) , which includes monthly forecaste d natural gas prices through 2013. While the STEO anal ys is onl y extends to the end of 2013, the discussion of the distribution of possible future natural gas prices until that point can illuminate the uncertainty around longer
- term forecasts. In the STEO, forecasted prices are a function of the volatility associated with a future
delivery contract, as well as the length of time until contract expiration. The STEO also incorporates an anal ys is of the probabilities that natural gas prices would fall below o r exceed specified prices through 2013. We note, however, that the probability analy sis uses the Henry Hub spot price, rather than the wellhead price paid to producer. The Henry Hub price will reflect markups for processing and tran s portation unlike the wellhead price. 19 In December 2013, the EIA anal ys is projects a Henry Hub price of $4.28/million Btu (or $4.40/Mcf 20 ) with a 90 pe rcent confidence interval of $2.36 to $7.16/million Btu. Also, the STEO reports that based upon futures prices as of February 2 012, spot natural gas prices in December 2013 at the Henry Hub have a 40 percent probability of being greater than $4.00 per million Btu; a 30 percent probability of being greater than $4.50 per million Btu; a 20 percent probability of being greater than $ 5.00 per million Btu; and a 10 percent probability of being less than $2.50 per million Btu (U.S. EIA, 2012). While this information is not directly comparable to the wellhead natural gas price, the probability analy sis highlights the challenges associate d with precisel y predicting future natural gas prices. It is additionall 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 ultimately

consumed b y final consumers. Several controls require combustio n of the natural gas rather than capture and direction into product streams. After adjusting estimates of national emissions reductions in Table 3 - 4 f or these combustion
- ty

pe controls, the final NSPS is
19 The National Energy Modeling System used to produce the Annual Energy Outlook does not explicitly model prices at the Henry Hub. Rather, the model uses an econometric equation to predict Henry Hub prices from mo deled wellhead pr ices. For the forecasts presented in 2012 Annual Energy Outlook, this equation predicts the Henry Hub price to be about 13 percent higher than the wellhead price. 20 The 2015 natural gas price used in EPA’s analysis is in units of thousand cubic feet and the spot natural gas prices used in the probability analysis are in units of million Btu. The conversion factor we used to convert the Btu measure to the cubic foot measure is 1 Mcf equals 1.027 million Btu. While EPA is able to convert the mean estimate of future natural gas prices, we are not able to convert the distribution around the mean without additional information that was used in the probability analysis.3 - 28

estimated to capture about 43 b illion cubic feet (bcf) of natural gas and 160,000 barrels of condensate . Estimates of unit
- level and nation
- level product recovery are presented in Table 3
- 7 below . 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 38 bcf (or 87 percent).3 - 29

**Table 3**  **- 7**  **Estimate s of**  **Control Unit -**  **level and National -**  **l evel Natural Ga**  **s and Condensate Recovery,**  **Sources and Emissions Points ,**  **Primary Baseline, NSPS**  **, 2015 Projected No.**  **of Affected Units**  **Unit -**  **level Product Recovery Total Product Recovery**  **Source/ Emissions Points Natural Gas**  **Savings (M**  **cf/unit) Condensate** 

**(bbl/unit) Natural Gas** 

**Savings (Mcf) Condensate** 

**(bbl) Well Completions**  Hydraulically Fractured Gas Wells that Meet Criteria for REC 4,107 8,100 34 33,268,158 139,644 Hydraulically Refractured Gas Wells that Meet Criteria for REC 532 8,100 34 4,309,200 18,088 **Equipment Leaks** Processing Plants 29 950 0 27,548 0 **Reciprocating Com pressors**  Gathering and Boosting Stations 210 397 0 83,370 0 Processing Plants 209 1,079 0 225,540 0 **Centrifugal Com pressors**  Processing Plants 13 12,526 0 162,844 0 **Pneumatic Controllers** Oil and Gas Production 13,632 386 0 5,254,997 0 Processing Plants 15 871 0 13,064 0 **Storage Vessels** Emissions at least 6 tons per year 304 146 0 44,189 0 **Total (Mcf) 43,388,910**  **157,732** A second adjustment to the natural gas quantities is necessary to account for nonhydrocarbon gases removed and gas that is 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 mini mally

processed at the meter and still contains impurities or co
- products that must be processed out of the natural gas at processing plants. This means that the engineering cost estimates of revenues from additional natural gas recovery arising from controls implemented at the wellhead include 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). Using 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.3 - 30

After making these adjustments, we estimate that the final NSPS will potentially recover about 34 bcf of natural gas that will ultimately be consumed by

natural gas consumers. 21 EIA forecasts that the domestic dry natural gas production in 2015 will be 2 2.4 t cf. Consequentl y, the final NSPS may

recover production representing about 0.15 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 . Clearly , this discussion raises the question as to why , if emissions can be reduce d profitably using environmental controls, more producers are not adopting the controls in their own economic self

- interest. This question is made clear when examining simple estimates of the rate of return to installing emissions controls, using the engi neering compliance costs estimates, the estimates of natural gas product recovery , and assumed product prices ( Table 3 - 8 ). The rates of return presented in Table 3
- 8 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**  **- 8**  **Simple Rate of Return Estimate for Final NSPS Controls , Primary Baseline** 
**Emission Point Control**  **Option Cost of Control**  **Revenues from Product**  **Recovery Estimated** 

**Rate of Return**  New Completions of Hydraulically Fractured Wells REC / Combustion $33,237 $34,780 4.6% Reciprocating Compressors (Processing Plants) Replace p acking $2,090 $4,317 106.5% Centrifugal Compressors (Processing Plants) Route to c ontrol $3,132 $50,106 1499.7% Pneumatic Controllers (Oil and Gas Production ) Emission s limit $23 $1,542 6467.3% **Overall NSPS*** **$ 169,914,312**  ***** **$ 184,596,889**  ***** **8.6 %**  ***** * Costs and estimated rate of return for overall NSPS based on national costs of rule, not per unit costs like the other items in the table. Note: The table presents only control options where estimated revenues from natural gas product recovery exceeds estimated annualized engineering c osts
21 To convert U.S. short tons of methane to a cubic foot measure, we use the conversion fac tor of 48.04 Mcf per U.S. short ton.3 - 31

Recall from Table 2 - 23 in the Industry Profi le, that EIA estimates an industry
- level rate of return on investments for various segments of the oil and natural gas industry . While the numbers vary 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 a REC , it is significantly lower than the rate of returns estimated for other controls anticipated to have net savings. Assuming financially

rational producers, standard economic theory suggests that all oil and natural gas firms would incorporate all cost
- effective improvements, which they are aware of, without government intervention. The cost analy sis of this RIA nevertheless is based on the observation that emission reductions that appear to be profitable , on average, in our anal ys is have not been adopted by

a significant segment of the industry . This observation, often termed the “energy paradox”, has been noted to occur in other contexts too where consumers and firms appear to undervalue a wide range of investments in energy conservation , even when they pay off over relativel y short time periods. 22 We discuss some possible explanations for the apparent paradox in this context . First, there may be an opportunity cost associated with the installation of environmental controls (for purposes of mitigating the emission of pollutants) that is not reflected in the control costs. In the event that the environmental investment displa ces other investment in productive capital, the difference between the rate of return on the marginal investment displaced b y the mandatory environmental investment is a measure of the opportunity cost of the environmental requirement to the regulated enti ty . However, if firms are not capital constrained, then there may not be any

displacement of investment, and the rate of return on other investments in the industry would not be relevant as a measure of opportunity cost. If firms should face higher borro wing costs as they take on more debt, there may be an additional opportunity

cost to the firm. To the extent that any opportunit y costs are not added to the control costs, the compliance costs presented above may be underestimated. A second explanation could be that the average impacts identified in this RIA are not reflective of the true costs and benefits of the RECs that are compelled b y the regulation, relative

22 See U.S. EPA (2011) for more discussion and a review of the economics literature examining why firms may not adopt technologies that would be expected to increase their profits. ( U.S. EPA. 2011. Final Rulemaking to Establish Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium
- and Heavy
- Duty Engines and Vehicles. Regulatory Impact Analysis. http://www.epa.gov/otaq/climate/documents/420r11901.pdf ) .3 - 32

to the RECs performed voluntarily . In this final rule, based on public comments and expl ained above, EPA has identified several circumstances under which RECs would not be feasible or cost - effective, and has allowed firms to continue to use combustion devices only for those completions and recompletions. In addition to these general categories, the natural variation in well
- head prices, cost, or other technical issues may mean that the rational decision to not complete using a REC in the absence of this regulation in certain circumstances may not be captured b y the anal ys is of central estimate impacts contained in this RIA. In part to address this issue, EPA has provided the break
- even analysis above, as well as a sensitivity analy sis where we vary

several parameters that may influence individual REC decision
- making. Third , the assumed $4/Mcf pay ment rate does not reflect any taxes or ro yalties that might apply to producers implementing the control technologies. We expect that royalties and taxes influence producers’ economic and operational decisions, particularl y at the margin, as these royalties or taxes reduce potential net returns and prevent adoption of environmental controls. However, there are various reductions in taxable income and incentives that can serve to reduce costs which also can affect decisionmaking. For example, firms may be able to deduct pollution control expenditures and depreciation from income taxes. Also, for the oil and natural gas industry , producers may

be eligible for deductions of intangible drilling costs and other state or federal production and investment credits. Historically , EPA has not estimated post
- tax (or post
royalty) compliance costs (which are typicall y cost - reducing) in compliance cost estimation as this requires information and tax accounting beyond the scope of the anal yses. A third explanation for why there appear to be negative cost control technologies 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 t o capturing emissions. Quantifying emissions is difficult and has been done in relatively few studies. Recently , however, advances in infrared imagery have made it possible to affordably visualize, if not quantify , methane emissions from any source using a handheld camera. This infrared camera has increased awareness within industry and among environmental groups and the public at large about the large number of emissions sources and possible scale of emissions from oil and natural gas production activit ies. Since a significant percent of new natural gas well completions with hydraulic fracturing and existing natural gas well recompletions with hydraulic fracturing are3 - 33

estimated to be controlled in the baseline, it is unlikely that a lack of information will be a major 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. Finally , the cost from the irreversibility associated with implementing these environm ental 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 emi ssions capture technology . If a firm has not adopted the technology on its own, then a regulation mandating its use means the firm loses the option to postpone investment in the technology in order to pursue alternative investments today , and the option t o suspend use of the technology if it becomes unprofitable in the future. Therefore, the full cost of the regulation to the firm is the engineering cost and the lost option value minus the revenues from the sale of the additional recovered product. In th e absence of quantitative estimates of this option value for each emission point affected b y the NSPS and NESHAP improvements, the costs presented in this RIA may underestimate the full costs faced b y the affected firms. With these caveats in mind, EPA b elieves it is analy tically appropriate to anal yz e engineering compliance costs presented in Table 3 - 2 and Table 3 - 4 using the additional product recovery and associated revenues. EPA continues to explore what factors could explain apparent underinvestment in cost
- effective emission reducing technolo gi es absent government regulation, and the measurement of opportunity costs more generall y. 3.2.2.2 NESHAP Sources As discussed in Section 3.2.1.2 , EPA examined two 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 - 9 shows the projected number of controls required, estimated unit
- level capital and annualized costs, and3 - 34

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 - 35

**Table 3**  **- 9**  **Summary of Estimated**  **Capital and Annual Co sts, Emissions Reductions,**  **and HAP Reduction Cost -**  **Effectiveness for Final**  **NESHAP Amendments**

**Source/Emission s Point**  **Projecte**

**d No. of**  **Controls Required**  **Em ission Reductions (tons per**  **year) Capital**  **Costs/ Unit (2008$)**  **Ann ual**  ****

**ized Cost/Unit**  **(2008$) Total** 

**Annualized Cost**  **(2008$) HAP**  **VOC Methane**  **HAP Reduction**  **Cost**   ** Effectivenes** **s (2008$/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 Reporting and Recordkeeping N/A N/A N/A 1,694,907 N/A N/A N/A N/A **Total 81**  **3,484,907 669**  **1,213 419**  **5,209** Note: Totals may not sum due to independent rounding . Under the final NESHAP Amendments , about 81 controls will be required, costing a total of $3.5 million annually ( Table 3 - 9 ). 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 670 tons, VOC emissions by about 1,200 tons, and methane by about 420 tons. The cost
- per - ton to reduce HAP emissions is estimated at about $5,200 per ton. All figures are in 2008 dollars. **3.3 References**  Oil and Gas Journal . “Natural Gas Pipelines Continue Growth Despite Lower Earnings; Oil Profits Grow.” November 1, 2010. Oil and Gas Journal . “OGJ150.” September 21, 2009. Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. Oil and Gas Journal . “Special Report : Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010. U.S. Energy

Information Administration (U.S. EIA) . 2012. Short
- Term Energy Outlook March 2012. < http://205.254.135.7/forecasts/steo/uncertainty /index.cfm> March 6, 2012.4 - 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 that there are no health benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available , as explained below . 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, 190,000 tons of VOC , 11,000 tons of HAP, and 1.0 million tons of methane from new sources, while the final NESHAP Amendments are anticipated to reduce 670 tons of HAP , 1,200 tons of VOC , and 420 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 ), 550 tons of nitrogen oxides (NOx), 19 tons of PM, 3,000 tons of CO, and 1,100 tons of total hydrocarbons (THC). The specific control techno logies for the NESHAP Amendments are anticipated to have minor secondary disbenefits, but EPA was unable to estimate these secondary disbenefits. Both rules would have additional emission changes associated with the energy sy stem impacts. The net CO 2 - equ ivalent emission reductions are 18 million metric tons for the final NSPS and 8,000 metric tons for the final NESHAP. As described in the subsequent sections, these pollutants are associated with substantial health effects, welfare effects, and climate ef fects. With the data available, we are not able to provide a credible benefits estimates for an y of these pollutants for these rules, due to the differences in the locations of oil and natural gas emission points relative to existing information, and the highl y localized nature of air quality4 - 2

responses associated with HAP and VOC reductions. 23 In addition, we do not yet have interagency

agreed 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. In stead, we provide a qualitative assessment of the benefits and co
- benefits as well as a break
- even anal ys is in Section 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. The se emission points 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 below the National Ambient Air Quality Standards (NAAQS) in some areas and assist other areas with attaining the NAAQS. Due to the high degree of variability in the responsiveness of ozone and PM 2.5 formation to VOC emission reductions, we are unable to determine how these rules might affect attainment status without air quality modeling data. 24

23 Previous studies have estimated the monetized benefits
- per - ton of reducing VOC emissions associated with the 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). While these ranges of benefit
- per - ton estimates provide useful context for the break
- even analysis, the geographic distribution of VOC emissions from the oil and gas sector are not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition, the ben efit
- per - ton estimates for VOC emission reductions in that study are derived from total VOC emissions across all sectors. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 and the highly localized nature of air qu ality responses associated with VOC reductions, these factors lead us to conclude that the available VOC benefit
- per - ton estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding exercise. 24 The responsiveness of ozon e and PM 2.5 formation is discussed in greater detail in sections 4.4.1 and 4.5.1 of this RIA.4 - 3

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 States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of othe r 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 reduc tions for implementation rules are generally from a specific class of well
- characterized sources. In general, EPA is more confident in the magnitude and location of the emission reductions for implementation rules rather than illustrative NAAQS anal ys es. Emission reductions achieved under these and other promulgated rules will ultimately be reflected in the baseline of future NAAQS analy ses, which would reduce the incremental costs and benefits associated with attaining the NAAQS. EPA remains forward loo king 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 for 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 anticipated for these rules. Itis important to note that these benefits accrue at different spatial scales. HAP emission reductions reduce exposure to carcinogens and other toxic pollutants primarily near the emissi on 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 primaril y at a global scale, but methane is also a precursor to ozone, a short
- lived climate forcer that exhibits spatial and temporal variability .4 - 4

**Table 4**  **- 1**  **Direct Em**  **ission Reductions Associated with the Oil and Natura l Gas NSPS**  **and NESHAP Amendments**  **in 2015 ( short**  **tons per year)**

Pollutant NESHAP Amendments NSPS Primary Baseline HAP 669 11,487 VOC 1,213 188,741 Methane 419 1,010,382

Alternative Regulatory

Baseline HAP 669 19,028 VOC 1,213 292,532 Methane 419 1,721,763
**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. 25 For example, b y combusting VOC and HAP, combustion increases emissions of carbon monoxide, NOx, particulate matter and other pollutants. In addition to “producer
- side” impacts, these control techniques would also allow additional natural gas recovery , which would contribute to additional combustion of the recovered natural gas and ultimately

a shift in the national fuel mix. We refer to the seco ndary 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 .

25 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” imp acts. Relative to the direct emission reductions anticipated from these rules, the magnitude of these secondary air pollutant impacts is small. Because the geographic distribution of these emissions from the oil and gas sector is not consistent with emis sions 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 increased 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 pot ential compared to methane (IPCC, 2007). 26 **Table 4**  **- 2**  **Secondary Air Pollutant Impacts Associated with Control Techniques by Emissions Category**  **, Primary Baseline**  **(“Producer -**  **Side”) ( short**  **tons per year) Emissions Category**  **CO 2**  **NOx PM**  **CO THC**  Total Completions of New Gas Wells (NSPS) 981,559 504 15 2,745 1,039 New Gas Well Completions: REC/Combust 133,177 68 0 372 141 New Gas Well Completions: Combust 848,382 436 15 2,373 898 Existing Well Recompletions: Combust 91,800 47 1 257 97 Existing Well Completions: REC/Combust 17,251 9 0 48 18 Existing Well Completions: Combust 74,549 38 1 208 79 Pneumatic Controllers (NSPS) 22.0 1.0 2.6 0.0 0.0 Storage Vessels (NSPS) 856.0 0.5 0.0 2.4 0.9 **Total NSPS 1,074,237**  **553 19**  **3,004 1,137**  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 ) . 27 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. 65 million metric tons for the final NSPS and NESHAP Amendments in 2015. This is in addition to the other secondary impacts and directl y avoided emissions, for a total 17.7 million metric tons of CO 2 - equivalent emissions averted as shown in Table 4 - 4 . While the NEMS is designed to estimate changes in fuel consumption as economic and regulatory factors change (such as are shown in Table 7
- 11), the NEMS is unable to estimate national
- level emissions of criteria pollutants.

26 This issue is discussed in more detail in Section 4.7 of this RIA. 27 A full discussion of the energy modeling is available in Section 7 of this RIA.4 - 7

**Table 4**  **- 3**  **Modeled Changes in Energy**  **- related**  **CO 2**  **- equivalent**  **Emissions by Fuel Type for the**  **Final Oil and Gas NSPS**  **and NESHAP Amendments in 2015**  **(million metric ton ne**  **s) (**  **"Consumer -**  **Side") 1**  Fuel T ype NSPS (million metric tons change in CO 2 - e) Petroleum
- 0. 07 Natural Gas 0.04 Coal 0.68 Other 0.00 **Total m odeled Change in CO**  **2 -**  **e Em issions**  **0.65** 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 and NESHAP Amendments**  **in 2015 (million metric ton**  **ne s)**  **Emissions Source NSPS**  **NESHAP Am**  **endments** Averted CO 2 - e Emissions from New Sources 1

- 19.2 - 0.008 Additional CO 2 - e Emissions from Com bustion and Supplemental Energy (Producer
- side) 2 0.97 N/A Total Modeled Change in Energy
- related CO 2 - e Emissions (Consumer
side) 3 0.65 N/A **Total Change in CO 2**  **- e Emissions after Adjustment for Secondary**  **Impacts -**  **17.6 -**  **0.008** 1 This estimate reflects the GWP of the avoided methane emissions from new sources shown in Table 4
- 1 and has been converted from short tons to metric tons. 2 This estimate represents the secondary producer
- side impacts associated with additional CO 2 emissions from combustion and from additional electricity requirements shown in Table 4
- 2 and has been converted from short tons to metric tons. 3 Th is estimate reflects the modeled change in the energy

–related consumer
- side impacts shown in Table 4
- 3 and r eflects both NSPS and NESHAP Amendments. 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 damage, 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**  **Amendments in 2015 (short tons per year)**  **Pollutant NSPS**  **NESHAP Am**  **endments Change in Direct Emissions**  VOC - 190,000 - 670 Methane
- 1,000,000 - 1,200 HAP - 11,000 - 420
**Change in Secondary Emissions (Producer**  **- Side)**  CO 2 1,100,000 N/A NOx 550 N/A PM 19 N/A CO 3,000 N/A THC 1,100 N/A **Change in Secondary Emissions (Consumer**   ** Side)** CO 2 - e 720,000 N/A **Net Change in CO 2**  **- equivalent Emissions**  CO 2 - e (short tons) - 19,000,000 - 8,800 CO 2 - e (metric tonnes) - 18,000,000 - 8,000 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). 28 The levels of air toxi cs 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. EP A conducts the NATA. 29 The most recent NATA was conducted for calendar ye ar 2005 and was released in March 2011. NATA includes four steps:
28 The 2005 NATA is available on the Internet at http://www.epa.gov/ttn/atw/nata2005/. 29 The NATA modeling frame work has a number of limitations that prevent its use as the sole basis for setting regulatory standards. These limitations and uncertainties are discussed on the 2005 NATA website. Even so, this modeling framework is very useful in identifying air toxic pollutants and sources of greatest concern, setting regulatory priorities, and informing the decision making process. U.S. EPA. (2011) 2005 National
- Scale Air Toxics Assessment. http://www.epa.gov/ttn/atw/nata2005/4 - 9

1) Compiling a national emissions inventory of air toxics emissions from outdoor sources 2) Estimating ambient and exposure concentrations of air toxics across the United States 3) Estimating population exposures across the United States 4) Characterizing potential public health risk due to inhalation of air toxics including both cancer and noncancer effects Based on the 2005 NATA, EPA estimates that about 5 percent of census tracts nationwide have increased cancer risks greater than 100 in a million. The average national cancer risk is about 50 in a million. Nationwide, the key pollutants that contribute most to the overall cancer risks are formaldeh yde and benzene. 30 , 31 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 ef

fects can result from chronic, 32 subchronic, 33 or acute 34 inhalation exposures to air toxics, and include neurological, cardiovascular, liver, kidney, and respiratory effects as well as effects on the immune and reproductive sy stems. According to the 2005 NA TA, 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 fo r noncancer respiratory

risk.

30 Details on EPA’s approach to characterization of cancer risks and uncertainties associated with the 2005 NATA risk estimates can be found at http://www.epa.gov/ttn/atw/nata1999/riskbg.html#Z2 . 31 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 qualitative (e.g., quality of data, review of emission inventories) judgments can be found at http://www.epa.gov/ttn/atw/nata/roy/page16.html. 32 Chronic exposure is defined in the glossary of the Integrated Risk Information System (IRIS) database (http://www.epa.gov/iris) as repeated exposure by the oral, dermal, or inhalation route for more than approximately 10% of the life span in humans (more than approximatel y 90 days to 2 years in typically used laboratory animal species). 33 Defined in the IRIS database as r epeated exposure by the oral, dermal, or inhalation route for more than 30 days, up to approximately 10% of the life span in humans (more than 30 days up to approximately 90 days in typically used laboratory animal species) . 34 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.4 - 10

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

hazard from the assessment. It is important to note that l arge reductions in HAP emissions may

not necessarily

tr anslate 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 more 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 acetaldeh yd e, suggesting that acrolein could be potentially more toxic than acetaldeh yde. 35 Thus, it is important to account for the toxicity and exposure, as well as the mass of the targeted emissions.

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

**Figure 4**  **- 2**  **Estimated Chronic Census Tract Carcinogenic Risk from HAP exposure**  **from outdoor sources (2005 NATA)**4 - 12

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

and data limitations, we were unable to estimate the benefits associated with the hazardous air pollutants that would be reduced as a result of these rules . In a few previous anal ys es of the benefits of reductions in HAP , EPA has quantified the benefits of potentia l 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. 36 These URFs are designed to be conservative, a nd as such, are more likely to represent the high end of the distribution of risk rather than a best or most likely estimate of risk. As the purpose of a benefit analy sis is to describe the benefits most likely to occur from a reduction in pollution, use o f high
- end, conservative risk estimates would overestimate the

36 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 - 13

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 bene fit 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 implementation 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, unc ertainties in emissions inventories and background levels, the difficulty of extrapolating risk estimates to low doses and the challenges of tracking health progress for diseases, such as cancer, that have long latency periods” (U.S. EPA
- SAB, 2008 ). In 2009, EPA convened a workshop to address the inherent complexities, limitations, and uncertainties in current methods to quantify the benefits of reducing HAP . Recommendations from this workshop included identifying research priorit ies, 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 be nefits 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 to be reduced by these rules and we summarize the results of the residual risk assessment for the Risk and Te chnology Review (RTR). EPA remains committed to improving methods for estimating HAP benefits by continuing to explore additional concepts of benefits, including changes in the distribution of risk. Available emissions data show that several different HAP are emitted from oil and natural gas operations, either from equipment leaks, processing, compressing, transmission and distribution, or storage tanks. Emissions of eight HAP make up a large percentage of the total4 - 14

HAP emissions by

mass from the oil and gas sector: toluene, hexane, benzene, x yl enes (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 o il 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 t ons 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 e xisting 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 could be 2 0 - in
- a - million with a cancer incidence of 0.001. Approximately 1,100 people are estimated to have cancer risks at or above 1
- in
- 1 million for oil and gas transmission and storage. Benzene is the primary cancer risk driver. The results also indicate that significant noncancer impacts from existing sources are unlikel y, especially after controls. It is important to note that the magnitude of the HAP emissions avoided by new sources with the NSPS are much higher than the HAP emissions reduced from existing sources with the NESHAP. **4.4.1 Benzene**  The EPA’s IRIS database lists benzene as a known human carcinogen (causing leukemia) by all routes of exposure, and concludes that exposure is assoc iated with additional health effects, including genetic changes in both humans and animals and increased proliferation of bone marrow cells in mice. 37 , 38 , 39 EPA states in its IRIS database that data indicate a causal

37 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. 38 International Agency for Research on Cancer, IARC monographs on the evaluation of carcinogenic risk of ch emicals to humans, Volume 29, Some industrial chemicals and dyestuffs, International Agency for Research on Cancer, World Health Organization, Lyon, France, p. 345
- 389, 1982. 39 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, V.A. (1992) Synergisti c action of the benzene metabolite hydroquinone on myelopoietic stimulating activity of granulocyte/macrophage colony
- stimulating factor in vitro, Proc. Natl. Acad. Sci. 89:3691
- 3695.4 - 15

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 Research on Carcinogens (IARC) has determined that benzene is a human carci nogen and the U.S. Department of Health and Human Services (DHHS) has characterized benzene as a known human carcinogen. 40 , 41 A number of adverse noncancer health effects including blood disorders, such as preleukemia and aplastic anemia, have also been ass ociated with long
- term exposure to benzene. 42 , 43 The most sensitive noncancer effect observed in humans, based on current data, is the depression of the absolute ly mphocy te count in blood. 44 , 45 Inaddition, recent work, including studies sponsored by the H ealth Effects Institute (HEI), provides evidence that biochemical responses are occurring at lower levels of benzene exposure than previously known. 46 , 47 , 48 , 49 EPA’s IRI S program has not ye t evaluated these new data.

40 International Agency for Research on Cancer (IARC). 1987. Monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 29, Supplement 7, Some industrial chemicals and dyestuffs, World Health Organization, Lyon, France. 41 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens available at: http://ntp.niehs.nih.gov/go/16183. 42 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193
- 197. 43 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541
- 554. 44 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. 45 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene (Noncancer Effects). Research and Development, National Center for Environmental Assessm ent, Washington, DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm. 46 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. 47 Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohen, e t al. (2002). Hematological changes among Chinese workers with a broad range of benzene exposures. Am. J. Industr. Med. 42: 275
- 285. 48 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels of Benzene. Science 306: 1774
- 1776. 49 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 - 16

**4.4.2 Toluene**  **50** 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 r ats 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 target for toluene toxicity in both humans and animals for acute and chron ic 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 nervou s sy stem depression has been reported to occur in chronic abusers exposed to high levels of toluene. Sy mptoms include ataxia, tremors, cerebral atroph y, ny stagmus (involuntary

eye movements), and impaired speech, hearing, and vision. Chronic inhalation e xposure of humans to toluene also causes irritation of the upper respiratory tract, eye irritation, dizziness, headaches, and difficulty with sleep. Human studies have also reported developmental effects, such as CNS dy sfunction, attention deficits, and mi nor 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 occupationall y exposed humans exists. The weight of evidence from these s tudies 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 Carbon** 

**yl 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 effects and irritate

50 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 - 17

the eyes and skin in humans. 51 No information is availab le on the chronic (long
- term), reproductive, developmental, or carcinogenic effects of carbonylsulfide in humans. Carbonyl sulfide has not undergone a complete evaluation and determination under U.S. EPA's IRIS program for evidence of human carcinogenic potential. 52 **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 also a constituent of crude petroleum and is found in gasoline and diesel fu els. 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 neurological effects such as dizziness. Chronic (long
- term) exposure of humans to ethylbenzene may cause eye and lung irritation, with possible adverse effects on the blood. Animal studies have reported effects on the blood, liver, and kidneys and endocrine sy stem from chronic inhalation exposure to ethylbenzene. No information is ava ilable 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. 53 , 54 The reports of these studies lacked detailed information on the incidence of specific tumors, statistical analy sis, survival data, and i nformation on historical controls, thus the results of these studies were considered inconclusive by the International Agency for Research on Cancer (IARC, 2000) and the National Toxicology

Program (NTP). 55 , 56 The NTP (1999) carried out a chronic inhalation

51 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. 52 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. 53 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. 54 Maltoni C, Ciliberti A, Pinto C, Soffritti M, Belpoggi F and Menarini L, 1997. Results of long
- term expe rimental carcinogenicity studies of the effects of gasoline, correlated fuels, and major gasoline aromatics on rats. Annals NY Acad Sci 837:15
- 52. 55 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 - 18

bioassay in mice and rats and found clear evidence of carcinogenic activity in male rats and some evidence in female rats, based on increased incidences of renal tubule adenoma or carcinoma in male rats and renal tubule adenoma in females. NTP (1999) also noted increases in the incidence of testicular adenoma in male rats. Increased incidences of lung alveolar/bronchiolar adenoma or carcinoma were observed in male mice and liver hepatocellular adenoma or carcinoma in female mice, which provided some eviden ce of carcinogenic activity in male and female mice (NTP, 1999). IARC (2000) classified ethylbenzene as Group 2B, possibly carcinogenic to humans, based on the NTP studies. **4.4.5 Mixed xylenes**  Short
- term inhalation of mixed xylenes (a mixture of three closely
- r elated compounds) in humans may

cause irritation of the nose and throat, nausea, vomiting, gastric irritation, mild transient eye irritation, and neurological effects. 57 Other reported effects include labored breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and kidney s. 58 Lo ng - term inhalation exposure to xylenes in humans has been associated with a number of effects in the nervous s ys tem including headaches, dizziness, fatigue, tremors, and impaired motor coordination. 59 EPA has classified mixed xylenes in Category D, not classifiable with respect to human carcinogenicity. **4.4.6 n**  **- Hexane**  The studies available in both humans and animals indicate that the nervous system is the primary target of toxicity

upon exposure of n - hexane via inhalation. There are no data in humans and very limited information in animals about the potential effects of n
- hexane via the oral route. Acute (short
- term) inhalation exposure of humans to high levels of hexane causes mild central

56 National Toxicology Program (NTP), 1999. Toxicology and Carcinogenesis Studies of Ethylbenzene (CAS No. 100 - 41 - 4) in F344/N Rats and in B6C3F1 Mice (Inhalation Studies). Technical Report Series No. 466. NIH Publication No. 99
- 3956. U.S. Department of Health and Human Services, Public Health Service, National Institutes of Health. NTP, Research Triangle Park, NC. 57 U.S. Environmental Protection Agency (U.S. EPA). 2003. Integrat ed 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. 58 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. 59 Agency for Toxic Substances and Disease Registry (ATSDR), 2007 . T he Toxicological Profile for xylene is available electronically at http://www.atsdr.cdc.gov/ToxProfiles/TP.asp?id=296&tid=53.4 - 19

nervous system effects, including dizziness, giddiness, slight nausea, and headache. Chronic (long
- term) exposure to hexane in air causes numbness in the extremities, muscular weakness, blurred vision, headache, and fatigue. Inhalation studies in rodents have re ported 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 . 60 **4.4.7 Other Air Toxics**  In addition to the compounds described above, other toxic compounds might be affected by these rules, including hydrogen sulfide (H 2 S). Information regarding the health effects of those compounds can be found in EPA’s IRI S database. 61 **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 it is unlikely

this sector has a large contribution to

60 U.S. EPA. 2005. Guidelines for Carcinogen Risk Assessment. EPA/630/P
- 03/001B. Risk Assessment Forum, Washington, DC. March. Available on the Internet at <http://www.epa.gov/ttn/atw/cancer_guidelines_final_3
- 25 - 05.pdf>. 61 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris4 - 20

ambie nt secondary

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

. Due to time limitations under the court
- ordered schedule 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 reductions, we are unable to es timate 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 toxicological, clinical and epid emiological 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 premature mortality for adults and infants, cardiovascular morbidity such as heart attacks, hospital admissions, and respiratory morbidity such as asthma attacks, acute and chronic bronchitis, hospital and ER visits, work loss 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, other cardiovascular effect s, and other respiratory effects (U.S. EPA, 2009a). EPA assumes that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differenti ation 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 - 21

Previous studies have estimated the monetized benefits
- per - ton of reducing VOC emissions associated with the effect that those emissions have on ambient PM 2.5 levels and the health effects associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009). Using the estimates in Fann, Fulcher, and Hubbell (2009), the monetized benefit
- per - ton of reducing VOC emissions in nin e 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 anal ys is 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 estim ate. 62 After these adjustments, the range of values increases to $680 to $7,000 per ton of VOC reduced for Laden et al. (2006). Using alternate assumptions regarding the relationship between PM 2.5 exposure and premature mortality from empirical studies an d 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 derived from expert opinions in Roman et al. (2008) as a characterization of uncertainty . In addition to the range of benefits based on epidemiology studies, this study

also provided a range of benefits associated with reducing emissions in eight specific urban areas. The range of VOC benefits that reflects the adjustments as well as the range of epidemiology

studies and the range of the urban areas is $280 to $7,000 per ton of VOC reduced. While these ranges of benefit
- per - ton estimates provide useful context for the break
- even 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 reductions in that study are derived from total VOC

62 For more information regarding EPA’s current VSL estimate, ple ase 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 - 22

emissions across all sectors. Coupled with the larger uncertainties about the relationship 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 - 23

**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 Ro man et al. (2008) as a characterization of uncertainty.4 - 24

**4.5.3 Organic PM welfare effects**  According to the residual risk assessment for this sector (U.S. EPA, 2011a), persistent and bioaccumulative HAP reported as emissions from oil and gas operations include polycyclic organic matter (POM). POM defines a broad class of compounds that includes the polycyclic aromatic h ydrocarbon compounds (PAHs). Several significant ecological effects are associated with deposition of organic particles, inc luding 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 properti es 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 t o 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 sur faces 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 demo nstrated 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 effec ts 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 - 25

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, 199 6). 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 determi ne 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 - 26

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 the se 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 ). 63 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

63 While EPA has estimated the ozone benefits for many scenarios, most of the se scenarios also reduce NOx emissions, which make it difficult to isolate the benefits attributable to VOC reductions.4 - 27

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 - 28

**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 that contributes to increased global warming and continuing climate change. Methane reacts in the atmosphere 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, m elting 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 Rep ort (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 a fter CO 2 . However, after accounting for changes in other greenhouse substances such as ozone and stratospheric water vapor due to chemical reactions of methane in the atmosphere , historical methane emissions were estimated to have contributed to 0.86 W/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 Apri l 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 - 29

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 1.0 million short tons or approximately

19 million metric tons CO 2 - e. The se reductions represent about 7 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 18 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 4 million typ ical passenger cars off the road or eliminating electricity use from about 2 million ty

pical homes each ye ar. 64 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
64 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 - 30

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. 65 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.

65 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 - s pecific estimates of SCC in the literature. See Interagency Working Group on Social Cost of Carbon. 2010. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866.4 - 31

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 reductions 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 approxi mates 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, su ch 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 confounding issue given that the social cost of GHGs is based on a discounted stream of damages that are non
- linear in temperature. For example, methane has an expected adjusted atmospheric lifetime of about 12 years and associated GWP of 21 (IPCC Second Assessment Report (SAR) 100 - year GWP estimate). Gases w ith 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 GWP treats additional forcing the same independent of when it occurs in time. Furthermore, the baseline temperature change is lower in the near term and therefore the additional warming from relativel y short lived gases will have a lower marginal impact relative to longer lived gases that have an impact fur ther 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 othe r 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 - 32

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 social cost of methane . In the absence of direct model estimates from the interagency analy sis, EPA has used a “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 mul tiplied 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 bro adl 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 public comments sent in response to this request, is provided in the response to comments document. Ap plying 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 . 66 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 $1 0 0 millio n to about $ 1 . 3 billion; the mean SCC at the 3 percent discount rate ($25 per metric ton) results in an estimate of $ 44 0 m illion in 2015 (Table 4
- 7) .

66 The per ton estimates range from approximately $110 to $1400 per short ton of methane reduced, depending on the discount rate assumed, with an estimate of $480 per short ton of methane, using the mean SCC at 3% discount rate.4 - 33

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

**SCC Value for 2015 em ission**  **reductions ($/ton**

**CO 2**  **in 2008 dollars) 1**  **Total Benefits based on 100 year GWP adjustment 2**  **(m illions 2008$)**  **Final NSPS Final**  **NESHAP Am**  **endments** $6 (mean 5% discount rate) $100 $0.05 $25 (mean 3% discount rate) $44 0 $0.20 $40 (mean 2.5% discount rate) $7 00 $0.32 $76 (95 th percentile at 3% discount rate) $1,300 $0.60 **Me thane Emission Reductions**  **3 (MMT CO**  **2 -**  **e) 17.**  **6 0.008**  1 SCC values for 2015 from the SCC TSD in the light duty vehicle rule adjusted to reflect 2008$ 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 mul tiplied 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 m ethane directly computed from integrated assessment mo dels. See Marten and Ne wbold (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. Note: Results reflect independent rounding. 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 short er atmospheric lifetime of m ethane relative 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 benef its 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 reductions in most cases (Marten and Newbold, 2011). This conclusion is reached using the 100 year GWP for methane of 25 as put forth in the IPCC Fourth Assessment Report as opposed to the lower value of 21 used in this ana ly 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 est imate the methane climate4 - 34

co - benefits for this oil and gas rule . The use of the SAR GWP values allows comparability of 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 2002 but continue to require the use of GWPs from the SAR. The parties to the UNFCCC have also agreed to use GWPs based upon a 100
- ye ar time horizon although other time horizon values are available. The SAR GWP va lue for methane is also currently used to establish 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 fro m those agreed upon by 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’ climate co
- benefit estimates as an interim method to produce estimates until the interagency group develops values for non
- CO 2 GHGs.4 - 35

**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, ther efore, can reduce global background ozone concentrations, human exposure to ozone, and the incidence of ozone
- related health effects (West et al., 2006, Anenberg et al., 2009) . These benefits are global and occur in both urban and rural areas. Reduction s 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 sho rter 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; Shi ndell et al., 2005, 2012; UNEP/WMO, 2011). VOC The health, welfare, and climate effects associated with ozone are described in the preceding sections. Without air quality modeling, we are unable to estimate the effect that reducing methane will have on ozo ne concentrations at particular locations. **4.7.3 Combined m**  **ethane and ozone effects**  A recent United 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 first half of this century . Relative to a business as usual reference scenario,4 - 36

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

averaged warming in 2050 (including the impacts of both methane itself and 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 $5 , 000 per metric ton 67
. The methane measures examined include extended methane recovery /utilization and reduced fugitive emissions from oil and g as 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 e xpected value approach. ” Energy Journal 15 (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:10.1029/200 7J D009162

67 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 di fferent assumptions for the value of a statistical life. Similarly, these values cannot be compared to, nor are they additive with, the methane climate valuation estimates in Section 4.7. 1 since they include health and agricultural benefits and use differ ent assumptions for the Social Cost of Carbon.4 - 37

Forster, P. et al. 2007 . Changes in Atmospheric Constituents an d in Radiative Forcing. In: Climate Change 2007. The Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change [Solomon, S., D. Qin, M. Manning, Z. Chen, M. Marquis, K.B. Averyt, M. Tignor and H.L . Miller (eds.)]. Cambridge Universit y 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(658 0):301

– 303, 1996. Hope, C . 2005. “ The climate change benefits of reducing methane emissions. ” Climatic Change 68(1):21

– 39. Hope , C. and D. Newbery . 2006. “Calculating the Social Cost of Carbon” Forthcoming in Delivering a Low Carbon Electricity S ys tem: Technologies, Economics and Policy Editors: Michael Grubb, Tooraj Jamasb and Michael G. Pollitt (University of Cambridge) Cambridge Universi ty

Press. Available on the Internet at <http://www.dspace.cam.ac.uk/handle/1810/194738 > Accessed March 30, 2011. Industrial Economics, Inc (IEc). 2009. Section 812 Prospective Study of the Ben efits and Costs of the Clean Air Act: Air Toxics Case Study

— Health Benefits of Benzene Reductions in Houston, 1990

–2020. Final Report , July 14, 2009. <http://www.epa.gov/air/sect812/dec09/812CAAA_Benzene_Houston_Final_Report_Jul y_2009.pdf>. Accessed March 30, 2011. Interagency

Working Group on Social Cost of Carbon (IWGSC). 2010. T echnical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. Docket ID EPA - HQ - OAR - 2009 - 0472 - 114577. Participation by Council of E conomic Advisers, Council on Environmental Quality , Department of Agriculture, Department of Commerce, Department of Energy , Department of Transportation, Environmental Protection Agency , National Economic Council, Office of Energy and Climate Change, Offi ce 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: Synthe sis Report. Contribution of Working Groups I, II 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 - 38

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Division. Corvallis, Oregon. Marten, A. and S. Newbold. 2011. “Estimating the Social Cost of Non
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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). Chapter 4, pp. 148
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—RTP Division. <http://cfpub.epa.gov/nce a/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. Off ice 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: Petrol eum and Natural Gas S ys tems; Final Rule . Federal Register Vol. 75, No. 229 , November 30, 2010 . 74458 - 74515. r< <http://edocket.access.gpo.gov/2010/pdf/2010
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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 o f Air Quality

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— Science Advisory

Board (U.S. EPA
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— Science Advisory

Board (U.S. EPA
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–2020 . EPA - COUNCIL - 08 - 001. July . <http://yosemite.epa.gov/sab/sabproduct.nsf/D4D7EC9DAEDA8A548525748600728A8 3/$File/EPA - COUNCIL - 08 - 001 - unsigned.pdf>. Accessed March 30, 2011. West et al. 2006. “Global health benefits of mitigating ozone pollution with methane emission controls.” PNAS 103:11:3988 - 3993. West, J.J., A.M. Fiore . 2005 . “ Management of tropospheric ozone by r educing 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 Planning and Review and Executive Order 13563, Improving Regulation and Regulatory Review**  Under section 3(f)(1) Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an “economically

significant regulatory

a ction” 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 response to OMB recommendations have been documented in the docket for this action. Table 5 - 1 shows the results of the cost and benefit s 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 1**  **NSPS NESHAP Amendments**  **NSPS and NESHAP**  **Am endments**  **Combined** Total Monetized Benefits 2 N/A N/A N/A Total Costs 3

- $1 5 million $3.5 million
- $1 1 million Net Benefits N/A N/A N/A Non - monetized Benefits 6 1 1 ,000 tons of HAP 670 tons of HAP 12 ,000 tons of HAP 1 90 ,000 tons of VOC 1,200 tons of VOC 19 0 ,000 tons of VOC 1. 0 million tons of methane 420 tons of methane 1 .0 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 product 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. 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, PM 2.5 and ozone exposure, visibility and vegetation effects and climate e ffects are co
- benefits. 6 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 ), 550 tons of nitrogen oxides NOx, 19 tons of PM, 3,000 tons of CO, and 1,100 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system im pacts. The specific control technologies for the NESHAP are anticipated to have minor secondary disbenefits but EPA was unable to es timate these secondary disbenefits. The net CO 2 - equivalent emission reductions are 18 million metric tons. **5.2 Paperwork Reduction Act**  The information collection requirements in this rule have been submitted for approval to the Office of Management and Budge t (OMB) under the Paperwork Reduction Act , 44 U.S.C.5 - 3

3501, et seq . The information collection requirements are not enforceable until OMB approves them. The I CR d ocuments prepared by the EPA have been assigned EPA ICR numbers 2437.01, 2438.01, 2439.01 and 2440.01. The information requirements are based on notification, recordkeeping and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specificall y authorized b y CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. This final rule requires maintenance inspections of the control devices but would not require any notifications or reports beyo nd those required b y the General Provisions. The recordkeeping requirements require onl y the specific information needed to determine compliance. When a malfunction occurs, sources must report them according to the applicable reporting requirements of 40 CFR part 63, subpart HH or 40 CFR part 63, subpart HHH. An affirmative defense to civil penalties for exceedances of emission limits that are caused b y malfunctions is available to a source if it can demonstrate that certain criteria and requirements are s atisfied. The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 63.2 (sudden, infrequent, not reasonable preventable, and not caused by poor maintenance and or careless operation) and where the source took necessary actions to minimize emissions. In addition, the source must meet certain notification and reporting requirements. For example, the source must prepare a written root cause anal ys is and submit a written report to the Administrator documenting that it has met the conditions and requirements for assertion of the affirmative defense. For this rule, the EPA is adding affirmative defense to the estimate of burden in the I CR . To provide the public with an estimate of the relative magnitude of the burden associated with an assertion of the affirmative defense position adopted by a source, the EPA has provided administrative adjustments to this I CR that shows what the notificat ion, recordkeeping and reporting requirements associated with the assertion of the affirmative defense might entail. The EPA’s estimate for the required notification, reports, and records, including the root cause5 - 4

anal ys is, associated with a single incident totals approximately totals $3,141 and is based on the time and effort required of a source to review relevant data, interview plant employees, and document the events surrounding a malfunction that has caused an exceedance of an emission limit. The esti mate also includes time to produce and retain the record and reports for submission to the EPA. The EPA provides this illustrative estimate of this burden, because these costs are only incurred if there has been a violation, and a source chooses to take advantage of the affirmative defense. The EPA provides this illustrative estimate of this burden because these costs are onl y incurred if there has been a violation and a source chooses to take advantage of the affirmative defense. Given the variety of circ umstances under which malfunctions could occur, as well as differences among sources’ operation and maintenance practices, we cannot reliably predict the severity and frequency of malfunction
- related excess emissions events for a particular source. It is i mportant to note that the EPA has no basis currently for estimating the number of malfunctions that would qualify for an affirmative defense. Current historical records would be an inappropriate basis, as source owners or operators previously operated thei r facilities in recognition that they

were exempt from the requirement to comply with emissions standards during malfunctions. Of the number of excess emissions events reported b y source operators, only a small number would be expected to result from a mal function (based on the definition above), and only

a subset of excess emissions caused by malfunctions would result in the source choosing to assert the affirmative defense. Thus, we believe the number of instances in which source operators might be expect ed to avail themselves of the affirmative defense will be extremely small. For this reason, we estimate a total of 39 such occurrences for all sources subject to 40 CFR part 63, subpart HH, a total of three such occurrences for all sources subject to 40 C FR part 63, subpart HHH, and a total of 6 such occurrences for all sources subject to 40 CFR part 60, subparts KKK and LLL over the 3
- ye ar period covered b y this ICR. We expect to gather information on such events in the future, and will revise this estimate as better information becomes available. The annual monitoring, reporting, and recordkeeping burden for this collection (averaged over the first 3 ye ars after the effective date of the standards) is estimated to be $20.1 million. This includes 384,866 labor hours per ye ar at a total labor cost of $19.5 million per year, and5 - 5

annualized capital costs of $0.36 million, and annual operating and maintenance costs of $0.20 million. This estimate includes initial and annual performance tests, semiannual excess emission reports, developing a monitoring plan, notifications, and recordkeeping. All burden estimates are in 2008 dollars and represent the most cost effective monitoring approach for affected facilities. Burden is defined at 5 CFR 1320.3(b). 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 the EPA's regulations in 40 CFR are listed in 40 CFR part 9. When these ICR 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 Flexibility 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 agency cert ifies 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 as defined b y NAICS codes 211111, 211112, 221210, 486110 and 486210; 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 enter

prise which is independentl y owned and operated and is not dominant 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. The baseline used in this analy sis takes into account RECs conducted pursuant to state regulations covering these operations and estimates of RECs performed voluntarily . To account for RECs performed in regulated states, EPA subsumed emissions reductions and complianc e costs in states where these5 - 6

completion
- related emissions are already controlled into the baseline. Additionally , based on public comments and reports to EPA's Natural Gas STAR program, EPA recognizes that some producers conduct well completions using RE C techniques voluntarily for economic and/or environmental objectives as a normal part of business. To account for emissions reductions and costs arising from voluntary implementation of pollution controls EPA used information on total emission reductions reported to the EPA by partners of the EPA Natural Gas STAR. This estimate of this voluntary REC activity in the absence of regulation is also included in the baseline. More detailed discussion on the derivation of the baseline is presented in a technical memorand

um in the docket . When revenue from additional natural gas product recovered is not included, we estimate that 123 of the 127 small firms anal yz ed (97 percent) are likel y to have impacts less than 1 percent in terms of the ratio of annualized compliance costs to revenues. Meanwhile, four firms (3 percent) are likel y to have impacts greater than 1 percent. Three of these four firms are likel y to have impacts greater than 3 percent. However, when revenue from additional natural gas product recove ry

is included, we estimate that none of the analyzed firms will have an impact greater than 1 percent. For the final NESHAP Amendments, we estimate that 11 of the 35 firms (31 percent) that own potentially

affected facilities are small entities. The EPA performed an anal ys is for impacts on all expected affected small entities by comparing compliance costs to entity revenues. Among the small firms, none are likely to have impacts greater than 1 percent in terms of the ratio of annualized compliance costs t o revenues. After considering the economic impact of the combined NSPS and NESHAP amendments on small entities, Icertify 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, 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 analy zed for the NSPS. When revenues from additional natural gas product sales are not included, 132 of the 136 small firms (97 percent) in the sample are likel y to have impacts of less than 1 percent in terms o f the ratio of annualized compliance costs to revenues. Meanwhile, four firms (3 percent) are likely to have impacts greater than 1 percent. Three of5 - 7

these four firms are likely to have impacts greater than 3 percent. When revenues from additional natural gas product sales are included, none of the 136 small firms (100 percent) are likel y to have impacts of greater than 1 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 co sts to be significantly mitigated. This conclusion is enhanced because the returns to REC activities occur without a significant time lag between implementing the control and obtaining the recovered product, unlike many control options where the emissions reductions accumulate over long periods of time; the reduced emission completions occur over a short span of time, during which the additional product recovery is also accomplished and pay ments for recovered products are settled. Although this final rule will not impact a substantial number of small entities, the EPA, nonetheless, has tried to reduce the impact of this rule on small entities by setting the final emissions limits at the MACT floor, the least stringent level allowed b y law. **5.4 Unfunded Mandates**  **Reform Act** This final action does not contain a federal mandate under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531
- 1538 for state, local, and tribal governments, in the aggregate, or to the private sector. The action would not result in expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, or to the private sector in any 1 year. Thus, this final rule is not subject to the requirements of sections 202 or 205 of UMRA. This final rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory

requirements that might significantly or uniquel y affect small governments because it contains no requirements that apply to such governments n or does it impose obligations upon them.5 - 8

**5.5 Executive Order 13132: Federalism**  This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. These final rules primarily affect private industry , and do not impose significant economic costs on state or local government s. Thus, Executive Order 13132 does not apply

to this action. **5.6 Executive Order 13175: Consultation and Coordination with Indian Tribal**  **Governments** Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) the EPA may not issue a regulation th at has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by tribal governments, or the EPA cons ults with tribal officials early

in the process of developing the proposed regulation and develops a tribal summary

impact statement. The EPA has concluded that this action will not have tribal implications because it doesn’t impose a significant cost to the tribal government. However, there are significant tribal interests because of the growth of the oil and gas production industry in Indian country . The EPA initiated a consultation process with tribal officials earl y in the process of developing this r egulation to permit them to have meaningful and timely input into its development. During the consultation process, the EPA conducted outreach and information meetings prior to the proposal in 2010. The EPA met with the Inter Tribal Environmental Council, which include many of the Region VI tribes, The Tribal leadership summit in Region X, and Tribal Energy

Conference hosted by

Ft. Belknap, and the National Tribal Forum. After the proposal was published, letters were sent to all tribal leaders offering to consult on a government - to - government basis on the rule. As part of the consultation process and in response to these letters, an outreach call was held on October 12, 2011. Tribes that participated on this call were: Fond du L ac Band of Lake Superior Chippewa, Fort Belknap Indian5 - 9

Community , Forest County Potawatomi Community , Southern Ute Indian Tribe, and Pueblo of Santa Clara. In this meeting the tribes were presented the information in the proposal. The tribes 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 In dian 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 Environm**  **ental Health Risks and Safety Risks**  This action is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because the Agency

does not believe the environmental health risks or safety risks addressed by this action present a disproportionate ris k to children. This action would not relax the control measures on existing regulated sources. The EPA’s risk assessments (included in the docket for this final rule) demonstrate that the existing regulations are associated with an acceptable level of risk and provide an ample margin of safety to protect public health . **5.8 Executive Order 13211: Actions Concerning Regulations That Significantly Affect**  **Energy Supply, Distribution, or Use** This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May

22, 2001), because it is not likely to have a significant adverse effect on the supply , distribution, or use of energy . These 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 , distribution, or use of energy . As s uch, 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, or5 - 10

use of energy . As s uch, the final NSPS is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001). The basis for these determinations is as follows. Emission controls for the NSPS capture VOC emissions that otherwise would be vente d to the atmosphere. Since methane is co
- emitted with VOC, a large proportion of the averted methane emissions can be directed into natural gas production streams and sold. One pollution control requirement of the final NSPS also captures saleable condensates. The revenues from additional natural gas and condensate recovery are expected to offset the costs of implementing the final rules. We use the National Energy Modeling S ys tem (NEMS) to estimate the impacts of the combined final rules on the United States energy sy stem. The NEMS is a publically available model of the United States energy econom y developed and maintained b y the Energy In formation Administration of the DOE and is used to produce the Annual Energy Outlook, a reference publication that prov ides detailed forecasts of the United States energy econom y. Based on public comments and reports to EPA's Natural Gas STAR program, EPA recognizes that some producers conduct well completions using REC techniques, which are required b y the final NSPS fo r certain completions of hydraulicall y fractured and refractured natural gas wells, voluntarily based upon economic and environmental objectives. The baseline used for the energy

s ys tem impacts analy sis takes into account RECs conducted pursuant to state r egulations covering these operations and estimates of RECs performed voluntarily . To account for RECs performed in regulated states, EPA subsumed emissions reductions and compliance costs in states where these completion
- related emissions are already controlled into the baseline. Additionally , based on public comments and reports to EPA's Natural Gas STAR program, EPA recognizes that some producers conduct well completions using REC techniques voluntarily for economic and/or environmental objectives as a normal part of business. To account for emissions reductions and costs arising from voluntary implementation of pollution controls EPA used information on total emission reductions reported to the EPA by partners of the EPA Natural Gas STAR. This estimate of this voluntary REC activity

in the absence of regulation is also included in the baseline. More detailed discussion on the derivation of the baseline is presented in a technical memorandum in the docket . The anal ys is of energy

sy stem impacts for the final NSPS under the primary baseline shows that domestic natural gas production is not likely to change in 2015, the year used in the5 - 11

RIA to anal yz e impacts. Average natural gas prices are also not estimated to change in response to the final rules. Dom estic 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 dollar s. The NEMS - based analy sis estimates in the year of analy sis, 2015, that net imports of natural gas and crude oil will not change. Additionally , the NSPS establishes several performance standards that give regulated entities flexibility

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

and economically

heterogeneous, this flexibility is an important factor in reducing regulatory

burden. For more information on the estimat ed energy effects of this final rule, ple ase see Section 7 of this RIA. **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 NT TAA directs the EPA to provide Congress, through OMB, explanations when the EPA decides not to use available and applicable VCS. This final action does not involve technical standards. Therefore, the EPA is not considering the use of any VCS. **5.10 Executive**  **Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low**  **- Income Populations**  Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice. Its main provision direc ts Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or5 - 12

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

high and adverse human health or environmental effects on any population, including an y minority, low
- in come, 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 populat ion 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 the EPA rulemakings is an evolving scien ce. The EPA conducted a demographic anal ys is, focusing on populations within 50 km of any facilit y 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 in dices 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 Productio n 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 w ith an acceptable level of risk and that the proposed additional requirements will provide an ample margin of safety to protect public health. Our anal ys es also show that, for these source categories, there is no potential for an adverse environmental effe ct or human health multi
- pathway

effects, and that acute and chronic non
- cancer health impacts are unlikel y. The EPA has determined that, although there may be an existing disparity

in HAP risks from these sources between some demographic groups, no demographic group is exposed to an unacceptable level of risk. To promote meaningful involvement, the EPA conducted three public hearings on the proposal. The hearings were held in Pittsburgh, Pennsylvania, on September 27, 2011, Denver,5 - 13

Colorado, on September 28, 2011, and Arlington, Texas, 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
- based and environmental organizations, industry representatives, associations representing industry and local and state government officials. **5.11 Congressional Review Act**  T he Congressional Review Act, 5 U.S.C. 801, et seq ., as added b y the Small Business Regulatory

Enforcement Fairness Act of 1996, generall y 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 Comptroller General of the United States. The EPA will submit a report containing this final rule and other required information to the United States Senate, the United States House of Representatives, and the Comptroller General of the United S tates 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 a “major rule” as defined b y 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 annualized engineering cost of the final NSPS in the analy sis year of 2015 when the additional natural gas and condensate recovery is included in the anal ys is is estimated at
- $ 1 5 million . EPA anticipates that this rule would prevent 1 90,000 tons of VOC, 1. 0 million tons of methane, and 1 1 ,000 t ons of HAP in 2015 from new sources. In 2015, EPA estimates the annualized costs for the NESHAP Amendments to be 3.5 million. 68 EPA anticipates that this rule would reduce 1,200 tons of VOC , 420 tons of methane, and 670 tons of HAP in 2015 from existing sources. For the NESHAP Amendments, a break
- even anal ys is suggests that HAP emissions would need to be valued at $5,200 per ton for the benefits to exceed the costs if the health benefits, and ecosystem and climate co
- benefits from the reductions in VOC and methane emissions are assumed to be zero. If we assume the health benefits from HAP emission reductions are zero, the VOC emissions would need to be valued at $2,900 per ton or the methane emissions would need to be valued at $8, 300 per ton for the benefits to exceed the costs. All estimates are in 2008 dollars. For the final NSPS, the revenue from additional natural gas recovery already exceeds the costs, which renders a break
- even analy sis unnecessary . However, as discussed i n 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 als o 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

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

gas would need to be at least $3. 66 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 about $ 150 pe r ton for the benefits to exceed the costs. All estimates are in 2008 dollars.

**Figure 6**  **- 1**  **Illustrative Break -**  **Even Diagram for Alternate Natural Gas Prices for the NSPS**  With the data available, we are not able to provide a credible benefit
- per - ton estimate for any of the pollutant reductions for these rules to compare to the break
- even estimates . Based on the methodology

from Fann, Fulcher, and Hubbell (2009), average PM 2.5 health
- related benefits of VOC e missions are valued at $280 to $7,000 per ton across a range of eight urban areas. 69 In addition, ozone benefits have been previousl y valued at $240 to $1,000 per ton of VOC reduced.

69 See Section 4.5 of this RIA for more information regarding PM 2.5 benefits and Section 4.6 for more information r egarding ozone benefits.

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

**VOC Cos**  **t -**  **ef fe**  **ctiv en**  **ess ($**  **/ton r** **ed uc** **tio n)** 

EIA Fore ca st Pri ce in 2 015 ($ 4.22/ Mcf) RIA Assume d Pric e in 2015 ($ 4.00/ Mc f ) Cost Ef fect ivene ss as Functi on of Natural Gas Pri ce As sum ptio n

NaturalG as Pri ce ($ /Mcf) in 2 015 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.006 - 3

Using the GWP approach, the climate co
- benefits range from approximately $110 to $1,400 per short ton of methane reduced depending upon the discount rate assumed with a per ton estimate of $760 at the 3 percent discount rate. These break
- even benefit
- per - ton estimates assume that all other pollutants have zero value. Of cours e, 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 con sidered. 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 need to be summed in order to develop a comprehensive estimate of the monetize d 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 be nefits 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 wou ld 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 Am endments , respectively. The NSPS analy sis assumes that RECs performed voluntarily

or in States where these emissions are already regulated would continue in absence of Federal regulation. Table 6 - 3 provides a summary of the direct and secondary emissions changes for each rule .6 - 4

**Table 6**  **- 1**  **Summary of**  **the Monetized Benefits, Costs, and Net Benefits for the**  **Fi nal**  **Oil and Natural Gas NSPS in 2015**  **1 Final**  **4** Total Monetized Benefits 2 N/A Total Costs 3 - $1 5 million Net Benefits N/A Non - monetized Benefits 1 1 ,000 tons of HAP 5 1 90,000 tons of VOC 1. 0 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 partic ulate 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 1.1 million tons of carbon dioxide (CO 2 ), 550 tons of nitrogen oxides (N O x ) , 19 tons of PM, 3,000 tons of CO, and 1,100 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 18 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 th e**  **Fi nal**  **Oil and Natural Gas**  **NESHAP Amendments in 2015**  **1 Final**  Total Monetized Benefits 2 N/A Total Costs 3 $3.5 Net Benefits N/A Non - monetized Benefits 5 670 tons of HAP 1,200 tons of VOC 4 420 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. 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. 5 The specifi c control technologies for the NESHAP are anticipated to have minor secondary disbenefits, but EPA wa s unable to estimate these secondary disbenefits . The net CO 2 - equivalent emission reductions are 8,000 metric tons.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 - 190,000 - 670 Methane
- 1,000,000 - 1,200 HAP - 11,000 - 420
**Change in Secondary Emissions (Producer -**  **Side) 1**  CO 2 1,100,000 N/A NOx 550 N/A PM 19 N/A CO 3,000 N/A THC 1,100 N/A **Change in Secondary Emissions (Consumer -**  **Side)** CO 2 - e 720,000 N/A **Net Change in CO 2**  **- equivalent Emissions**  CO 2 - e (short tons) - 19,000,000 - 8,800 CO 2 - e (metric tons) - 18,000,000 - 8,0007 - 1

**7 ECONOMIC IMPACT ANAL**  **YSIS AND DISTRIBUTIO NAL ASSESSMENTS** 
**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 and NESHAP Amendments**  We use the National Energy Modeling S ys tem (NEMS) to estimate the impacts of the final NS PS and NESHAP Amendments 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 evalu ate whether and to what extent the increased production costs imposed by the final rules might alter the mix of fuels consumed at a national level. With this information we estimate how the changed fuel mix affects national level CO 2 - equivalent greenhouse gas emissions from energy

sources. We additionall y combine these estimates of changes in CO 2 - equivalent greenhouse gas emissions from energy sources and emissions co
- reductions of methane from the engineering anal ys is with the 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 Section 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 effic iency gain at the producer level. For example, the analy sis for the final rules shows that about 9 2 percent of the natural gas captured b y emissions controls suggested b y the rule is captured b y performing REC on new and existing wells that are completed after being7 - 2

hydraulicall 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 wellhead, and producers are paid based upon this meter ed production. Depending on the situation, the gas captured by REC 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 slightl y more for less). However, because of differing ob jectives 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 analy sis, it is necessary to estimate the expected costs and revenues from implementing emissions controls at the unit level. Because of this, we estimate the net costs as expected costs minus expected revenues for representative units. On the other hand, NEMS models the profit maximizing behavior of represent ative 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. Consequently , project development adjusts to a new equ ilibrium. 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

economic 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 Energy 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 (DOE) . NEMS is used to produce the Annual Energy

Outlook, a reference publication that provides detailed forecasts of the energy7 - 3

econ om y from the current year to 2035. DOE first developed NEMS in the 1980s, and the model has undergone frequent updates and expansion since. DOE uses the modeling s ys tem extensively

to produce issue reports, legislative analy ses, and respond to Congressio nal 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 accompan yi 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

namics 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 electricity generation, and the quantity and prices fo r 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, demography, and macroeconomic conditions. An overview of the model and complete documentation of NEMS can be found at <http://www.eia.doe.gov/oiaf/aeo/overview/index.html >.7 - 4

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

solves multiple models, linear and non
- linear, using nonlinear Gauss
- Seidel methods (Gabriel et al. 200 1) . What this means is that NEMS solves a single module, holding all else constant at provisional solutions, then moves to the next model after establishing an updated provisional solution. NEMS provides what EIA refers to as “mid
- term” projections to the year 2035. However, as this RIA is concerned with estimating regulatory impacts in the first year of full implementation, our 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. 70 The RIA baseline is consistent with that of the Annual Energy Outlook 2011 which is used extensively in Section 2 in the Industry Profile.

70 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 S**  **ystem** To model potential impacts associated with the final rules, 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). The treatment of oil and gas resources is detai led 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 co sts , 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 structure of the OGSM is amenable to anal yz ing pot ential impacts of the final rules . We are able to target additional expenditures for environmental controls required by the NSPS and NESHAP Amendments on new exploratory and developmental oil and gas production activities, as well as add additional costs to existing projects. We model the impacts of additional environmental costs, as well as the impacts of additional product recovery . We explicitly model the additional natural gas recovered when implementing the final rules . 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 drilling projects. While the o il pro duction simulated by the OGSM is sent to the refining module ( the Petroleum Market Module) , simulated natural gas production is sent to a transmission and distribution network captured in the NGTDM. The NGTDM balances gas supplies and prices and “negotiat es” supply

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

7.2.2.1 Compliance Costs for Oil and Gas Exploration and Production As the NSPS affects new emissions sources, we chose to estimate impacts on new exploration and development projects 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 reco mpletions on existing wells are added to stimulation 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 engin eering costs including revenues from additional product recovery . This approach is appropriate given the structure of the NEMS algorithm that estimates the net present value of drilling projects. One concern in basing the regulatory costs inputs into NEM S 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, pote ntial barriers to obtaining additional capital should be reflected in the annualized cost via these barriers increasing the cost of capital. With this in mind, assuming the estimates of capital costs and product recovery are valid, the NEMS results will r eflect barriers to obtaining the re quired capital. A caveat to this is that the estimated unit
- level capital costs of controls that are newl y required at a national
- level as a result of the regulation

—REC , for example

—

may not incorporate potential additio nal 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 appl y 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 calc ulations. We then divide the estimated compliance costs for the given emissions point (from Table 3 - 4 ) b y the appropriate number of expected new well s in the year of anal ys is. The result yields an approximation of per well compliance costs. We assume this approximation is representative of the incremental cost faced b y a producer when evaluating a prospective drilling project. Like the engineering an aly sis, 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 the NSPS are re completed using hydraulic fracturing in any given ye ar using h ydraulic fracturing. Meanwhile, within NEMS, wells are assumed to be stimu lated every five years. We assume these more frequent stimulations are less intensive than stimulation using hydraulic fracturing but add costs such that the recompletions costs reflect the same assumptions as the engineering anal ys is. In entering compli ance costs into NEMS, we also account for reduced emissions completions, completion combustion, and recompletions performed in absence of the regulation, using the same assumptions as the engineering costs 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 So**  **urces/Points Emissions**  **Control Per Well Costs** 

**(2008$) Wells Applied To in NEMS**  **Equipment Leaks** Processing Plants (NSPS) Subpart VVa $ 14 Natural Gas **Reciprocating Com pressors**  Gathering and Boosting Stns. (NSPS) AMM $1 0 Natural Gas Processing Plants (NSPS) AMM - $ 2 7 Natural Gas **Centrifugal Com pressors**  Processing Plants (NSPS) Route to c ontrol
- $ 3 5 Natural Gas **Pneumatic Controllers -**  Oil and Gas Production (NSPS) Emission limits $11/
- $69 8 Oil/Natural Gas Processing Plants (NSPS) Emission limits 7.0 Natural Gas **Storage Vessels** Emissions at least 6 tons per year (NSPS) Emission limits $203/ $1 97 Oil/Natural Gas **Sm all Glycol Dehydrators**  Production and Transmission Segments (NESHAP) Emission limits $ 60/$60 Oil/Natural Gas **Reporting and Recordkeeping** NSPS and NESHAP N/A $ 87/$60 Oil/Natural Gas **Table 7**  **- 2**  **Summa ry of Additional**  **Per Completion/Recompletion Costs (2008$**  **) 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 New Natural Gas Wells REC /Com bustion
- $ 271 New Tight Sand/ Shale Gas/CBM **Well Recompletions**  Hydraulically Ref ractured Existing Natural Gas Wells REC /Com bustion
- $604 Existing Tight Sand/ Shale Gas /Coalbed Methane
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 decremented7 - 9

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 e enter the increased natural gas recovery into NEMS on a per
- well basis for new wells, following an estimation procedure similar to that of entering compliance costs into NEMS on a per - well basis for new wells. For the final NSPS , we estimate that natural gas recovery is 2,473 Mcf per well. We make a simplifying assumption that natural gas recovery accruing to new wells accrues to new wells in shale gas, tight sands, and CBM fields. We make these assumptions because new wells in these fields are m ore likel y to satisfy criteria such that RECs are required, which contributed that large majority of potential natural gas recovery. Note that th is per - well natural gas recovery estimate is lower than the per
- well estimate when RECs are implemented. The estimate is lower because we account for emissions that are combusted, REC that are implemented absent Federal regulation, as well as the likelihood that natural gas is used during processing and transmission or reinjected. We treat the potential natural gas recovery associated with recompletions of existing wells differently

in that we estimated the natural gas recovery by natural gas resource type based on a combination of the engineering anal ys is and production patterns from the 2011 Annual Energy Outlo ok. We estimate that additional natural gas product recovered by recompleting existing wells to be about 3.4 bcf, with 1.6 bcf accruing to shale gas, 1.4 bcf accruing to tight sands, and 0.4 bcf accruing to CBM, respectively . This quantity is distributed within the NGTDM to reflect regional production by resource t ype.7 - 10

7.2.2.3 Fixing Canadian Drilling Costs to Baseline Path Domestic drilling costs serve as a prox y 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 importe d 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. **7.2.3 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 final NSPS and NESHAP Amendments might alter the mix of fuels consumed at a national level. In each of these estimate s, we present estimates for the baseline year of 2015 and predicted re sults for 2015 under the final rules . For context, we provide estimates of production activities in 2011. 7.2.3.1 Impacts on Drilling Activities Because the potential costs of the final rules 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 pr esents estimates of successful wells drilled in the U.S. in 2015, the analy sis year.7 - 11

**Table 7**  **- 3**  **Successful Oil and Gas Wells Drilled , NSPS**  **Future Scenario, 2015 2011**  **Baseline Under Final NSPS**  **Successful Wells Drilled**  Natural Gas 16,373 19,097 19,162 Crude Oil 10,352 11,025 11,025 **Total 26,725**  **30,122 30,164**  **% Change in Successful Wells Drilled from Baseline** Natural Gas 0.34% Crude Oil 0.00% **Total 0.22%**  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 0.34%. Table 7
- 4 pre sents the forecast of successful wells by well ty pe, for onshore drilling in the lower 48 states. The results show that conventional well drilling is unaffected by the NSPS, as reduced emission completion and completion combustion requirements are directe d 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.7 - 12

**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 2,785 Shale Gas 5,007 7,022 7,066 Coalbed Methane 1,593 1,609 1,618 **Total 16,308**  **19,010 19,076**  **% Change in Successful Wells Drilled from Baseline** Conventional Gas Wells 0.00% Tight Sands 0.47% Shale Gas 0.63% Coalbed Methane 0.56% **Total 0.35%**  Well drilling in tight sands is estimated to increase slightly , about 0.47 percent. Drilling in shale gas is forecast to increase from the baseline b y 0.63 percent. Wells in CBM reserves are also estimated to increase from the baseline b y 0.56 percent. 7.2.3.2 Impacts on Production, Prices, and Consumption Table 7
- 5 shows estimates of the changes in the domestic production of natural gas and crude oil under the final NSPS and NESHAP Amendments, as of 2015. Domestic natural gas and crude oil production are not forecast to change under the final rules, again because impacts of the rules 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 22.4 3 Crude Oil (million barrels/day) 5.46 5.81 5.81 Natural Gas 0.00% Crude Oil 0.00% The NEMS anal ys is estimates no 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 43 bcf). This difference is because NEMS models the adjustment of energy markets to the now relativel y more efficient natural gas production sector. At the new post - rule equilibrium, producers implementing emissions controls still capture and sell approxim ately 43 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 analy sis about voluntary RECs performed, RECs required under State regulations and exploratory wells and relativel y low pressure wells exempted from REC requirements, about 4,100 NSPS - required RECs would be performed on new natural gas well completions, according to the NEMS anal ys is , not including the recompletion s of existing wells . This recovered natural gas substitutes for natural gas that would be produced from the ground absent th e rule. In effect, then, the natural gas that would have been extracted and emitted into the atmosphere is left in the formation f or future extraction , according to these results . 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. With the exception of tight s ands, production from all types of wells is estimated to increase under the final rules. However, the decrease in production from tight sands is estimated to offset the slight production increases estimated in conventional, shale, and coalbed methane form ations.7 - 14

**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. 85 Shale Gas 5.21 7.20 7.2 4 Coalbed Methane 1.72 1.67 1.68 **Total 16.95**  **18.51 18.5**  **1 % Change in Natural Gas Production by Well Type from Baseline**  Conventional Gas Wells 0.27% Tight Sands
- 0.68% Shale Gas 0.56% Coalbed Methane 0.60% **Total 0.05%**  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 price are not forecast to change under the final rules, while cr ude oil prices are forecast to decrease slightly under the NSPS. **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 4.22 Crude Oil (2008$ per barrel) 83.65 94.60 94.59 **% Change in Lower 48 Average Wellhead Price from Baseline** Natural Gas 0.00% Crude Oil
- 0.01%7 - 15

Table 7
- 8 presents estimates of the price of natural gas to final consumers in 2008 dollars per million BTU. Commercial and industrial sector consumers of natural gas are estimated to re ceive slight price increases, while the national average price to consumers of natural gas is not estimated to change . **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 10.35 Commercial 9.26 8.56 8.57 Industrial 4.97 5.0 7 5.08 Electric Power 4.81 4.77 4.77 Transportation 12.30 12.24 12.24 **Average 6.76**  **6.59 6.59**  **% Change in Delivered Prices from Baseline** Residential 0.00% Commercial 0.12% Industrial 0.20% Electric Power 0.00% Transportation 0.00% **Average 0.00%**  Final consumption of natural gas is not estimated to change in 2015 from the baseline under the final rules, as is shown on Table 7
- 9 . Like delivered price, the consumption shifts are distributed differentl y across sectors.7 - 16

**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 4.81 Commercial 3.22 3.38 3.38 Industrial 6.95 8.05 8.06 Electric Power 7.00 6.98 6.97 Transportation 0.03 0.04 0.04 Pipeline Fuel 0.64 0.65 0.65 Lease and Plant Fuel 1.27 1.20 1.20 **Total 23.86**  **25.11 25.11**  **% Change in Consumption from Baseline** Residential 0.00% Commercial 0.00% Industrial 0.12% Electric Power
- 0.14% Transportation 0.00% Pipeline Fuel 0.00% Lease and Plant Fuel 0.00% **Total 0.00%**  Note: Totals may not sum due to independent rounding .
7.2.3.3 Impacts on Imports and National Fuel Mix The NEMS modeling estimates that the impacts from the NSPS and NEHSAP Amendment s are not sufficiently large to affect the trade balance of natural gas. As shown in Table 7
- 10 , estimates of crude oil imports do not vary from the baseline in 2015 under the NSPS.7 - 17

**Table 7**  **- 10**  **Net Imports of Natural Gas and Crude Oil**  **, NSPS Future Scenario, 2015**  **2011 Baseline**  **Under Final NSPS Net Imports**  Natural Gas (trillion cubic feet) 2.75 2.69 2.6 9 Crude Oil (million barrels/day) 9.13 8.70 8.70 **% Change in Net Imports** Natural Gas 0.00 % 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 ys is. The NSPS is estimated to have small effects at the national level. We estimate an increase in 0.01 quadrillion BTU in 2015, a 0.01 percent increase. The percent contribution of natural gas, coal, and biomass is projected to increase slightl y in 2015.7 - 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 39.10 Natural Gas 24.49 25.77 25.78 Coal 20.42 19.73 19.74 Nuclear Power 8.40 8.77 8.77 Hydropower 2.58 2.92 2.92 Biomass 2.98 3.27 3.28 Other Renewable Energy 1.72 2.14 2.14 Other 0.30 0.31 0.31 Total **98.29 102.02**  **102.03 % Change in Consumption from Baseline**  Liquid Fuels 0.00% Natural Gas 0.04% Coal 0.05% Nuclear Power 0.00% Hydropower 0.00% Biomass 0.31% Other Renewable Energy 0.00% Other 0.00% **Total 0.01%**  Note: Totals may not sum due to independent rounding . With the national profile of energy consumption estimated to change slightly under the NSPS in 2015, the year of anal ys is, it is important to examine whether aggregate energy
- related CO 2 - equivalent greenhouse gas (GHG) e missions also shift. A more detaile d 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 from emissions specificall y associated with the extraction, processing, and transportation of fuels in the oil and natural gas sector under examination in this RIA. W e 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 2,433.53 Natural Gas 1,283.78 1,352.20 1,352.24 Coal 1,946.02 1,882.08 1,882.76 Other 11.99 11.99 11.99 **Total 5,601.39**  **5,679.87 5,680.52**  **% Change in Energy -**  **related CO 2**  **- equivalent GHG Emissions from Baseline**  Petroleum 0.00% Natural Gas 0.00% Coal 0.04% 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 rules are predicted to slightly increase consumer
- side aggregate energy- related CO 2 - equ ivalent GHG e missions by about 650 ,000 metric tons (0.01 percent), mainly

because consumer
- side emissions from coal combustion increase slightl y as a result of the slight consumption increases noted in Table 7 - 11 . **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 s ys tem 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 maintenance of control requirements . **7.3.1 Employment Impacts from Pollution Control Requirements**  Regulations set in motion new orders for pollution control equipment and services. New categories of employ

ment 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 r egulation 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. 71 While these revenues and employ ment figures represent gains for the environmental technologies industry , they are costs to the regulated industries required to install the equipment. Moreover, it is not clear the 1.7 million employees in 2008 represent new emp loy 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 lik e they hire workers to produce more output. Morgenstern et al. (2002) examined how regulated industries respond to regulation. Morgenstern et al. identif ied three separate components of the employ ment change in response to a regulation:

 Higher production costs raise market prices, higher prices reduce consumption (and production), reducing demand for labor within the regulated industry (“demand effect”);

71 In 2008, the industry totaled approximately $315 billion in revenues and 1.9 million employees including indirect em ployment effect ; pollution abatement equipment production employed approximately 4.2 million workers in 2008. These indirect employment effects are based on a multiplier for indirect employment = 2.24 (1982 value from Nestor and Pasurka
- appro ximate 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/068f3801d04 7f26e85256883006ffa54/4878b7e2fc08ac6d85256883006c45 2c?OpenDocument7 - 21

 As costs go up, plants add more capital and labor. For example, pollution abatement activities require additional labor services to produce the same level of output (“cost effect”);
 Post - regulation production technologies may be more or less labor intensive (i.e., more/less labor is required per dollar of output) (“factor
- shift 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. Environmental regulations support employ ment in many

basic industries . In addition to the increase 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. T he focus of this part of the anal ys is is on labor requirements related to the compliance a ctions of the affected entities within the affected sector. We do not estimate any potential changes in labor outside of the oil and natural gas sector. This 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 may re quire unprofitable investments for some operat ors , there is a possibility that these producers decrease output in response and creat e downward pressure on labor demand, both in7 - 22

the regulated sector and on those sectors using natural gas as an input. This R IAexcludes 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 h ave 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 th e regulations. Each of these labor changes may either be required as part of an initial effort to comply with the new regulation or required as a continuous or annual effort to maintain compliance. We estimate up - front and continual, annual labor require ments by estimating hours of labor required and converting this number to full
- time equivalents (FTEs) by dividing by

2,080 (40 hours per week multiplied by

52 weeks). We note that this ty pe of FTE estimate cannot be used to make assumptions about the spe cific 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, proces sing plant, or transmission pipelines uses in

– house employees extensively in dail y operations, 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 b etween labor changes within and outside of the regulated sector. The results of this employment estimate are presented in Table 7 - 13 for the final NSPS and in Table 7 - 14 for the final NESHAP Amendments . The tables breaks down the installation, operation, and maintenance estimates b y t ype 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 require ments; the reporting and7 - 23

recordkeeping estimates are consistent with estimates EPA submitted 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 4 FTEs for the final NES HAP 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 570 FTEs for the final NSPS and about 30 FT Es for the final NESHAP Amendments. These ongoing FTE labor requirements can be viewed as sustained labor requirements required for affected entities to continuously comply with the new regulation. Two main categories contain the majority of the labor re quirements for the final rules: implementing reduced emissions completions ( REC ) and reporting and recordkeeping requirements for the final NSPS. Also, note that pneumatic controllers have no up
- front or continuing labor requirements. While the controls do require labor for installation, operation, and maintenance, the required labor is less than that of the controllers that would be used absent the regulation. In this instance, we assume the incremental labor requirements are zero. Implementing REC s are estimated to require about 500 FTE, about 87 percent of the total continuing labor requirements for the final NSPS. 72 We denote REC
- related requirements as continuing, or annual, as the REC requirements will in fact recur annuall y, albeit at different wells each ye ar. The REC requirements are associated with certain new well completions or existing well recompletions . 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
- related labor requirements are annual.

72 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

**7.3.2 Employment**  **Im**

**pacts 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 Regulatory 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 output (environmental quality) to their product mix es . Although legally compelled to satisfy

this new demand, regulated firms have to finance this additional production with the proceeds of sales of their other (market) products. Satisfying this new demand requires additional inputs, including labor, and m ay alter the relative proportions of labor and capital used b y regulated firms in their production processes. Using plant
- level Census information between the years 1979 and 1991, Morgenstern et al. estimate the size of each effect for four polluting and regulated industries (petroleum refining , plastic material, pulp and paper, and steel). On average across the four industries, each additional $1 million (1987$) spending on pollution abatement results in a (statistically insignificant) net increase of 1.5 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 the 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 the final rules. We believe the transfer of parameter es timates from the Morgenstern et al. study to the final NSPS and NESHAP Amendments is beyond the range of the study for two reasons.7 - 25

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

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

**No. of Affected**  **Units Per Unit** 

**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 REC/Combustion 4,107 0 218 0 893,397 0 4 30 New Hydraulically Fractured Gas Wells Com bustion 1,377 0 22 0 29,719 0 14 Hydraulically Re
- fractured Gas Wells REC/Combustion 532 0 218 0 115,721 0 5 6 Hydraulically Re
- fractured Gas Wells Com bustion 121 0 22 0 2,611 0 1 **Equipment Leaks** Processing Plants NSPS Subpart VVA 29 587 887 17,023 25,723 8 12 **Reciprocating Com pressors**  Gathering and Boosting Stations Annual Monitoring/ Maintenance (AMM) 210 1 1 210 210 < 1 < 1 Processing Plants AMM 209 1 1 209 209 < 1 < 1 **Centrifugal Com** **pressors** Processing Plants Route to Control 13 355 0 4,615 0 2 0 **Pneumatic Controllers** Oil and Gas Production Lo w Bleed/Route to Process 13,632 0 0 0 0 0 0 **Storage Vessels** Emissions at least 6 tons per year 95% control 304 271 190 82,279 57,582 40 2 8 **Reporting and Recordkeeping for Complete NSPS** All N/A N/A 0 68,882 0.0 33 **TOTAL N/A**  **N/A N/A**  **104,336 1,194,055**  **50 574**  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 10 Transmission Com bustion devices, recovery devices, process modifications 7 27 285 189 1,998 <1 1 **Reporting and Recordkeeping for Complete NESHAP Amendments**  N/A N/A N/A 6,442 38,923 3 1 9 **TOTAL 81**  **N/A N/A**  **8,631 62,040**  **4 30**  Note: Full
- time equivalents (FTE) are estimated by first multiplying the projected number of affected units by 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 th e final NSPS might offset the costs of compl yi ng with the rule presents challenges to estimating employ ment effects (see Section 3.2.2.1 of the RIA for a detailed discussion of the natural gas recovery). The Morgenstern et al. paper , for example, is intended to 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 effe ct s when compliance costs are expected to be negative. Second, the final regulations primarily affect the natural gas production, processing, and transmission segments of the industry . While the natural gas processing segment of the oil and natural gas industry

is similar to petroleum refining, which is examined in Morgenstern et al., the production side of the oil and natural gas industry (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 because the segments of the oil and natural gas industry affected by

the rules are not examined b y M orgenstern 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 likelihood of additional natural gas recov ery is an important component of the market response to the rule , as it is expected that this additional natural gas recovery will reduce the price of natural gas . Because of the estimated fall in prices in the natural gas sector due to the final NSPS , prices in other sectors that consume natural gas are likely drop slightly due to the decrease in energy prices. This small production increase and price decrease may have a slight stimulative effect on 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 an y 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. Small 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 Amendments and NSPS, the analy sis indicates that these rules will not have a significant economic impact on a substantial number of small entities (or “SISNOSE”). 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 is, under the final NSPS, s ome 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 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 products. T his small entity

impacts anal ys is uses the primary baseline used for the impacts anal ys is of our NSPS . This primary baseline takes into account RECs conducted pursuant to state regulations covering these operations and estimates of RECs performed voluntarily . To estimate emissions reductions and compliance costs arising from these voluntary RECs , EPA used information reported to EPA by partners of the EPA Natural Gas STAR. More detailed discussion on the derivation of the baseline is presented in a techn ical memorandum in the docket 73 , as well as in Section 3 of this RIA . **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 Statist ics of U.S. Businesses (SUSB) provide s national information on the distribution of economic variables b y industry and
73 “Voluntary Reductions from Gas Well Completions with Hydraulic Fracturing” in U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution: Background Supplemental Technical Support Document for the Final New Source Performance Standards. EPA
- 453/R
- 11 - 002. April 2012.7 - 29

ente rprise size . The Census Bureau and the Office of Advocacy of the Small Business Administration (SBA) supported and developed these fil es for use in a broad range of economic anal ys es . 74 Statistics 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:

 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 o r 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 i ndustry 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, in cluding 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 mo re domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single
- establishment firms. Each multi
- establishment company forms one enterprise

—the enterprise emplo yment and annual p ay

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 definitions (SBA, 2008 ) appl y to an establishment ’ s “ultimate pare nt compan y, ” we assume d in this analy sis that the “firm” definition above is consistent with the concept of ultimate parent compan y that is ty pically used for SBREFA anal ys es , and the terms are used int erchangeabl y.

74 S ee http://www.census.gov/csd/susb/ and http://www.sba.gov/advocacy/ for additional details.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 Receipts by Firm Size and NAICS, 2007** Percent of Firms NAICS NAICS Description Total Firms Small Businesses Large

Businesses Total Firms **Number of Firms by Firm Size** 211111 Crude Petroleum and Natural Gas Extraction 6,424 98.5% 1.5% 100.0% 211112 Natural Gas Liquid Extraction 139 70.5% 29.5% 100.0% 213111 Drilling Oil and Gas Wells 2,059 97.6% 2.4% 100.0% 486210 Pipeline Transportation of Natural Gas 126 48.4% 51.6% 100.0% **Total Employment by Firm Size** 211111 Crude Petroleum and Natural Gas Extraction 133,286 41.7% 58.3% 100.0% 211112 Natural Gas Liquid Extraction 8,523 22.0% 78.0% 100.0% 213111 Drilling Oil and Gas Wells 106,426 34.4% 65.6% 100.0% 486210 Pipeline Transportation of Natural Gas 24,683 N/A* N/A* N/A* **Estimated Receipts by Firm Size ($1000)** 211111 Crude Petroleum and Natural Gas Extraction 194,107,252 23.2% 76.8% 100.0% 211112 Natural Gas Liquid Extraction 39,977,741 5.4% 94.6% 100.0% 213111 Drilling Oil and Gas Wells 23,848,238 30.6% 69.4% 100.0% 486210 Pipeline Transportation of Natural Gas 20,796,681 N/A* N/A* N/A* Note: Employment and receipts could not be broken down between small and large businesses because of non
disclosure requirements. Source: SBA 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 o il 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 wel l 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, transportation, 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 focus on this sector. In our understanding, there is no single industry niche for small entities in the production segment of the industry

since small operators have different business strategies and that small entities can own diff

erent ty pes of wells. The organization of firms in the 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 (wildcatters) have been critical sources of industrial innovation and opened up critical new energy supplies for the U.S. (IHS Global Insight). In recent decades, as the oil and gas industry has concentrated via mergers, many of these smaller firms have been absorbed into large firms. Another critical role, which provides an interesting contrast to small firms pioneering new territory , is that smaller independents maintain and operate a large proportion of th e Nation’s low producing wells, which are also known as marginal or stripper wells (Duda et al. 2 005) . 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 of 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 difficult y 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 likely 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 le vels 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 - revenu e ratios to identify small firms that might be significantly

impact ed 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 tes t, 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 normally 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 e stimating small business impacts for a rulemaking such as this one is consistent with guidance offered b y EPA on compliance with SBREFA 75 and is consistent with guidance published b y the U.S. SBA’s Office of Advocacy that suggests that cost as a percentage

75 The SBREFA compliance guidance to EPA rulewriters regarding the types of small business analysis that should be cons idered can be found 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) . 76 **7.4.3 Small**  **Entity Economic Impact Analysis, Final NSPS** 7.4.3.1 Overview of Sample Data and Methods The final NSPS covers emission s 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 groups. 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 th e annual Oil and Gas Journal 150 Survey (OGJ 150) 77 as described in the Industry Profile in Section 2 . Although the proportion of small firm s in the OGJ 150 is smaller than the proportion evaluated b y the Census Bureau’s SUSB, the OGJ 150 provides detailed information on the production activities and financial returns of the firms within the list, which are critical ingredients to the small business impacts analy sis. The Census SUSB provides aggregated totals for all businesses in a particular NAI CS code. It is not possible to use these data to identify

those firms that actually

drill wells or specific financial information for individual firms. The OGJ 150 includes all public firms incorporated in the U.S. with reserves in the U.S. While the OGJ 150 lists only public firms, we believe the list is reasonabl y representative of the

76 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 . 77 Oil and Gas Journal. “ OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010 and Oil and Gas Journal. “OGJ150.” September 21, 2009.7 - 36

larger population of public and private firms operating in this segment of the industry . The sample of firms represented by the OGJ 150 accounts for 62% of the gas wells drilled i n 2008 and 2009. While the population of firms responsible for the remaining 38% of gas wells may include some small private firms, there are also a number of large private companies and foreign firms not represented in the OGJ 150. Examples of companies that are not included in the OGJ 150, but that are likel y responsible for a large number of h ydraulicall y fractured natural gas well completions include BP, Encana, and Royal Dutch Shell. To further examine the representativeness of the sample, EPA compared the revenues reported for the OGJ 150 to those reported for small firms in the Census Bureau’s SUSB. While the average revenues in the OGJ 150 appear significantly larger than those in the Census Bureau’s SUSB, this comparison is misleading. First, the OG J 150 reports pre - tax revenues, which we would expect to be higher in every instance than the post
- tax Census Bureau’s SUSB receipts. 78 Additionally , due to the size of the sample, the descriptive statistics for the OGJ 150 may be influenced by

a few partic ularl y large data points. For example, for firms with 10 to 19 employees, removing one firm from the OGJ 150 sample decreases the average revenue for the group b y approximately

38 percent. The result is roughl y equal to the Census SUSB average for the same group, even before an y adjustment for taxes. We believe that, despite these outliers, the data for the OGJ 150 are generall y representative of the population in this industry. While the Census SUSB data includes a greater proportion of very small firms ( 0 - 4 employees) than the OGJ 150 sample, we believe this sample appropriatel y reflects the industry for a number of reasons. First, the OGJ 150 includes companies of a range of sizes, from 1 to over 1 million employees. While there is generall y a relationsh ip between size and revenues, this does not necessarily

hold true when examining the impacts on individual firms. In some cases, a firm with relativel y few employees may have higher revenues than a mu ch larger firm. Additionally , there is not necessarily a relationship between the size of a firm and the proportion of its costs to revenues. Finally , as discussed above, it is impossible to determine what portion of

78 Census SUSB r eceipts (net of taxes) are defined as the re venue for goods produced, distributed, or services provided, including revenue earned from premiums, commissions and fees, rents, interest, dividends, and royalties. Receipts excludes all revenue collected for local, state, and federal taxes. http://www.ce nsus.gov//econ/susb/definitions.html7 - 37

the firm s in the Census SUSB would be affected firms under the NSPS provisions related to compl etions of hydraulically fractured and refractured natural gas wells . In the anal ys is that follows, we present median, minimum, and maximum values in addition to the average to provide readers with a more complete understanding of the firms in the sample. W e are not able to compare these additional statistics to the Census Bureau’s SUSB due to the aggregated nature of those data. When making a SISNOSE determination, we calculate the sales test ratio at the firm level, rather than as an average as is reported by the Census SUSB . By using this methodology , we ensure that the results reflect the impacts to all firms in the sample and are not skewed b y unusually large data points. We drew upon the OGJ 150 lists published for the years 2008 and 2009 ( Oil and Gas J ournal , September 21, 2009 and Oil and Gas Journal , September 6, 2010) . The year 2009 saw relativel y 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 pric es. Combined, we believe these two years of data are representative. 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 processing facilities 79 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 OGJ survey on the economics of the U.S. pipeline industry . This report examines the economic status of all major and non
- major natural gas pipeline c ompanies . 80 For these firms, we also us ed the American Business Directory and corporate websites to best identify

the ultimate owner of the facilities or companies. These firms represent all potentially

impacted firms in these segments, not a sample.

79 Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010. 80 Oil and Gas Journal. “Natural Gas Pipelines Continue Growth Despite Lo wer Earnings; Oil Profits Grow .” November 1, 2010.7 - 38

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 criteria. We estimate 119 firms (43 percent) are not small firms according to SBA criteria. We are unable to classify the remaining 28 firms (10 percent) because of a lack of required information on employee counts or revenue estimates. Table 7 - 18 shows the estimated revenues for 246 firms for which we have sufficient data that would be potentially

affected by

the final NSPS based upon their activities in 2008 and 2009. We segmented the sample into four groups, production and integrated firms, processing firms, pipeline firms, and pipelines/processing firms. For the firms in the pipelines/processing group, we were unable to determine the firms’ primary line of business, so we opted to group together as a fourth group.7 - 39

**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 engaged in production activities (the E&P firms mentioned earlier).7 - 40

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 s pent 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 oil 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 n atural 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 - 41

apportion the wells dri lled 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** 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**  **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 th e engineering costs estimates, as well as the estimates of expected natural product recovery from controls such as REC . Unlike the anal ys is of regulatory impacts on small entities 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 in advance, particularl y in the case of new and modified sources such as well completions and recompletions which are spatially

diffuse and potentiall y large in number. The engineering cost analy sis estimated compliance costs in a top
- down fashion, projecting the number of new sources at an annual level and multiplying these estimates by7 - 42

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 d 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 o il well compliance costs of $260 per drilled well and natural gas well compliance costs of $8,800 or less than 1 percent of the average costs of drilling a wel l according to EIA (see Table 2
- 8) without considering estimated revenue s from product recovery and $260 and
- $940 per drilled crude oil and natural gas well, respectivel y, with estimated revenues from product recovery included . Note that the divergence o f estimated per well costs between crude oil and natural gas wells is because the final NSPS requirements are primary directed toward natural gas wells. Also note that the per
- well cost savings estimate for natural gas wells is different than the estimate d 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 by 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 f rom 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 es timated at $ 6.9 million without estimated revenues from product recovery and $ 5.0 million with estimated7 - 43

revenues from product recovery , respectivel y, in 2008 dollars, or about $2 0 /MMcf without revenues and $1 4 /MMcf with revenues. The OGJ report on pipeli ne 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 refle ct a representative year or this analysis. We estimate the annual compression and transmission
- related NSPS compliance costs at $ 6.0 million without estimated revenues from product recovery

and $ 5.9 million with estimated revenues from product recovery , r espectivel 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 firms in the OGJ
- based sample will face about $117 million in 2008 dollars, about 69 percent of the estimated annualized costs of the final NSPS without including revenues from additional product recovery of $116 million. When including revenues from additional product recovery , the estimated compli ance costs for the firms in the sample are about $1.1 million. Table 7 - 21 presents the d istribution of estimated final NSPS compliance costs across firm s ize for the firms within our sample. Evident from this table, about 92 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 16 percent of the costs accruing to the integrated and production s egment) are concentrated on small firms.7 - 44

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

Number of Firms Estimated Engineering Compliance Costs Without Estimated Revenues from Natural Gas Product Recovery (2008 dollars) Firm Type/Size Total Average Median Minimum Maximum Production and Integrated Small 77 17,795,916 231,116 48,134 749 2,299,042 Large 47 90,671,503 1,929,181 1,361,483 10,325 7,710,293 Subtotal 124 108,467,419 874,737 221,017 749 7,710,293 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**  **18,281,886 143,952**  **13,602 20**  **2,299,042 Large**  **119 99,012,106**  **832,035 48,054**  **38 7,710,293**  **Total 246**  **117,293,992 476,805**  **22,225 20**  **7,710,293** These distributions are similar when the revenues from expected natural gas recovery are included ( Table 7 - 22 ). A total savings from the final NSPS of about $ 1.1 million is expected to accrue to small firms (about 23 percent of the savings to the integrated and production segment accrue to small fir

ms), while large firms are expected to have a total cost of $ 2.3 million. Note also in Table 7 - 22 that the pipeline and processing segments (and the pipeline/processing firms) are not expected to experience net cost savings (negative costs) from the final NSPS.7 - 45

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

Number of Firms Estimated Engineering Compliance Costs With Estimated Revenues from Natural Gas Product Recovery (millions, 2008 dollars) Firm Type/Size Total Average Median Minimum Maximum Production and Integrated Small 77 - 1,500,434 - 19,486 25 - 218,672 23,982 Large 47 - 5,137,073 - 109,299 - 108,363 - 721,121 924,574 Subtotal 124 - 6,637,507 - 53,528 - 11,873 - 721,121 924,574 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**  **- 1,147,170**  **- 9,033**  **207 -**  **218,672 202,911**  **Large 119**  **2,285,911 19,209**  **2,419 -**  **721,121 2,777,165**  **Total 246**  **1,138,741 4,629**  **343 -**  **721,121 2,777,165** 7 - 46

**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 0.49% 0.11% 0.00% 11.86% Large 47 0.10% 0.07% 0.00% 0.65% Subtotal 124 0.34% 0.09% 0.00% 11.86% Pipeline Small 11 0.01% 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% 0.16% 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**  **0.30% 0.04%**  **0.00% 11.86%**  **Large 119**  **0.05% 0.01%**  **0.00% 0.65%**  **Total 246**  **0.18% 0.02%**  **0.00% 11.86%** 

The mean cost - sales ratio for all businesses when estimated product recovery is excluded from the anal ys is of the sample data is 0.18 percent, with a median ratio of 0.02 percent, a minimum of less than 0.01 percent, and a max imum of over 11 percent ( Table 7 - 23 ). For small firms in the sample, the mean and median cost
- sales ratios are 0.30 percent and 0.04 percent, respectivel y , with a minimum of less than 0.01 percent and a maximum of over 11 percent ( Table 7 - 23 ). Each of these statistics indicates that, when considered in the aggregate, impacts are relativel y higher on small firms than on 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 - 47

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

Number of Firms Descriptive Statistics for Sales Test Ratio With Estimated Revenues from Natural Gas Product Recovery (%) Firm Type/Size Average Median Minimum Maximum Production and Integrated

Small 77 - 0.01% 0.00% - 0.85% 0.40% Large 47 0.00% 0.00 % - 0.06% 0.14% Subtotal 124 - 0.01% 0.00% - 0.85% 0.40% Pipeline Small 11 0.01% 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**  **0.00% 0.00%**  **- 0.85%**  **0.40%**

**Large 119**  **0.00% 0.00%**  **- 0.06%**  **0.14%** Total **246 0.00%**  **0.00% -**  **0.85% 0.40%**  The mean cost - sales ratio for all businesses when estimated product recovery is included is in the sample is less than 0.01 percent, with a median ratio of less than 0.01 percent, a minimum of
- 0.85 percent, and a maximum of 0.40 percent ( Table 7 - 24 ). For small firms in the sample, the mean and median cost
- sales ratios are less than 0.01 percent and less than 0.01 percent, respectively , with a minimum of
- 0.85 percent and a maximum of 0.40 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 i ncluded , 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 gas7 - 48

product recover from implementing controls. When revenues estimates are included, all of the 127 firms (100 percent) have estimated cost
- sales ratio s less than 1 percent. The highest cost
sales ratios for small firms in the sample experiencing impacts are largel y driven by costs accruing to processing and pipeline firms. That said, the incremental costs imposed on firms that process natural gas or tr ansport natural gas via pipelines are not estimated to create significant impacts on a cost
- sales ratio basis at the firm
- level. **Table 7**  **- 25**  **Impact Levels of Final NSPS on Small Firms as a P**  **ercent of Small Firm s 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% 12 3 9 6.9 % 127 100.0% C/S Ratio 1
- 3% 1 0.8 % 0 0.0% CS Ratio greater than 3% 3 2.4% 0 0.0% When the estimated revenues from product recovery are not included in the anal ys is, one firm (less than 1 percent) is estimated to have sales test ratios between 1 and 3 percent. Three firms (less than 3 percent) are estimated to have sales test ratios greater than 3 percent. These results noted, the exclusion of product recovery is somewhat artificial. While the mean engineering compliance costs and revenues estimates are valid, drawing on the means ign ores the distribution around the mean estimates, which risks masking effects. Because of this risk, the following section offers a qualitative discussion of small entities with regard to obtaining REC services, the validity of the cost and performance of REC 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 - 49

7.4.3.3 Small Entity Impact Analysis, Final NSPS, Additional Qualitative Discussion 7.4 .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, and whether small entities pursue particular “niche” strategies that may i nfluence 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 gas well in 2007 was about $4 .8 million (adjusted to 2008 dollars). This average includes lower cost wells that may be relatively

shallow or are not hydraulicall y fractured. Hydraulicall y fractured wells in deep formations may cost up to $10 million. REC s contracted from a service provider are estimated to cost $3 3,200 (in 2008 dollars) or roughl y 0.3% - 0.7% of the ty

pical cost of 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 a REC, a service provider is t ypically 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 multiple well pads. For gas captured and sold to the gathering s ys tem, Lease Automatic Custody Transfer (LACT) meters are ty pically automatically read dail y, and sales transactions are typically settled at the end of the month. Invoices from service providers are generall y delivered in 30
- day increments during the well deve lopment 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, is that 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. To the extent there is a lag between a REC expenditure s and receipt of revenue from recovered products , we believe the impact on cash flows would be minimal.7 - 50

We assume small firms are performing RECs in CO and WY, as in man y instances RECs are required under state regulation. In addition to State regulations, some companies are implementing RECs voluntarily such as through participation in the EPA Natural Gas STAR Program and the focus of recent press reports. As described in more detail below, many small independent E&P companies often do not conduct an y of the actual field work. These firms will ty picall y contract the drilling, completion, testing, well de sign, 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 straightfo rward and inexpensive extension of drilling, completion, and testing activities. To the extent that very

small firms may

specialize in operating 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 that 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 dri lling and completion cost, the effect of any bulk discount disparity between large and small operators will be small, if in fact it does exist.7 - 51

Although small operators may own the majority

of marginal and stripper wells, they will make decisions based on economics just as an y 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 retur n that exceeds alternative investment opportunities. Therefore, small or large operators that are performing h ydraulic fracture completions will experience the same distribution of REC performance. For refracturing an existing well, the well must be a go od candidate to respond to the re
- fracture/completion with a production increase that merits the investment in the re
fracture/completion. There are situations in which operators, large or small, may face constraints in directing captured gas to the gathe ring lines or pipelines . In these instances, this rule p rovides the flexibility to combust completion emissions rather than performing a REC. Plugging and abandoning wells is complex and costly , so sustaining the productivity of wells is important for max imizing the exploitation of proven dom estic resources. However, many marginal gas wells are likel y to be older and in conventional formations, 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 . 7.4 .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 require ments of these rules might present impediments to owners and operators of older equipment. The NSPS is a standard that applies to new or modified sources. Because of this, NSPS requirements target new or modified affected facilities or equipment, such as processing plants and compressors. While the requirements may apply to modifications of existing facilities, it is important to discuss well completion
- related requirements aside from other requirements in the NSPS distinctly . Excluding well completion requirements from the cost estimates, the non
- completion NSPS requirements (related to equipment leaks at processing plants, reciprocating and7 - 52

centrifugal compressors, pneumatic controllers, and storage vessels) are estimated to require about $15 million in annualized engineering costs. EPA also estimates that the annualized costs of these requirements will be mostly if not fully , offset by

revenues expected from natural gas recovery . EPA does not expect these requirements to disproportionately affect producers with older equipment. Meanwhile, the REC and emissions combustion requirements in the final NSPS relate to well completion activities at new hydraulicall y fractured natural gas wells and existing wells that 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 a ge of the well and equipment may be an important factor for small and large producers in determining whether it is economical to fracture or re
- fracture an existing well, this equipment is unlikely

to be subject to the NSPS. To comply with completion
- related requirements, producers are likel y to rel y heavily on portable and temporary completion 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 place and operating in the case of existing wells

—is not likely to be subject to the NSPS requirement. **7.4.4 Small**  **Entity Economic Impact Analysis, Final NESHAP Amendments**  The Final NESHAP Amendments will affect facilities operating three typ es of equipment: gl ycol deh ydrators at production facilities, gl ycol deh ydrators at transmission and compression facilities, and storage vessels. We identified likely affected facilitie s 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 sales ratio to identify small businesse s that might be significantl y impacted b y the NESHAP.7 - 53

While we were able to identify the owners of all but 9 facilities likely to be affected, we could not obtain employment and revenue levels for all of these firms. Overall, we expect about 81 facilities to be affected, and these facilities are owned b y an estimated 42 firms. We were unable to obtain financial information on 7 ( 16 percent) of these firms due to inadequate data. In some instances, firms are private, and financial data is not available. In other instance, firms may no longer exist, since NEI data are not updated continuously . From the ownersh ip information and compliance cost estimates from the engineering anal ys is, we estimated total compliance cost per firm. Of the 35 firms for which we have financial information, we identified 1 1 small firms ( 31 percent) and 2 4 large firms ( 69 percent) th at would be affected b y the NESHAP Amendments . Annual compliance costs for small firms are estimated at $ 3 90 ,000 ( 2 2 percent of the total compliance costs), and annual compliance costs for large firms are estimated at $1
. 1 million ( 66 percent of the total compliance costs). The facilities for which we were unable to identify the ultimate owners, emplo yment, and revenue levels would have an estimated annual compliance cost of $2 00,000 (1 1 percent of the total). All figures are in 2008 dollars. The average estimated annualized compliance cost for the 11 small firms identified in the dataset is $ 35 ,000, while the mean annual revenue figure for the same firms is over $1 16 million, or less than 0.01 percent on average for all 10 firms ( Table 7 - 26 ). The median sale
- test ratio for these firms is smaller at 0. 09 percent. Large firms are likel y to see an average of $ 48 ,000 in annual compliance costs, whereas average revenue fo r these firms exceeds $ 2 9 billion since this set of firms includes many of the very large, integrated energy

firms. For large firms, the average sales
- test ratio is less than 0.01 percent, and the median sales
- test ratio is also 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 Kno wn

Affected Firms % of Total Known

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

C/S Ratio Small 11 31% 0.24% 0.09% < 0.01% 0.93% Large 24 69% < 0.01% < 0.01% < 0.01% 0.01% All 35 100% 0.08% < 0.01% < 0.01% 0.93%7 - 54

Among the small firms, all are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to revenues ( Table 7 - 27 ). T he se firms represent a very small slice of the oil and gas industry in its entirety , less than 0. 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% 11 100 . 0 % 0.17 % C/S Ratio 1
- 3% 0 0.0 % 0 .0 % CS Ratio greater than 3% 0 0.0 % 0.0% **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, 132 of the 1 36 small firms ( 97 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, four firms ( 3 percent) are likely to have impacts greater than 1 percent. Three of these four firms are likely to have impacts greater than 3 percent. When revenues from addition al natural gas product sales are included, all 136 small firms ( 100 percent) are likely to have impacts of less than 1 percent.7 - 55

**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% 132 97.1 % 136 100.0 % C/S Ratio 1
- 3% 1 0.7 % 0 0.0 % CS Ratio greater than 3% 3 2.2 % 0 0.0 % 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 co ndensate recovery engendered by

the implementation of the controls evaluated in this RIA. As much of the additional natural gas recovery is estimated to arise from completion
- related activities, we expect the impact on well
- related compliance costs to be 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 recovery 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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