# Regulatory Impact Analysis

Proposed New Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Ga s

Industry

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

July 2011ii CONTACT INFORMATION

This document has been prepared by staff from the O ffice of Air Quality Planning and Standards, U.S. Environmental Protection Agency. Qu estions related to this document should be addressed to Alexander Macpherson, U.S. Environment al Protection Agency, Office of Air Quality Planning and Standards, C445-B, Research Tr iangle Park, North Carolina 27711 (email: macpherson.alex@epa.gov ).

ACKNOWLEDGEMENTS

In addition to EPA staff from the Office of Air Qua lity Planning and Standards, personnel from the U.S. EPA Office of Atmospheric P rograms, EC/R Incorporated, and ICF International contributed data and analysis to this document. Specific sections where EC/R Incorporated made contributions include the section s describing emissions options, pollution control options, secondary impacts analysis, engine ering cost analysis, and employment impacts. Specific sections where ICF International made cont ributions also include the sections describing emissions options, pollution control options, engin eering cost analysis, employment impacts, and small business impacts.iii TABLE OF CONTENTS

T ABLE OF C ONTENTS .................................................. ................................................... ............... III L IST OF T ABLES .................................................. ................................................... ........................ VI L IST OF F IGURES .................................................. ................................................... ................... VIII 1 E XECUTIVE S UMMARY .................................................. ................................................... ... 1-1
1.1 B ACKGROUND

.................................................. ................................................... ......................................... 1-1 1.2 NSPS R ESULTS

.................................................. ................................................... ....................................... 1-2 1.3 NESHAP A MENDMENTS R ESULTS

.................................................. ................................................... ......... 1-5 1.4 O RGANIZATION OF THIS R EPORT

.................................................. ................................................... ............. 1-7 2 I NDUSTRY P ROFILE .................................................. ................................................... ........ 2-1
2.1 I NTRODUCTION

.................................................. ................................................... ....................................... 2-1 2.2 P RODUCTS OF THE C RUDE O IL AND N ATURAL G AS I NDUSTRY

.................................................. .................. 2-2 2.2.1 Crude Oil .........................................

................................................... ............................................... 2-2 2.2.2 Natural Gas .......................................

................................................... .............................................. 2-2 2.2.3 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 R ESERVES AND M ARKETS

.................................................. ................................................... ....................... 2-8 2.4.1 Domestic Proved Reserves ..........................

................................................... ................................... 2-9 2.4.2 Domestic Production................................

................................................... ..................................... 2-13 2.4.3 Domestic Consumption ..............................

................................................... ................................... 2-21 2.4.4 International Trade ...............................

................................................... ......................................... 2-24 2.4.5 Forecasts .........................................

................................................... .............................................. 2-26 2.5 I NDUSTRY C OSTS

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

................................................... ........................................... 2-31 2.5.2 Lifting Costs .....................................

................................................... ............................................ 2-33 2.5.3 Operating and Equipment Costs .....................

................................................... .............................. 2-34 2.6 F IRM C HARACTERISTICS

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

................................................... ............................................ 2-36 2.6.2 Size Distribution of Firms in Affected ............

................................................... .............................. 2-37 2.6.3 Trends in National Employment and Wages ...........

................................................... ..................... 2-39 2.6.4 Horizontal and Vertical Integration ...............

................................................... ............................... 2-44 2.6.5 Firm-level Information ............................

................................................... ..................................... 2-45 2.6.6 Financial Performance and Condition................

................................................... ........................... 2-49 2.7 R EFERENCES

.................................................. ................................................... ......................................... 2-53 3 E MISSIONS AND E NGINEERING C OSTS .................................................. .............................. 3-1
3.1 I NTRODUCTION

.................................................. ................................................... ....................................... 3-1 3.2 E MISSIONS P OINTS , C ONTROLS , AND E NGINEERING C OSTS A NALYSIS

.................................................. ...... 3-1 3.2.1 Emission Points and Pollution Controls assessed in the RIA ........................................... ................. 3-2 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 .........................

................................................... ..................................... 3-7iv 3.2.2.1 NSPS Sources ......................................

................................................... .................................. 3-8 3.2.2.2 NESHAP Sources ....................................

................................................... ............................ 3-25 3.3 R EFERENCES

.................................................. ................................................... ......................................... 3-26 4 B ENEFITS OF E MISSIONS R EDUCTIONS .................................................. ............................. 4-1
4.1 I NTRODUCTION

.................................................. ................................................... ....................................... 4-1 4.2 D IRECT E MISSION R EDUCTIONS FROM THE O IL AND N ATURAL G AS R ULES ................................................ 4 -2 4.3 S ECONDARY I MPACTS A NALYSIS FOR O IL AND G AS R ULES

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

.................................................. ........................................ 4-8 4.4.1 Benzene ...........................................

................................................... ............................................. 4-13 4.4.2 Toluene ...........................................

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

................................................... .......................................... 4-15 4.4.4 Ethylbenzene.......................................

................................................... .......................................... 4-16 4.4.5 Mixed xylenes .....................................

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

................................................... ............................................. 4-17 4.4.7 Other Air Toxics ..................................

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

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

................................................... ................................ 4-18 4.5.2 PM 2.5 health effects and valuation ......................

................................................... ........................... 4-19 4.5.3 Organic PM welfare effects ........................

................................................... .................................. 4-23 4.5.4 Visibility Effects ................................

................................................... ........................................... 4-24 4.6 VOC S AS AN O ZONE P RECURSOR

.................................................. ................................................... ......... 4-24 4.6.1 Ozone health effects and valuation ................

................................................... ............................... 4-25 4.6.2 Ozone vegetation effects ..........................

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

................................................... ....................................... 4-26 4.7 M ETHANE (CH 4 ) .................................................

................................................... .................................... 4-27 4.7.1 Methane as an ozone precursor .....................

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

................................................... ............................. 4-27 4.8 R EFERENCES

.................................................. ................................................... ......................................... 4-34 5 S TATUTORY AND E XECUTIVE O RDER R EVIEWS .................................................. .............. 5-1
5.1 E XECUTIVE O RDER 12866, R EGULATORY P LANNING AND R EVIEW AND E XECUTIVE O RDER 13563, I MPROVING R EGULATION AND R EGULATORY R EVIEW

.................................................. ........................................ 5-1 5.2 P APERWORK R EDUCTION A CT

.................................................. ................................................... ................ 5-3 5.3 R EGULATORY F LEXIBILITY A CT

.................................................. ................................................... ............. 5-4 5.3.1 Proposed NSPS .....................................

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

................................................... ........................... 5-5 5.4 U NFUNDED M ANDATES R EFORM A CT

.................................................. ................................................... .... 5-6 5.5 E XECUTIVE O RDER 13132: F EDERALISM

.................................................. .................................................. 5-6 5.6 E XECUTIVE O RDER 13175: C ONSULTATION AND C OORDINATION WITH I NDIAN T RIBAL G OVERNMENTS ... 5-6 5.7 E XECUTIVE O RDER 13045: P ROTECTION OF C HILDREN FROM E NVIRONMENTAL H EALTH R ISKS AND S AFETY R ISKS

.................................................. ................................................... ................................................... ............. 5-7 5.8 E XECUTIVE O RDER 13211: A CTIONS C ONCERNING R EGULATIONS T HAT S IGNIFICANTLY A FFECT E NERGY S UPPLY , D ISTRIBUTION , OR U SE

.................................................. ................................................... ....................... 5-7 5.9 N ATIONAL T ECHNOLOGY T RANSFER AND A DVANCEMENT A CT

.................................................. ................ 5-9 5.10 E XECUTIVE O RDER 12898: F EDERAL A CTIONS TO A DDRESS E NVIRONMENTAL J USTICE IN M INORITY P OPULATIONS AND L OW -I NCOME P OPULATIONS

.................................................. ............................................... 5-1 0 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
7.1 I NTRODUCTION

.................................................. ................................................... ....................................... 7-1 7.2 E NERGY S YSTEM I MPACTS A NALYSIS OF P ROPOSED NSPS .............................................. ........................... 7-1 7.2.1 Description of the Department of Energy National En ergy Modeling System .............................. .... 7-2 7.2.2 Inputs to National Energy Modeling System .........

................................................... ......................... 7-5v 7.2.2.1 Compliance Costs for Oil and Gas Exploration and Pr oduction .......................................... .... 7-6 7.2.2.2 Adding Averted Methane Emissions into Natural Gas P roduction ......................................... . 7-9 7.2.2.3 Fixing Canadian Drilling Costs to Baseline Path ...

................................................... ............. 7-10 7.2.3 Energy System Impacts .............................

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

................................................... ......................... 7-11 7.2.3.2 Impacts on Production, Prices, and Consumption ....

................................................... ........... 7-13 7.2.3.3 Impacts on Imports and National Fuel Mix ..........

................................................... ............... 7-17 7.3 E MPLOYMENT I MPACT A NALYSIS

.................................................. ................................................... ......... 7-20 7.3.1 Employment Impacts from Pollution Control Requireme nts ............................................... ............ 7-21 7.3.2 Employment Impacts Primarily on the Regulated Indus try ............................................... .............. 7-24 7.4 S MALL B USINESS I MPACTS A NALYSIS

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

................................................... ............................ 7-29 7.4.2 Small Entity Economic Impact Measures .............

................................................... ........................ 7-34 7.4.3 Small Entity Economic Impact Analysis, Proposed NSP S ................................................. ............. 7-36 7.4.3.1 Overview of Sample Data and Methods ...............

................................................... ............... 7-36 7.4.3.2 Small Entity Impact Analysis, Proposed NSPS, Result s ................................................. ....... 7-42 7.4.3.3 Small Entity Impact Analysis, Proposed NSPS, Additi onal Qualitative Discussion.............. 7-48 7.4.3.4 Small Entity Impact Analysis, Proposed NSPS, Screen ing Analysis Conclusion .................. 7-51 7.4.4 Small Entity Economic Impact Analysis, Proposed NES HAP Amendments .................................. 7 -52 7.5 R EFERENCES

.................................................. ................................................... ......................................... 7-54vi LIST OF TABLES

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

Regulatory Options in 2015 (millions of 2008$) 1

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

NESHAP in 2015 (millions of 2008$) 1

.................................................. ............................................ 1-6 Table 2-1 Technically Recoverable Crude Oil and Natural Gas R esource Estimates, 2007............................ . 2-10 Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Produ ction, Proved Reserves, and Proved Ultimate

Recovery, 1977-2008 ...............................

................................................... ..................................... 2-11 Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by St ate, 2008 ......................................... ............ 2-13 Table 2-4 Crude Oil Domestic Production, Wells, Well Producti vity, 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 Developme nt Wells and Average Depth, 1990-2009 . 2-17 Table 2-7 U.S. Onshore and Offshore Oil, Gas, and Produced Wa ter Generation, 2007 .............................. ... 2-18 Table 2-8 U.S. Oil and Natural Gas Pipeline Mileage, 1990-200 8 ................................................. .................. 2-20 Table 2-9 Crude Oil Consumption by Sector, 1990-2009 ........

................................................... ..................... 2-21 Table 2-10 Natural Gas Consumption by Sector, 1990-2009 ......

................................................... .................... 2-23 Table 2-11 Total Crude Oil and Petroleum Products Imports (Mil lion Bbl), 1990-2009 .............................. ..... 2-25 Table 2-12 Natural Gas Imports and Exports, 1990-2009 ........

................................................... ....................... 2-26 Table 2-13 Forecast of Total Successful Wells Drilled, Lower 4 8 States, 2010-2035 ............................... ........ 2-27 Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhea d 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, 1 990-09 ............................................ ......... 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 Tota l Assets), 2010 ................................... ....... 2-47 Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throu ghput), 2009 ...................................... ........ 2-48 Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2009 ............................. 2-49 Table 2-22 Selected Financial Items from Income Statements (Bi llion 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 200 8 Dollars) ........................................ .......... 2-52 Table 3-1 Emissions Sources, Points, and Controls Included in NSPS Options...................................... ........... 3-9 Table 3-2 Summary of Capital and Annualized Costs per Unit fo r NSPS Emissions Points ........................... 3-15 Table 3-3 Estimated Nationwide Compliance Costs, Emissions Re ductions, and VOC Reduction CostEffectiveness by Emissions Sources and Points, NSPS , 2015 ............................................ ............. 3-16 Table 3-4 Estimated Engineering Compliance Costs, NSPS (2008$ ) ................................................. ............. 3-18 Table 3-5 Estimates of Control Unit-level and National Level Natural Gas and Condensate Recovery, NSPS

Options, 2015 .....................................

................................................... ........................................... 3-21 Table 3-6 Simple Rate of Return Estimate for NSPS Control Opt ions .............................................. .............. 3-23 Table 3-7 Summary of Estimated Capital and Annual Costs, Emis sions Reductions, and HAP Reduction CostEffectiveness for Proposed NESHAP Amendments ......

................................................... ............... 3-26 Table 4-1 Direct Emission Reductions Associated with Options for the Oil and Natural Gas NSPS and NESHAP

amendments in 2015 (short tons per year) ..........

................................................... ............................. 4-3 Table 4-2 Secondary Air Pollutant Impacts Associated with Con trol Techniques by Emissions Category

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

................................................... ................................... 4-6 Table 4-3 Modeled Changes in Energy-related CO 2 -equivalent Emissions by Fuel Type for the Proposed Oil

and Gas NSPS in 2015 (million metric tons) ("Consum er-Side") 1

.................................................. ... 4-7 Table 4-4 Total Change in CO 2 -equivalent Emissions including Secondary Impacts f or the Proposed Oil and Gas NSPS in 2015 (million metric tons) ............

................................................... ............................. 4-7 Table 4-5 Summary of Emissions Changes for the Proposed Oil a nd Gas NSPS and NESHAP in 2015 (short

tons per year) ....................................

................................................... ............................................... 4-8 Table 4-6 Monetized Benefits-per-Ton Estimates for VOCs (2008 $) ................................................ .............. 4-22 Table 5-1 Summary of the Monetized Benefits, Costs, and Net B enefits for the Proposed Oil and Natural Gas

NSPS and NESHAP Amendments in 2015 (millions of 200 8$) 1

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

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

NSPS in 2015 (millions of 2008$) 1

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

NESHAP amendments in 2015 (millions of 2008$) 1

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

tons per year) ....................................

................................................... ............................................... 6-6 Table 7-1 Summary of Additional Annualized O&M Costs (on a Pe r New Well Basis) for Environmental

Controls Entered into NEMS.........................

................................................... .................................. 7-8 Table 7-2 Summary of Additional Per Completion/Recompletion C osts (2008$) for Environmental Controls

Entered into NEMS .................................

................................................... ........................................ 7-9 Table 7-3 Successful Oil and Gas Wells Drilled, NSPS Options

................................................... .................. 7-11 Table 7-4 Successful Wells Drilled by Well Type (Onshore, Low er 48 States), NSPS Options...................... 7 -12 Table 7-5 Annual Domestic Natural Gas and Crude Oil Productio n, NSPS Options ................................... .... 7-13 Table 7-6 Natural Gas Production by Well Type (Onshore, Lower 48 States), NSPS Options ....................... 7 -15 Table 7-7 Lower 48 Average Natural Gas and Crude Oil Wellhead Price, NSPS Options .............................. 7-16 Table 7-8 Delivered Natural Gas Prices by Sector (2008$ per m illion BTU), 2015, NSPS Options ............... 7-1 6 Table 7-9 Natural Gas Consumption by Sector, NSPS Options ...

................................................... ................. 7-17 Table 7-10 Net Imports of Natural Gas and Crude Oil, NSPS Opti ons ............................................... ............... 7-18 Table 7-11 Total Energy Consumption by Energy Type (Quadrillio n BTU), NSPS Options ............................ 7 -19 Table 7-12 Modeled Change in Energy-related "Consumer-Side" CO 2 -equivalent GHG Emissions ................ 7-20 Table 7-13 Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and

Maintaining Control Equipment Requirements, Propose d NSPS Option in 2015 ........................... 7 -26 Table 7-14 Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating, and

Maintaining Control Equipment Requirements, Propose d NESHAP Amendments in 2015 ........... 7-27 Table 7-15 Number of Firms, Total Employment, and Estimated Re ceipts by Firm Size and NAICS, 2007 .... 7-31 Table 7-16 Distribution of Small and Large Firms by Number of Firms, Total Employment, and Estimated

Receipts by Firm Size and NAICS, 2007 .............

................................................... ......................... 7-32 Table 7-17 Distribution of Crude Oil and Natural Gas Wells by Productivity Level, 2009 .......................... ..... 7-34 Table 7-18 Estimated Revenues for Firms in Sample, by Firm Typ e and Size ........................................ .......... 7-38 Table 7-19 Descriptive Statistics of Capital and Exploration E xpenditures, Small and Large Firms in Sample,

2008 and 2009 (million 2008 dollars) ..............

................................................... ............................. 7-39 Table 7-20 Descriptive Statistics of Estimated Wells Drilled, Small and Large Firms in Sample, 2008 and 2009

(million 2008 dollars) ............................

................................................... ........................................ 7-40 Table 7-21 Distribution of Estimated Proposed NSPS Compliance Costs Without Revenues from Additional

Natural Gas Product Recovery across Firm Size in Sa mple of Firms ..................................... ......... 7-43 Table 7-22 Distribution of Estimated Proposed NSPS Compliance Costs With Revenues from Additional Natural

Gas Product Recovery across Firm Size in Sample of Firms ............................................. .............. 7-44 Table 7-23 Summary of Sales Test Ratios, Without Revenues from Additional Natural Gas Product Recovery for Firms Affected by Proposed NSPS ...................

................................................... ............................ 7-45 Table 7-24 Summary of Sales Test Ratios, With Revenues from Ad ditional Natural Gas Product Recovery for

Firms Affected by Proposed NSPS ...................

................................................... ............................ 7-46 Table 7-25 Impact Levels of Proposed NSPS on Small Firms as a Percent of Small Firms in Sample, With and

Without Revenues from Additional Natural Gas Produc t Recovery ........................................ ........ 7-47 Table 7-26 Summary of Sales Test Ratios for Firms Affected by Proposed NESHAP Amendments ................ 7-53 Table 7-27 Affected Small Firms as a Percent of Small Firms Na tionwide, Proposed NESHAP amendments . 7-53viii LIST OF FIGURES
Figure 2-1 A) Domestic Crude Oil Proved Reserves and Cumulativ e Production, 1990-2008. B) Domestic

Natural Gas Proved Reserves and Cumulative Producti on, 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, 19 90-2009. .......................................... ............ 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 C onsumption), 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 4 8 States, 2010-2035 ............................... ........ 2-28 Figure 2-7 Forecast of Domestic Crude Oil Production and Net I mports, 2010-2035 ................................. ...... 2-30 Figure 2-8 Costs of Crude Oil and Natural Gas Wells Drilled, 1 981-2008 .......................................... ............. 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 Co mpanies, 1981-2008 (3-year Running Average)2-

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

dollars), 1976-2009 ...............................

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

2-36 Figure 2-13 Employment in Drilling of Oil and Natural Gas Wells (NAICS 213111), and Total Oil and Natural

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

................................................... ................................. 2-40 Figure 2-14 Employment in Crude Petroleum and Natural Gas Extra ction (NAICS 211111) and Total Crude Oil

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

................................................... ....................... 2-41 Figure 2-15 Employment in Natural Gas Liquid Extraction (NAICS 211112), Employment in Pipeline

Transportation of Natural Gas (NAICS 486210), and T otal Natural Gas Production, 1990-2009 ... 2-42 Figure 2-16 Oil and Natural Gas Industry Average Wages by NAICS , 1990-2009 ($2008) ............................... 2-44 Figure 3-1 Sensitivity Analysis of Proposed NSPS Annualized Co sts after Revenues from Additional Product

Recovery are Included .............................

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

NATA) .............................................

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

sources (2005 NATA) ...............................

................................................... .................................... 4-11 Figure 6-1 Illustrative Break-Even Diagram for Alternate Natur al Gas Prices for the NSPS ........................ ...... 6-2 Figure 7-1 Organization of NEMS Modules (source: U.S. Energy I nformation Administration) ....................... 7-41-1 1 EXECUTIVE SUMMARY

1.1 Background
The U.S. Environmental Protection Agency (EPA) revi ewed the New Source Performance Standards (NSPS) for volatile organic c ompound and sulfur dioxide emissions from Natural Gas Processing Plants. As a result of thes e NSPS, this proposal amends the Crude Oil and Natural Gas Production source category currentl y listed under section 111 of the Clean Air
Act to include Natural Gas Transmission and Distrib ution, amends the existing NSPS for volatile organic compounds (VOCs) from Natural Gas Processin g Plants, and proposes NSPS for stationary sources in the source categories that ar e not covered by the existing NSPS. In addition, this proposal addresses the residual risk and technology review conducted for two source categories in the Oil and Natural Gas sector regulated by separate National Emission Standards for Hazardous Air Pollutants (NESHAP). I t also proposes standards for emission sources not currently addressed, as well as amendme nts to improve aspects of these NESHAP related to applicability and implementation. Final ly, it addresses provisions in these NESHAP related to emissions during periods of startup, shu tdown, and malfunction.

As part of the regulatory process, EPA is required to develop a regulatory impact analysis (RIA) for rules that have costs or benefits that ex ceed $100 million. EPA estimates the proposed NSPS will have costs that exceed $100 million, so t he Agency has prepared an RIA. Because the NESHAP amendments are being proposed in the sam e rulemaking package (i.e., same Preamble), we have chosen to present the economic i mpact analysis for the proposed NESHAP
amendments within the same document as the NSPS RIA

.
This RIA includes an economic impact analysis and a n analysis of human health and climate impacts anticipated from the proposed NSPS and NESHAP amendments. We also estimate potential impacts of the proposed NSPS on the national energy economy using the U.S. Energy Information Administration’s National Energy Modeling System (NEMS). The engineering compliance costs are annualized using a 7 percent discount rate. This analysis assumes an analysis year of 2015.

Several proposed emission controls for the NSPS cap ture VOC emissions that otherwise would be vented to the atmosphere. Since methane i s co-emitted with VOCs, a large proportion1-2

of the averted methane emissions can be directed in to natural gas production streams and sold. One emissions control option, reduced emissions wel l completions, also recovers saleable hydrocarbon condensates which would otherwise be lo st 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 p roposed option. In the economic impact and energy economy analyses for the NSPS, we presen t results for three regulatory options that include the additional product recovery and the rev enues we expect producers to gain from the additional product recovery.

1.2 NSPS Results
For the proposed NSPS, the key results of the RIA f ollow and are summarized in Table 1-1:

 Benefits Analysis: The proposed NSPS is anticipated to prevent signif icant new emissions, including 37,000 tons of hazardous air pollutants ( HAPs), 540,000 tons of VOCs, and 3.4 million tons of methane. While we expect that thes e avoided emissions will result in improvements in ambient air quality and reductions in health effects associated with exposure to HAPs, ozone, and particulate matter (PM ), we have determined that quantification of those benefits cannot be accompli shed 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 i n emissions for this industrial sector with the data currently available. In addition to health improvements, there will be improvements in visibility effects, ecosystem effects, as well a s additional natural gas recovery. The methane emissions reductions associated with the pr oposed NSPS are likely to result in significant climate co-benefits. The specific cont rol technologies for the proposed NSPS are anticipated to have minor secondary disbenefits, in cluding an increase of 990,000 tons of carbon dioxide (CO 2 ), 510 tons of nitrogen oxides NOx, 7.6 tons of PM, 2,800 tons of CO, and 1,000 tons of total hydrocarbons (THC) as well as emission reductions associated with the energy system impacts. The net CO 2 -equivalent emission reductions are 62 million metric tons.

 Engineering Cost Analysis: EPA estimates the total capital cost of the propose d NSPS will be $740 million. The total annualized engineering costs of the proposed NSPS will be $740 million. When estimated revenues from additional n atural gas and condensate recovery are included, the annualized engineering costs of the p roposed NSPS are estimated at $-45 million, assuming a wellhead natural gas price of $ 4/thousand cubic feet (Mcf) and condensate price of $70/barrel. Possible explanati ons for why there appear to be negative cost control technologies are discussed in the engi neering costs analysis section in the RIA. The estimated engineering compliance costs that inc lude the product recovery are sensitive to the assumption about the price of the recovered pro duct. There is also geographic variability in wellhead prices, which can also influence estima ted engineering costs. For example, $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $180 million, given EPA estimates th at 180 billion cubic feet of natural gas1-3

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

 Energy System Impacts: Using the NEMS, when additional natural gas recover y is included, the analysis of energy system impacts for the proposed NSPS shows that domestic natural gas production is likely to increase slight ly (about 20 billion cubic feet or 0.1 percent) and average natural gas prices to decrease slightly (about $0.04/Mcf or 0.9 percent at the wellhead for onshore production in the lower 48 sta tes). Domestic crude oil production is not expected to change, while average crude oil prices are estimated to decrease slightly (about $0.02/barrel or less than 0.1 percent at the wellhe ad for onshore production in the lower 48 states). All prices are in 2008 dollars.

 Small Entity Analyses: EPA performed a screening analysis for impacts on s mall entities by comparing compliance costs to revenues. For the pr oposed NSPS, we found that there will not be a significant impact on a substantial number of small entities (SISNOSE).

 Employment Impacts Analysis: EPA estimated the labor impacts due to the install ation, operation, and maintenance of control equipment, as well as labor associated with new reporting and recordkeeping requirements. We estim ate up-front and continual, annual labor requirements by estimating hours of labor required for compliance and converting this number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks). The up-front labor requirement to co mply with the proposed NSPS is estimated at 230 full-time-equivalent employees. Th e annual labor requirement to comply with proposed NSPS is estimated at about 2,400 full -time-equivalent employees. We note that this type of FTE estimate cannot be used to ma ke assumptions about the specific number of people involved or whether new jobs are created for new employees.1-4

Table 1-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Oil and Natural Gas NSPS Regulatory Options in 2015 (millio ns of 2008$) 1 Option 1: Alternative Option 2: Proposed 4 Option 3: Alternative

Total Monetized Benefits 2 N/A N/A N/A
Total Costs 3 -$19 million -$45 million $77 million
Net Benefits N/A N/A N/A
Non-monetized Benefits 17,000 tons of HAPs 5 37,000 tons of HAPs 5 37,000 tons of HAPs 5 270,000 tons of VOCs 540,000 tons of VOCs 550,00 0 tons of VOCs 1.6 million tons of methane 5 3.4 million tons of methane 5 3.4 million tons of methane 5

Health effects of HAP exposure 5 Health effects of HAP exposure 5 Health effects of HAP exposure 5
Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Visibility impairment Visibility impairment Visibi lity impairment Vegetation effects Vegetation effects Vegetation e ffects Climate effects 5 Climate effects 5 Climate effects 5

1 All estimates are for the implementation year (2015 ) and include estimated revenue from additional nat ural gas recovery as a result of the NSPS.

2 While we expect that these avoided emissions will r esult in improvements in air quality and reductions in health effects associated with HAPs, ozone, and particulat e matter (PM) as well as climate effects associated with methane, we have determined that quantification of those benefi ts and co-benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there ar e no benefits or co-benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect im pacts of the reductions in emissions for this indus trial sector with the data currently available. The specific control tec hnologies for the proposed NSPS are anticipated to have minor secondary disbenefits, including an increase of 990 ,000 tons of CO 2 , 510 tons of NOx, 7.6 tons of PM, 2,800 tons of CO, and 1,000 tons of total hydrocarbons (THC) as w ell as emission reductions associated with the ener gy system impacts. The net CO 2 -equivalent emission reductions are 62 million metr ic tons.

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

4 The negative cost for the NSPS Options 1 and 2 refl ects the inclusion of revenues from additional natu ral gas and hydrocarbon condensate recovery that are estimated as a result of the proposed NSPS. Possible explana tions for why there appear to be negative cost control technologi es are discussed in the engineering costs analysis section in the RIA.

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

1.3 NESHAP Amendments Results For the proposed NESHAP amendments, the key results of the RIA follow and are summarized in Table 1-2:

 Benefits Analysis: The proposed NESHAP amendments are anticipated to reduce a significant amount of existing emissions, including 1,400 tons of HAPs, 9,200 tons of VOCs, and 4,900 tons of methane. Results from the residu al risk assessment indicate that for existing natural gas transmission and storage, the maximum individual cancer risk decreases from 90-in-a-million before controls to 20-in-a-mil lion after controls with benzene as the primary cancer risk driver. While we expect that th ese avoided emissions will result in improvements in ambient air quality and reductions in health effects associated with exposure to HAPs, ozone, and PM, we have determined that quantification of those benefits cannot be accomplished for this rule. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulti es in modeling the direct and indirect impacts of the reductions in emissions for this industrial sec tor with the data currently available. In addition to health improvements, there will be impr ovements in visibility effects, ecosystem effects, and climate effects as well as additional natural gas recovery. The specific control technologies for the proposed NESHAP is anticipated to have minor secondary disbenefits, including an increase of 5,500 tons of CO 2 , 2.9 tons of NOx, 16 tons of CO, and 6.0 tons of total hydrocarbons (THC) as well as emission reduct ions associated with the energy system impacts. The net CO 2 -equivalent emission reductions are 93 thousand met ric tons.

 Engineering Cost Analysis: EPA estimates the total capital costs of the propos ed NESHAP amendments to be $52 million. Total annualized engi neering costs of the proposed NESHAP amendments are estimated to be $16 million. All est imates are in 2008 dollars.

 Energy System Impacts: We did not estimate the energy economy impacts of t he proposed NESHAP amendments as the expected costs of the rule are not likely to have estimable impacts on the national energy economy.

 Small Entity Analyses: EPA performed a screening analysis for impacts on s mall entities by comparing compliance costs to revenues. For the pr oposed NESHAP amendments, we found that there will not be a significant impact on a su bstantial number of small entities (SISNOSE).

 Employment Impacts Analysis: EPA estimated the labor impacts due to the install ation, operation, and maintenance of control equipment, as well as labor associated with new reporting and recordkeeping requirements. We estim ate up-front and continual, annual labor requirements by estimating hours of labor required for compliance and converting this number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks). The up-front labor requirement to co mply with the proposed NESHAP Amendments is estimated at 120 full-time-equivalent employees. The annual labor requirement to comply with proposed NESHAP Amendmen ts is estimated at about 102 fulltime-equivalent employees. We note that this type o f FTE estimate cannot be used to make assumptions about the specific number of people inv olved or whether new jobs are created for new employees.1-6

 Break-Even Analysis: A break-even analysis suggests that HAP emissions would need to be valued at $12,000 per ton for the benefits to excee d the costs if the health benefits, ecosystem and climate co-benefits from the reductions in VOC and methane emissions are assumed to be zero. If we assume the health benefits from HAP emission reductions are zero, the VOC emissions would need to be valued at $1,700 per ton or the methane emissions would need to be valued at $3,300 per ton for the benefits to exc eed the costs. Previous assessments have shown that the PM 2.5 benefits associated with reducing VOC emissions wer e valued at $280 to $7,000 per ton of VOC emissions reduced in speci fic urban areas. Previous assessments have shown that the PM 2.5 benefits associated with reducing VOC emissions wer e valued at $280 to $7,000 per ton of VOC emissions reduced in specific urban areas, ozone benefits valued at $240 to $1,000 per ton of VOC emissions r educed, and climate co-benefits valued at $110 to $1,400 per short ton of methane reduced. All estimates are in 2008 dollars.

Table 1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed Oil and Natural Gas NESHAP in 2015 (millio ns of 2008$) 1

Option 1: Proposed (Floor)

Total Monetized Benefits 2 N/A
Total Costs 3 $16 million
Net Benefits N/A
Non-monetized Benefits 1,400 tons of HAPs 9,200 tons of VOCs 4
4,900 tons of methane 4

Health effects of HAP exposure

Health effects of PM 2.5 and ozone exposure 4

Visibility impairment 4 Vegetation effects 4
Climate effects 4

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

2 While we expect that these avoided emissions will r esult in improvements in air quality and reductions in health effects associated with HAPs, ozone, and PM as well as climate effects associated with methane, we hav e determined that quantification of those benefits an d co-benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefi ts or co-benefits of the rules; rather, it is a ref lection of the difficulties in modeling the direct and indirect im pacts of the reductions in emissions for this indus trial sector with the data currently available. The specific control technologies for the proposed NESHAP are anticipate d to have minor secondary disbenefits, including an increase of 5,500 tons of CO 2 , 2.9 tons of NOx, 16 tons of CO, and 6.0 tons of THC as well as emission reductions associat ed with the energy system impacts. The net CO 2 -equivalent emission reductions are 93 thousand metric tons.

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

4 Reduced exposure to VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects, and cl imate effects are co-benefits.1-7

1.4 Organization of this Report
The remainder of this report details the methodolog y and the results of the RIA. Section 2 presents the industry profile of the oil and natu ral gas industry. Section 3 describes the emissions and engineering cost analysis. Section 4 presents the benefits analysis. Section 5 presents statutory and executive order analyses. S ection 6 presents a comparison of benefits and costs. Section 7 presents energy system impact, em ployment impact, and small business impact analyses.2-1 2 INDUSTRY PROFILE

2.1 Introduction
The oil and natural gas industry includes the follo wing five segments: drilling and extraction, processing, transportation, refining, a nd marketing. The Oil and Natural Gas NSPS and NESHAP amendments propose controls for the oil and natural gas products and processes of the drilling and extraction of crude oil and natura l gas, natural gas processing, and natural gas transportation segments.

Most crude oil and natural gas production facilitie s 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 well s is included in NAICS 213111. Most natural gas transmission and storage facilities are classif ied under NAICS 486210—Pipeline Transportation of Natural Gas. While other NAICS ( 213112—Support Activities for Oil and Gas Operations, 221210—Natural Gas Distribution, 48 6110—Pipeline Transportation of Crude Oil, and 541360—Geophysical Surveying and Mapping S ervices) are often included in the oil and natural gas sector, these are not discussed in detail in the Industry Profile because they are not directly affected by the proposed NSPS and NESH AP amendments.

The outputs of the oil and natural gas industry are inputs for larger production processes of gas, energy, and petroleum products. As of 2009 , the Energy Information Administration (EIA) estimates that about 526,000 producing oil we lls and 493,000 producing natural gas wells operated in the United States. Domestic dry natura l gas production was 20.5 trillion cubic feet (tcf) in 2009, the highest production level since 1 970. The leading five natural gas producing states are Texas, Alaska, Wyoming, Oklahoma, and Ne w 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 Me xico.

The Industry Profile provides a brief introduction to the components of the oil and natural gas industry that are relevant to the proposed NSPS and NESHAP Amendments. The purpose is to give the reader a general understanding of the g eophysical, engineering, and economic aspects of the industry that are addressed in subsequent ec onomic analysis in this RIA. The Industry Profile relies heavily on background material from the U.S. EPA’s “Economic Analysis of Air2-2

Pollution Regulations: Oil and Natural Gas Producti on” (1996) and the U.S. EPA’s “Sector Notebook Project: Profile of the Oil and Gas Extrac tion 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 re servoir characteristics are likely to be different from that of any other reservoir.

2.2.1 Crude Oil
Crude oil can be broadly classified as paraffinic, naphthenic (or asphalt-based), or intermediate. Generally, paraffinic crudes are use d in the manufacture of lube oils and kerosene. Paraffinic crudes have a high concentration of stra ight chain hydrocarbons and are relatively low in sulfur compounds. Naphthenic crudes are general ly used in the manufacture of gasolines and asphalt and have a high concentration of olefin and aromatic hydrocarbons. Naphthenic crudes may contain a high concentration of sulfur compound s. Intermediate crudes are those that are not classified in either of the above categories.

Another classification measure of crude oil and oth er hydrocarbons is by API gravity. API gravity is a weight per unit volume measure of a hydrocarbon liquid as determined by a method recommended by the American Petroleum Instit ute (API). A heavy or paraffinic crude oil is typically one with API gravity of 20 o or less, while a light or naphthenic crude oil, wh ich typically flows freely at atmospheric conditions, u sually has API gravity in the range of the high
30's to the low 40's.

Crude oils recovered in the production phase of the petroleum industry may be referred to
as live crudes. Live crudes contain entrained or d issolved gases which may be released during processing or storage. Dead crudes are those that have gone through various separation and storage phases and contain little, if any, entraine d or dissolved gases.

2.2.2 Natural Gas
Natural gas is a mixture of hydrocarbons and varyin g quantities of non-hydrocarbons that exists in a gaseous phase or in solution with crude oil or other hydrocarbon liquids in natural2-3

underground reservoirs. Natural gas may contain co ntaminants, such as hydrogen sulfide (H 2 S),
CO 2 , mercaptans, and entrained solids.

Natural gas may be classified as wet gas or dry gas . Wet gas is unprocessed or partially processed natural gas produced from a reservoir tha t contains condensable hydrocarbons. Dry gas is either natural gas whose water content has b een reduced through dehydration or natural gas that contains little or no recoverable liquid h ydrocarbons.

Natural gas streams that contain threshold concentr ations of H 2 S are classified as sour gases. Those with threshold concentrations of CO 2 are classified as acid gases. The process by
which these two contaminants are removed from the n atural 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 f eet, along with the presence of CO 2 . Concentrations of H 2 S and CO 2 , along with organic sulfur compounds, vary widely among sour gases. A majority total onshore natural gas produc tion and nearly all of offshore natural gas production is classified as sweet.

2.2.3 Condensates
Condensates are hydrocarbons in a gaseous state und er reservoir conditions, but become liquid in either the wellbore or the production pro cess. Condensates, including volatile oils, typically have an API gravity of 40 o or more. In addition, condensates may include hyd rocarbon liquids recovered from gaseous streams from various oil and natural gas production or natural gas transmission and storage processes and operatio ns.

2.2.4 Other Recovered Hydrocarbons
Various hydrocarbons may be recovered through the p rocessing of the extracted hydrocarbon streams. These hydrocarbons include mi xed 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 produc tion well. Produced water is separated from the extracted hydrocarbon streams in various production processes and operations.

2.3 Oil and Natural Gas Production Processes

2.3.1 Exploration and Drilling
Exploration involves the search for rock formations associated with oil or natural gas deposits and involves geophysical prospecting and/o r exploratory drilling. Well development occurs after exploration has located an economicall y recoverable field and involves the construction of one or more wells from the beginnin g (called spudding) to either abandonment if no hydrocarbons are found or to well completion if hydrocarbons are found in sufficient quantities.

After the site of a well has been located, drilling commences. A well bore is created by using a rotary drill to drill into the ground. As the well bore gets deeper sections of drill pipe ar e added. A mix of fluids called drilling mud is rele ased down into the drill pipe then up the walls of the well bore, which removes drill cuttings by t aking them to the surface. The weight of the mud prevents high-pressure reservoir fluids from pu shing their way out (“blowing out”). The well bore is cased in with telescoping steel piping during drilling to avoid its collapse and to prevent water infiltration into the well and to pre vent crude oil and natural gas from contaminating the water table. The steel pipe is c emented by filling the gap between the steel casing and the wellbore with cement.

Horizontal drilling technology has been available s ince the 1950s. Horizontal drilling facilitates the construction of horizontal wells by allowing for the well bore to run horizontally underground, increasing the surface area of contact between the reservoir and the well bore so that more oil or natural gas can move into the well . Horizontal wells are particularly useful in unconventional gas extraction where the gas is not concentrated in a reservoir. Recent advances have made it possible to steer the drill in differe nt directions (directional drilling) from the2-5

surface without stopping the drill to switch direct ions and allowing for a more controlled and precise drilling trajectory.

Hydraulic fracturing (also referred to as “fracking ”) has been performed since the 1940s (U.S. DOE, 2009). Hydraulic fracturing involves pu mping fluids into the well under very high pressures in order to fracture the formation contai ning 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 hydroca rbons and separating the mixture of liquid hydrocarbons, gas, water, and solids, removi ng 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, s eparating the liquid and gas components, and removing impurities.

Oil and natural gas are found in the pores of rocks and sand (Hyne, 2001). In a conventional source, the oil and natural gas have b een pushed out of these pores by water and moved until an impermeable surface had been reached . Because the oil and natural gas can travel no further, the liquids and gases accumulate in a reservoir. Where oil and gas are associated, a gas cap forms above the oil. Natural gas is extracted from a well either because it is associated with oil in an oil well or from a pure n atural gas reservoir. Once a well has been drilled to reach the reservoir, the oil and gas can be extracted in different ways depending on the well pressure (Hyne, 2001).

Frequently, oil and natural gas are produced from t he 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 occur s because natural gas usually is in the top of the oil formation, while the well usually is drille d into the bottom portion to recover most of the liquid. Production sites often handle crude oil an d natural gas from more than one well (Hyne, 2001).2-6

Well pressure is required to move the resource up f rom the well to the surface. During primary extraction, pressure from the well itself drives the resource o ut of the well directly. Well pressure depletes during this process. Typica lly, about 30 to 35 percent of the resource in the reservoir is extracted this way (Hyne, 2001). The amount extracted depends on the specific well characteristics (such as permeability and oil viscosity). Lacking enough pressure for the resource to surface, gas or water is injected into the well to increase the well pressure and force the resource out ( secondary or improved oil recovery). Finally, in tertiary extraction or enhanced recovery, gas, chemicals or steam are injected into the well. This can result in recovering up to 60 percent of the original amount of oil in the reservoir (Hyne, 2001).

In contrast to conventional sources, unconventional oil and gas are trapped in rock or sand or, in the case of oil, are found in rock as a chemical substance that requires a further chemical transformation to become oil (U.S. DOE, 20 09). Therefore, the resource does not
move into a reservoir as in the case with a convent ional source. Mining, induced pressure, or heat is required to release the resource. The spec ific type of extraction method needed depends on the type of formation where the resource is loca ted. Unconventional natural gas resource types relevant for this proposal include:

• Shale Natural Gas: Shale natural gas comes from sediments of clay mi xed with organic matter. These sediments form low permeability shal e rock formations that do not allow the gas to move. To release the gas, the rock must be fragmented, making the extraction process more complex than it is for conventional ga s extraction. Shale gas can be extracted by drilling either vertically or horizont ally, and breaking the rock using hydraulic fracturing (U.S. DOE, 2009).

• Tight Sands Natural Gas: Reservoirs are composed of low-porosity sandstone s and carbonate into which natural gas has migrated from other sources. Extraction of the natural gas from tight gas reservoirs is often perf ormed 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 a ctivity of microbes in the coal or from alterations of the coal through te mperature changes. Horizontal drilling2-7

is used but given that coalbed methane reservoirs a re frequently associated with underground water reservoirs, hydraulic fracturing is often restricted (Andrews, 2009).

2.3.3 Natural Gas Processing
Natural gas conditioning is the process of removing impurities from the gas stream so that it is of sufficient quality to pass through tr ansportation systems and used by final consumers. Conditioning is not always required. Natural gas f rom some formations emerges from the well sufficiently pure that it can be sent directly to t he pipeline. As the natural gas is separated from the liquid components, it may contain impurities th at 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 concen trations) to humans and is corrosive for pipes.
It is therefore desirable to remove H 2 S as soon as possible in the conditioning process.

Another concern is that posed by water vapor. At h igh pressures, water can react with components in the gas to form gas hydrates, which a re solids that can clog pipes, valves, and gauges, especially at cold temperatures (Manning an d 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 vap or pressure hydrocarbons that are liquids at surface temperature and pressure (benzene, toluene, ethylbenzene, and xylene, or BTEX) are removed and processed separately.

Dehydration removes water from the gas stream. Thr ee main approaches toward dehydration are the use of a liquid or solid desicc ant, and refrigeration. When using a liquid desiccant, the gas is exposed to a glycol that abso rbs the water. The water can be evaporated from the glycol by a process called heat regenerati on. The glycol can then be reused. Solid desiccants, often materials called molecular sieves , are crystals with high surface areas that attract the water molecules. The solids can be reg enerated simply by heating them above the boiling point of water. Finally, particularly for gas extracted from deep, hot wells, simply cooling the gas to a temperature below the condensa tion point of water can remove enough water to transport the gas. Of the three approaches ment ioned above, glycol dehydration is the most common when processing at or near the well.2-8

Sweetening is the procedure in which H 2 S and sometimes CO 2 are removed from the gas
stream. The most common method is amine treatment. In this process, the gas stream is exposed to an amine solution, which will react with the H 2 S and separate them from the natural gas. The contaminant gas solution is then heated, thereby se parating the gases and regenerating the amine. The sulfur gas may be disposed of by flaring, incin erating, or when a market exists, sending it to a sulfur-recovery facility to generate elemental su lfur as a salable product.

2.3.4 Natural Gas Transmission and Distribution
After processing, natural gas enters a network of c ompressor stations, high-pressure transmission pipelines, and often-underground stora ge sites. Compressor stations are any facility which supplies energy to move natural gas at increa sed pressure in transmission pipelines or into underground storage. Typically, compressor station s are located at intervals along a transmission pipeline to maintain desired pressure for natural g as transport. These stations will use either large internal combustion engines or gas turbines a s prime movers to provide the necessary horsepower to maintain system pressure. Undergroun d storage facilities are subsurface facilities utilized for storing natural gas which has been tra nsferred from its original location for the primary purpose of load balancing, which is the pro cess of equalizing the receipt and delivery of natural gas. Processes and operations that may be located at underground storage facilities include compression and dehydration.

2.4 Reserves and Markets
Crude oil and natural gas have historically served two separate and distinct markets. Oil is an international commodity, transported and cons umed throughout the world. Natural gas, on the other hand, has historically been consumed clos e to where it is produced. However, as pipeline infrastructure and LNG trade expand, natur al gas is increasingly a national and international commodity. The following subsections provide historical and forecast data on the U.S. reserves, production, consumption, and foreign trade of crude oil and natural gas.2-9

2.4.1 Domestic Proved Reserves
Table 2-1 shows crude oil and natural gas proved re serves, inferred reserves, and undiscovered and total technically recoverable reso urces as of 2007. According to EIA 1 , these concepts are defined as:

• Proved reserves: estimated quantities of energy sources that analys is of geologic and engineering data demonstrates with reasonable certa inty are recoverable under existing economic and operating conditions.

• Inferred reserves: the estimate of total volume recovery from known cr ude oil or natural gas reservoirs or aggregation of such reser voirs is expected to increase during the time between discovery and permanent abandonmen t.

• Technically recoverable: resources that are producible using current technol ogy without reference to the economic viability of prod uction.

The sum of proved reserves, inferred reserves, and undiscovered technically recoverable resources equal the total technically recoverable r esources. As seen in Table 2-1, as of 2007, proved domestic crude oil reserves accounted for ab out 12 percent of the totally technically
recoverable crude oil resources.

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

Table 2-1 Technically Recoverable Crude Oil and Nat ural 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 76 0.4 1625.7 48 States Onshore Non-Associated Gas 149.0 59 5.9 144.1 889.0 48 States Offshore Non-Associated Gas 12.4 50 .7 233.0 296.0 Associated-Dissolved Gas 20.7 117.2 137.9 Alaska 11.9 24.8 266.1 302.8 Shale Gas and Coalbed Methane 43.7 385 64.2 493. 0 Total U.S. 237.7 1056.3 824.6 2118.7 Source: U.S. Energy Information Administration, Annual Energy Review 2010. Inferred reserves for associateddissolved natural gas are included in "Undiscovered Technically Recoverable Resources." Totals may no t sum due to independent rounding.

Proved natural gas reserves accounted for about 11 percent of the totally technically recoverable natural gas resources. Significant proportions of these reserves exist in Alaska and offshore

areas.
Table 2-2 and Figure 2-1 show trends in crude oil a nd natural gas production and reserves from 1990 to 2008. In Table 2-2, proved ultimate r ecovery equals the sum of cumulative production and proved reserves. While crude oil an d natural gas are nonrenewable resources, the table shows that proved ultimate recovery rises ove r time as new discoveries become economically accessible. Reserves growth and decli ne is also partly a function of exploration activities, which are correlated with oil and natur al gas prices. For example, when oil prices are high there is more of an incentive to use secondary and tertiary recovery, as well as to develop
unconventional sources.2-11

Table 2-2 Crude Oil and Natural Gas Cumulative Dome stic 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 1,000,7 45 1996 173,198 23,324 196,522 854,453 166,474 1,020,9 27 1997 175,553 23,887 199,440 873,355 167,223 1,040,5 78 1998 177,835 22,370 200,205 892,379 164,041 1,056,4 20 1999 179,981 23,168 203,149 911,211 167,406 1,078,6 17 2000 182,112 23,517 205,629 930,393 177,427 1,107,8 20 2001 184,230 23,844 208,074 950,009 183,460 1,133,4 69 2002 186,327 24,023 210,350 968,937 186,946 1,155,8 83 2003 188,400 23,106 211,506 988,036 189,044 1,177,0 80 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 prove d reserves has declined over time for both crude oil and natural gas, from above 10 percent in the early 1990s to 8 to 9 percent from 2006 to 2008 for crude oil and from above 11 percent during the 1990s to about 8 percent from 2008 to 2008 for natural gas.2-12

Figure 2-1 A) Domestic Crude Oil Proved Reserves an d Cumulative Production, 1990- 2008. B) Domestic Natural Gas Proved Reserves and C umulative Production, 1990-2008
Table 2-3 presents the U.S. proved reserves of crud e oil and natural gas by state or producing area as of 2008. Four areas currently ac count for 77 percent of the U.S. total proved reserves of crude oil, led by Texas and followed by U.S. Federal Offshore, Alaska, and California. The top five states (Texas, Wyoming, C olorado, Oklahoma, and New Mexico) account for about 69 percent of the U.S. total prov ed reserves of natural gas. A). Crude Oil

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

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008Crude Oil (million bbl)

B). Natural Gas

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

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008Natural Gas (bcf)

Cumulative Production Proved Reserves2-13

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

State/Region Crude Oil (million bbls) Dry Natural Gas (bcf) Crude Oil

(percent of total) Dry Natural Gas

(percent of total) Alaska 3,507 7,699 18.3 3.1 Alabama 38 3,290 0.2 1.3 Arkansas 30 5,626 0.2 2.3 California 2,705 2,406 14.1 1.0 Colorado 288 23,302 1.5 9.5 Florida 3 1 0.0 0.0 Illinois 54 0 0.3 0.0 Indiana 15 0 0.1 0.0 Kansas 243 3,557 1.3 1.5 Kentucky 17 2,714 0.1 1.1 Louisiana 388 11,573 2.0 4.7 Michigan 48 3,174 0.3 1.3 Mississippi 249 1,030 1.3 0.4 Montana 321 1,000 1.7 0.4 Nebraska 8 0 0.0 0.0 New Mexico 654 16,285 3.4 6.7 New York 0 389 0.0 0.2 North Dakota 573 541 3.0 0.2 Ohio 38 985 0.2 0.4 Oklahoma 581 20,845 3.0 8.5 Pennsylvania 14 3,577 0.1 1.5 Texas 4,555 77,546 23.8 31.7 Utah 286 6,643 1.5 2.7 Virginia 0 2,378 0.0 1.0 West Virginia 23 5,136 0.1 2.1 Wyoming 556 31,143 2.9 12.7 Miscellaneous States 24 270 0.1 0.1 U.S. Federal Offshore 3,903 13,546 20.4 5.5 Total Proved Reserves 19,121 244,656 100.0 100.0 Source: U.S. Energy Information Administration, Annual Energy Review 2010. Totals may not sum due to independent rounding.

2.4.2 Domestic Production
Domestic oil production is currently in a state of decline that began in 1970. Table 2-4 shows U.S. production in 2009 at 1938 million bbl p er year, the highest level since 2004. However, annual domestic production of crude oil ha s dropped by almost 750 million bbl since
1990.2-14

Table 2-4 Crude Oil Domestic Production, Wells, Wel l 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 a t the lease or wellhead at which domestic crude is purchased. * 2009 Oil price is preliminary

Average well productivity has also decreased since 1990 (Table 2-4 and Figure 2-2). These production and productivity decreases are in spite of the fact that average first purchase prices have shown a generally increasing trend. The excep tion to this general trend occurred in 2008 and 2009 when the real price increased up to 86 dol lars per barrel and production in 2009
increased to almost 2 million bbl of oil.

Annual production of natural gas from natural gas w ells has increased nearly 3000 bcf from the 1990 to 2009 (Table 2-5). Natural gas ext racted 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 withd rawals in recent years.2-15

Table 2-5 Natural Gas Production and Well Productiv ity, 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 37.67 6 2008 18,011 5,845 1,898 25,754 20,286 478,562 37.63 6 2009 18,881 5,186 2,110 26,177 20,955 495,697 38.08 9 Source: U.S. Energy Information Administration, Annual Energy Review 2010. *Dry gas production is gas production after account ing for gas used repressurizing wells, the removal of nonhydrocarbon gases, vented and flared gas, and ga s used as fuel during the production process.

The number of wells producing natural gas wells has nearly doubled between 1990 and 2009 (Figure 2-2). While the number of producing wells has increased overall, average well productivity has declined, despite improvements in exploration and gas well stimulation technologies.2-16

Figure 2-2 A) Total Producing Crude Oil Wells and A verage Well Productivity, 1990- 2009. B) Total Producing Natural Gas Wells and Ave rage Well Productivity, 1990-2009.

Domestic exploration and development for oil has co ntinued during the last two decades. From 2002 to 2009, crude oil well drilling showed s ignificant increases, although the 1992-2001 period showed relatively low levels of crude drilli ng activity compared to periods before and after (Table 2-6). The drop in 2009 showed a depar ture from this trend, likely due to the recession experienced in the U.S.

Meanwhile, natural gas drilling has increased signi ficantly during the 1990-2009 period. Like crude oil drilling, 2009 saw a relatively low level of natural gas drillings. The success rate of wells (producing wells versus dry wells) has als o increased gradually over time from 75 percent in 1990, to 86 percent in 2000, to 90 perce nt in 2009 (Table 2-6). The increasing success rate reflects improvements in exploration technolog y, as well as technological improvements in A). Crude Oil Wells

0 100 200 300 400 500 600 700

1990 19 91 1992 19 93 1994 19 95 1996 19 97 1998 19 99 2 0 00 20 0 1 2 0 02 20 0 3 2004 20 05 2006 20 07 2008 20 09Producing Wells

0 1,000 2,000 3,000 4,000 5,000Crude Oil (bbl)/Well

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

B). Natural Gas Wells

0 100 200 300 400 500 600

1990 19 9 1 19 92 1993 19 94 19 95 1996 19 97 1 9 98 1999 20 00 2001 20 02 2003 20 0 4 20 05 2006 20 07 20 08 2009Producing Wells

0 10 20 30 40 50 60 70Natural Gas(MMcf)/Well

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

well drilling and completion. Similarly, well aver age depth has also increased by during this period (Table 2-6).
Table 2-6 Crude Oil and Natural Gas Exploratory and Development Wells and Average Depth, 1990-2009
Wells Drilled

Year Crude Oil Natural Gas Dry Holes Total Successful Wells (percent) Average

Depth (ft) 1990 12,800 11,227 8,237 32,264 75 4,841 1991 12,542 9,768 7,476 29,786 75 4,872 1992 9,379 8,149 5,857 23,385 75 5,138 1993 8,828 9,829 6,093 24,750 75 5,407 1994 7,334 9,358 5,092 21,784 77 5,736 1995 8,230 8,081 4,813 21,124 77 5,560 1996 8,819 9,015 4,890 22,724 79 5,573 1997 11,189 11,494 5,874 28,557 79 5,664 1998 7,659 11,613 4,763 24,035 80 5,722 1999 4,759 11,979 3,554 20,292 83 5,070 2000 8,089 16,986 4,134 29,209 86 4,942 2001 8,880 22,033 4,564 35,477 87 5,077 2002 6,762 17,297 3,728 27,787 87 5,223 2003 8,104 20,685 3,970 32,759 88 5,418 2004 8,764 24,112 4,053 36,929 89 5,534 2005E 10,696 28,500 4,656 43,852 89 5,486 2006E 13,289 32,878 5,183 51,350 90 5,537 2007E 13,564 33,132 5,121 51,817 90 5,959 2008E 17,370 34,118 5,726 57,214 90 6,202 2009E 13,175 19,153 3,537 35,865 90 6,108 Source: U.S. Energy Information Administration, Annual Energy Review 2010. Values for 2005-2009 are estimates.

Produced water is an important byproduct of the oil and natural gas industry, as management, including reuse and recycling, of produ ced water can be costly and challenging. Texas, California, Wyoming, Oklahoma, and Kansas we re the top five states in terms of produced water volumes in 2007 (Table 2-7). These estimates do not include estimates of flowback water from hydraulic fracturing activities (ANL 2009).2-18

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

State Crude Oil

(1000 bbl) Total Gas

(bcf) Produced Water

(1000 bbl) Total Oil and

Natural Gas (1000 bbls oil equivalent) Barrels

Produced Water per Barrel Oil Equivalent Alabama 5,028 285 119,004 55,758 2.13 Alaska 263,595 3,498 801,336 886,239 0.90 Arizona 43 1 68 221 0.31 Arkansas 6,103 272 166,011 54,519 3.05 California 244,000 312 2,552,194 299,536 8.52 Colorado 2,375 1,288 383,846 231,639 1.66 Florida 2,078 2 50,296 2,434 20.66 Illinois 3,202 no data 136,872 3,202 42.75 Indiana 1,727 4 40,200 2,439 16.48 Kansas 36,612 371 1,244,329 102,650 12.12 Kentucky 3,572 95 24,607 20,482 1.20 Louisiana 52,495 1,382 1,149,643 298,491 3.85 Michigan 5,180 168 114,580 35,084 3.27 Mississippi 20,027 97 330,730 37,293 8.87 Missouri 80 no data 1,613 80 20.16 Montana 34,749 95 182,266 51,659 3.53 Nebraska 2,335 1 49,312 2,513 19.62 Nevada 408 0 6,785 408 16.63 New Mexico 59,138 1,526 665,685 330,766 2.01 New York 378 55 649 10,168 0.06 North Dakota 44,543 71 134,991 57,181 2.36 Ohio 5,422 86 6,940 20,730 0.33 Oklahoma 60,760 1,643 2,195,180 353,214 6.21 Pennsylvania 1,537 172 3,912 32,153 0.12 South Dakota 1,665 12 4,186 3,801 1.10 Tennessee 350 1 2,263 528 4.29 Texas 342,087 6,878 7,376,913 1,566,371 4.71 Utah 19,520 385 148,579 88,050 1.69 Virginia 19 112 1,562 19,955 0.08 West Virginia 679 225 8,337 40,729 0.20 Wyoming 54,052 2,253 2,355,671 455,086 5.18 State Total 1,273,759 21,290 20,258,560 5,063,379 4.00 Federal Offshore 467,180 2,787 587,353 963,266 0.6 1 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 usi ng the conversion of 0.178 barrels of crude oil equ als 1000 cubic feet natural gas. Totals may not sum due to indepe ndent rounding.2-19

As can be seen in Table 2-7, the amount of water pr oduced is not necessarily correlated with the ratio of water produced to the volume of o il or natural gas produced. Texas, Alaska and Wyoming were the three largest producers in barrels of oil equivalent (boe) terms, but had relatively low rates of water production compared t o more Midwestern states, such Illinois, Missouri, Indiana, and Kansas.

Figure 2-3 shows the distribution of produced water management practices in 2007.

Figure 2-3 U.S. Produced Water Volume by Management Practice, 2007
More than half of the water produced (51 percent) w as re-injected to enhance resource recovery through maintaining reservoir pressure or hydraulic ally pushing oil from the reservoir. Another third (34 percent) was injected, typically into wel ls 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 t he remaining produced water (11 percent, the difference between the total managed and total gene rated) is uncertain (ANL, 2009).

The movement of crude oil and natural gas primarily takes place via pipelines. Total crude oil pipeline mileage has decreased during the 1990-2008 period (Table 2-8), appearing to follow the downward supply trend shown in Table 2-4 . While exhibiting some variation, pipeline mileage transporting refined products rema ined relatively constant. 51%

34% 3% 11%

Injection for Enhanced Recovery Injection or Disposal Surface Discharge

Unknown

Source: Argonne National Laboratory2-20

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 31,3 16 1,335,530 1995 97,029 84,883 181,912 1,003,798 296,947 30,93 1 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 34,46 3 1,331,775 1998 87,663 90,985 178,648 1,040,765 302,714 29,16 5 1,372,644 1999 86,369 91,094 177,463 1,035,946 296,114 32,27 6 1,364,336 2000 85,480 91,516 176,996 1,050,802 298,957 27,56 1 1,377,320 2001 52,386 85,214 154,877 1,101,485 290,456 21,61 4 1,413,555 2002 52,854 80,551 149,619 1,136,479 303,541 22,55 9 1,462,579 2003 50,149 75,565 139,901 1,107,559 301,827 22,75 8 1,432,144 2004 50,749 76,258 142,200 1,156,863 303,216 24,73 4 1,484,813 2005 46,234 71,310 131,348 1,160,311 300,663 23,39 9 1,484,373 2006 47,617 81,103 140,861 1,182,884 300,458 20,42 0 1,503,762 2007 46,658 85,666 147,235 1,202,135 301,171 19,70 2 1,523,008 2008 50,214 84,914 146,822 1,204,162 303,331 20,3 18 1,527,811

Source: U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Off ice of Pipeline Safety, Natural Gas Transmission, Gas Distribution, and Haz ardous 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 t ypes: distribution mains, transmission pipelines, and gathering lines. Gathering lines ar e low-volume pipelines that gather natural gas from production sites to deliver directly to gas pr ocessing plants or compression stations that connect numerous gathering lines to transport gas p rimarily to processing plants. Transmission pipelines move large volumes of gas to or from proc essing plants to distribution points. From these distribution points, the gas enters a distrib ution system that delivers the gas to final consumers. Table 2-8 shows gathering lines decreas ing from 1990 from above 30,000 miles from 1990 to 1995 to around 20,000 miles in 2007 an d 2008. Transmission pipelines added2-21

about 10,000 miles during this period, from about 2 92,000 in 1990 to about 303,000 miles in 2008. The most significant growth among all types of pipeline was in distribution, which increased about 260,000 miles during the 1990 to 20 08 period, driving an increase in total natural gas pipeline mileage (Figure 2-1). The gro wth in distribution is likely driven by expanding production as well as expanding gas marke ts in growing U.S. towns and cities.

2.4.3 Domestic Consumption
Historical crude oil sector-level consumption trend s for 1990 through 2009 are shown in Table 2-9 and Figure 2-4. Total consumption rose g radually 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 d uring 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, 1990-200 9 Percent of Total

Year Total

(million bbl) Residential Commercial Industrial Transportation Sector Electric

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

Figure 2-4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990- 2009

Natural gas consumption has increased over the last twenty years. From 1990 to 2009, total U.S. consumption increased by an average of a bout 1 percent per year (Table 2-10 and Figure 2-5). Over the same period, industrial cons umption of natural gas declined, whereas electric power generation increased its consumption quite dramatically, an important trend in the industry as many utilities increasingly use natural gas for peak generation or switch from coalbased to natural gas-based electricity generation. The residential, commercial, and transportation sectors maintained their consumption levels at more or less constant levels during this time period. 0% 10% 20% 30% 40% 50% 60% 70% 80%

1990 1991 1992

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

2003 2004 2005 2006 2007

2008 2009*Consumption (% of total)

Residential Commercial Industrial Transportation Sector Electric 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

Figure 2-5 Natural Gas Consumption by Sector (Perc ent of Total Consumption), 1990- 2009

2.4.4 International Trade Imports of crude oil and refined petroleum products have increased over the last twenty years, showing increased substitution of imports fo r domestic production, as well as imports satisfying growing consumer demand in the U.S (Tabl e 2-11). Crude oil imports have increased by about 2 percent per year on average, whereas pet roleum products have increased by 1 percent

on average per year. 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50%

1990 199 1 1992 199 3 1994 199 5 1996 1997 1998 1999

2000 2001 200

2 2003 200 4 2 005 200 6 2007 2008 2009*Consumption (% of total)

Residential Commercial Industrial Transportation Sector Electric Power2-25

Table 2-11 Total Crude Oil and Petroleum Products I mports (Million Bbl), 1990-2009 Year Crude Oil Petroleum Products Total Petroleum 1990 2,151 775 2,926 1991 2,111 673 2,784 1992 2,226 661 2,887 1993 2,477 669 3,146 1994 2,578 706 3,284 1995 2,639 586 3,225 1996 2,748 721 3,469 1997 3,002 707 3,709 1998 3,178 731 3,908 1999 3,187 774 3,961 2000 3,320 874 4,194 2001 3,405 928 4,333 2002 3,336 872 4,209 2003 3,528 949 4,477 2004 3,692 1,119 4,811 2005 3,696 1,310 5,006 2006 3,693 1,310 5,003 2007 3,661 1,255 4,916 2008 3,581 1,146 4,727 2009 3,307 973 4,280

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

Natural gas imports also increased steadily from 19 90 to 2007 in volume and percentage terms (Table 2-12). The years 2007 and 2008 saw imp orted natural gas constituting a lower percentage of domestic natural gas consumption. In 2009, the U.S exported 700 bcf natural gas to Canada, 338 bcf to Mexico via pipeline, and 33 b cf to Japan in LNG-form. In 2009, the U.S. primarily imported natural gas from Canada (3268 bc f, 87 percent) via pipeline, although a growing percentage of natural gas imports are in LN G-form shipped from countries such as Trinidad and Tobago and Egypt. Until recent years, industry analysts forecast that LNG imports would continue to grow as a percentage of U.S consu mption. However, it is possible that increasingly accessible domestic unconventional gas resources, such as shale gas and coalbed methane, might reduce the need for the U.S. to impo rt natural gas, either via pipeline or shipped
LNG.2-26

Table 2-12 Natural Gas Imports and Exports, 1990-20 09

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 drill ing activity and crude oil and natural gas domestic production, imports, and prices. The fore casts are from the 2011 Annual Energy Outlook produced by EIA, the most current forecast information available from EIA. As will be discussed in detail in Section 3, to analyze the im pacts of the proposed NSPS on the national energy economy, we use the National Energy Modeling System (NEMS) that was used to produce the 2011 Annual Energy Outlook.

Table 2-13 and Figure 2-6 present forecasts of succ essful wells drilled in the U.S. from
2010 to 2035. Crude oil well forecasts for the low er 48 states show a rise from 2010 to a peak in 2019, which is followed by a gradual decline until the terminal year in the forecast, totaling a 28 percent decline for the forecast period. The forec ast of successful offshore crude oil wells shows a variable but generally increasing trend.2-27

Table 2-13 Forecast of Total Successful Wells Dril led, Lower 48 States, 2010-2035
Lower 48 U.S. States Offshore Totals

Year Crude Oil Conventional

Natural Gas Tight

Sands Devonian

Shale Coalbed

Methane Crude

Oil Natural

gas Crude

Oil Natural Gas 2010 12,082 7,302 2,393 4,196 2,426 74 56 12,155 16 ,373 2011 10,271 7,267 2,441 5,007 1,593 81 73 10,352 16 ,380 2012 10,456 7,228 2,440 5,852 1,438 80 71 10,536 17 ,028 2013 10,724 7,407 2,650 6,758 1,564 79 68 10,802 18 ,447 2014 10,844 7,378 2,659 6,831 1,509 85 87 10,929 18 ,463 2015 10,941 7,607 2,772 7,022 1,609 84 87 11,025 19 ,096 2016 11,015 7,789 2,817 7,104 1,633 94 89 11,108 19 ,431 2017 11,160 7,767 2,829 7,089 1,631 104 100 11,264 19,416 2018 11,210 7,862 2,870 7,128 1,658 112 101 11,323 19,619 2019 11,268 8,022 2,943 7,210 1,722 104 103 11,373 20,000 2020 10,845 8,136 3,140 7,415 2,228 89 81 10,934 21 ,000 2021 10,849 8,545 3,286 7,621 2,324 91 84 10,940 21 ,860 2022 10,717 8,871 3,384 7,950 2,361 90 77 10,807 22 ,642 2023 10,680 9,282 3,558 8,117 2,499 92 96 10,772 23 ,551 2024 10,371 9,838 3,774 8,379 2,626 87 77 10,458 24 ,694 2025 10,364 10,200 3,952 8,703 2,623 93 84 10,457 2 5,562 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 2 7,633 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 3 1,239 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 3 3,206 2035 8,743 13,003 5,705 12,062 3,905 109 108 8,85 2 34,782 Source: U.S. Energy Information Administration, Annual Energy Outlook 2011.

Meanwhile, Table 2-13 and Figure 2-6 show increases for all types of natural gas drilling in the lower 48 states. Drilling in shale reservoi rs is expected to rise most dramatically, about 190 percent during the forecast period, while drill ing in coalbed methane and tight sands reservoirs increase significantly, 61 percent and 1 38 percent, respectively. Despite the growth in drilling in unconventional reservoirs, EIA forecast s successful conventional natural gas wells to increase about 78 percent during this period. Offs hore natural gas wells are also expected to increase during the next 25 years, but not to the d egree of onshore drilling.2-28

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

Table 2-14 presents forecasts of domestic crude oil production, reserves, imports and prices. Domestic crude oil production increases sl ightly during the forecast period, with much of the growth coming from onshore production in the lo wer 48 states. Alaskan oil production is
forecast to decline from 2010 to a low of 99 millio n barrels in 2030, but rising above that level for the final five years of the forecast. Net impo rts of crude oil are forecast to decline slightly during the forecast period. Figure 2-7 depicts the se trends graphically. All told, EIA forecasts total crude oil to decrease about 3 percent from 20 10 to 2035. 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000

2010 2015 2020 2025 2030 2035Successful Wells

Crude Oil Conventional Natural Gas

Tight Sands Devonian Shale Coalbed Methane2-29

Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2010-2035 Domestic Production (million bbls)

Year Total Domestic Lower 48

Onshore Lower 48

Offshore Alaska Lower 48

End of Year Reserves Net

Imports Total

Crude Supply (million bbls) Lower 48

Average Wellhead Price (2009 dollars per bbl) 2010 2,011 1,136 653 223 17,634 3,346 5,361 78.6 2011 1,993 1,212 566 215 17,955 3,331 5,352 84.0 2012 1,962 1,233 529 200 18,026 3,276 5,239 86.2 2013 2,037 1,251 592 194 18,694 3,259 5,296 88.6 2014 2,102 1,267 648 188 19,327 3,199 5,301 92.0 2015 2,122 1,283 660 179 19,690 3,177 5,299 95.0 2016 2,175 1,299 705 171 20,243 3,127 5,302 98.1 2017 2,218 1,320 735 163 20,720 3,075 5,293 101.0 2018 2,228 1,323 750 154 21,129 3,050 5,277 103.7 2019 2,235 1,343 746 147 21,449 3,029 5,264 105.9 2020 2,219 1,358 709 153 21,573 3,031 5,250 107.4 2021 2,216 1,373 680 163 21,730 3,049 5,265 108.8 2022 2,223 1,395 659 169 21,895 3,006 5,229 110.3 2023 2,201 1,418 622 161 21,921 2,994 5,196 112.0 2024 2,170 1,427 588 155 21,871 2,996 5,166 113.6 2025 2,146 1,431 566 149 21,883 3,010 5,155 115.2 2026 2,123 1,425 561 136 21,936 3,024 5,147 116.6 2027 2,114 1,415 573 125 22,032 3,018 5,131 117.8 2028 2,128 1,403 610 116 22,256 2,999 5,127 118.8 2029 2,120 1,399 614 107 22,301 2,988 5,108 119.3 2030 2,122 1,398 625 99 22,308 2,994 5,116 119.5 2031 2,145 1,391 641 114 22,392 2,977 5,122 119.6 2032 2,191 1,380 675 136 22,610 2,939 5,130 118.8 2033 2,208 1,365 691 152 22,637 2,935 5,143 119.1 2034 2,212 1,351 714 147 22,776 2,955 5,167 119.2 2035 2,170 1,330 698 142 22,651 3,007 5,177 119 .5 Source: U.S. Energy Information Administration, Annual Energy Outlook 2011. Totals may not sum due to independent rounding.

Table 2-14 also shows forecasts of proved reserves in the lower 48 states. The reserves forecast shows steady growth from 2010 to 2035, an increase of 28 percent overall. This increment is larger than the forecast increase in production fro m the lower 48 states during this period, 8 percent, showing reserves are forecast to grow more rapidly than production. Table 2-14 also2-30

shows average wellhead prices increasing a total of 52 percent from 2010 to 2035, from $78.6 per barrel to $119.5 per barrel in 2008 dollar term s.

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

Table 2-15 shows domestic natural gas production is forecast to increase about 24 percent from 2010 to 2035. Contrasted against the much hig her growth in natural gas wells drilled as shown in Table 2-13, per well productivity is expec ted to continue its declining trend. Meanwhile, imports of natural gas via pipeline are expected to decline during the forecast period almost completely, from 2.33 tcf in 2010 to 0.04 in 2035 tcf. Imported LNG also decreases from 0.41 tcf in 2010 to 0.14 tcf in 2035. Total supply , then, increases about 10 percent, from 24.08
tcf in 2010 to 26.57 tcf in 2035. 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

2010 2015 2020 2025 2030 2035Crude Oil (Million bbl)

Total Domestic Net Imports Lower 48 Onshore Lower 48 Offshore Alaska2-31

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

Year Dry Gas Production Supplemental

Natural Gas Net

Imports (Pipeline) Net

Imports (LNG) Total

Supply Lower 48

End of Year Dry Reserves Average Lower 48

Wellhead Price (2009 dollars per Mcf) 2010 21.28 0.07 2.33 0.41 24.08 263.9 4.08 2011 21.05 0.06 2.31 0.44 23.87 266.3 4.09 2012 21.27 0.06 2.17 0.47 23.98 269.1 4.09 2013 21.74 0.06 2.22 0.50 24.52 272.5 4.15 2014 22.03 0.06 2.26 0.45 24.80 276.6 4.16 2015 22.43 0.06 2.32 0.36 25.18 279.4 4.24 2016 22.47 0.06 2.26 0.36 25.16 282.4 4.30 2017 22.66 0.06 2.14 0.41 25.28 286.0 4.33 2018 22.92 0.06 2.00 0.43 25.40 289.2 4.37 2019 23.20 0.06 1.75 0.47 25.48 292.1 4.43 2020 23.43 0.06 1.40 0.50 25.40 293.6 4.59 2021 23.53 0.06 1.08 0.52 25.19 295.1 4.76 2022 23.70 0.06 0.89 0.49 25.14 296.7 4.90 2023 23.85 0.06 0.79 0.45 25.15 297.9 5.08 2024 23.86 0.06 0.77 0.39 25.08 298.4 5.27 2025 23.99 0.06 0.74 0.34 25.12 299.5 5.43 2026 24.06 0.06 0.71 0.27 25.10 300.8 5.54 2027 24.30 0.06 0.69 0.22 25.27 302.1 5.67 2028 24.59 0.06 0.67 0.14 25.47 304.4 5.74 2029 24.85 0.06 0.63 0.14 25.69 306.6 5.78 2030 25.11 0.06 0.63 0.14 25.94 308.5 5.82 2031 25.35 0.06 0.57 0.14 26.13 310.1 5.90 2032 25.57 0.06 0.50 0.14 26.27 311.4 6.01 2033 25.77 0.06 0.38 0.14 26.36 312.6 6.12 2034 26.01 0.06 0.23 0.14 26.44 313.4 6.24 2035 26.33 0.06 0.04 0.14 26.57 314.0 6.42 Source: U.S. Energy Information Administration, Annual Energy Outlook 2011. Totals may not sum due to independent rounding.

2.5 Industry Costs

2.5.1 Finding Costs Real costs of drilling oil and natural gas wells ha ve increased significantly over the past two decades, particularly in recent years. Cost pe r well has increased by an annual average of about 15 percent, and cost per foot has increased o n average of about 13 percent per year (Figure 2-8).2-32

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

The average finding costs compiled and published by EIA add an additional level of detail to drilling costs, in that finding costs incorporate t he costs more broadly associated with adding proved reserves of crude oil and natural gas. Thes e costs include exploration and development costs, as well as costs associated with the purchas e or leasing of real property. EIA publishes finding costs as running three-year averages, in or der to better compare these costs, which occur over several years, with annual average lifting cos ts. Figure 2-9 shows average domestic onshore and offshore and foreign finding costs for the sample of U.S. firms in EIA’s Financial Reporting System (FRS) database from 1981 to 2008. The costs are reported in 2008 dollars on a barrel of oil equivalent basis for crude oil and natural gas combined. The average domestic finding costs dropped from 1981 until the mid-1990s . Interestingly, in the mid-1990s, domestic onshore and offshore and foreign finding costs conv erged for a few years. After this period, offshore finding costs rose faster than domestic on shore 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 2008Drilling Costs Per Well ($2005)

0 100 200 300 400 500 600 700 800Drilling Costs Per Foot ($2005)

Dollars per Well (2005 dollars) Dollars per Foot (2005 dollars)2-33

Figure 2-9 Finding Costs for FRS Companies, 1981-20 08

After 2000, average finding costs rose sharply, wit h the finding costs for domestic onshore and offshore and foreign proved reserves diverging onto different trajectories. Note the drilling costs in Figure 2-8 and finding costs in Figure 2-9 present similar trends overall.

2.5.2 Lifting Costs
Lifting costs are the costs to produce crude oil or natural gas once the resource has been found and accessed. EIA’s definition of lifting co sts includes costs of operating and maintaining wells and associated production equipment. Direct lifting costs exclude production taxes or royalties, while total lifting costs includes taxes and royalties. Like finding costs, EIA reports average lifting costs for FRS firms in 2008 dollars on a barrel of oil equivalent basis. Total lifting costs are the sum of direct lifting costs a nd production taxes. Figure 2-10 depicts direct lifting cost trends from 1981 to 2008 for domestic and foreign production. 0 10 20 30 40 50 60 70 80

1 9 8 1 - 1 9 8 3

1

9 8 6 - 1 9 8 8

1

9 9 1 - 1 9 9 3

1

9 9 6 - 1 9 9 8

2

0 0 1 - 2 0 0 3

2

0 0 6 - 2 0 0 8$2008/boe

U.S. Onshore U.S. Offshore Foreign2-34

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

Direct lifting costs (excludes taxes and royalties) for domestic production rose a little more than $2 per barrels of oil equivalent from 1981 to 1985, then declined almost $5 per barrel of oil equivalent from 1985 until 2000. From 2000 to 2008 , domestic lifting costs increased sharply, about $6 per barrel of oil equivalent. Foreign lif ting costs diverged from domestic lifting costs from 1981 to 1991, as foreign lifting costs were lo wer than domestic costs during this period. Foreign and domestic lifting costs followed a simil ar track until they again diverged in 2004, with domestic lifting again becoming more expensive . Combined with finding costs, the total finding and lifting costs rose significantly in fro m 2000 to 2008.

2.5.3 Operating and Equipment Costs The EIA report, “Oil and Gas Lease Equipment and Op erating Costs 1994 through 2009” 2 , contains indices and estimated costs for domestic oil and natural gas equipment and production operations. The indices and cost trends track costs for representative operations in

2 U.S. Energy Information Administration. “Oil and G as 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/cur rent/ coststudy.html > Accessed February 2, 2011. 0 2 4 6 8 10 12

1 9 8 1 1 9 8 4 1 9 8 7 1 9 9 0 1 9 9 3 1 9 9 6 1 9 9 9 2 0 0 2 2 0 0 5 2 0 0 8$2008/boe

Domestic Foreign2-35

six regions (California, Mid-Continent, South Louis iana, South Texas, West Texas, and Rocky Mountains) with producing depths ranging from 2000 to 16,000 feet and low to high production rates (for example, 50,000 to 1 million cubic feet per day for natural gas).
Figure 2-11 depicts crude oil operating costs and e quipment costs indices for 1976 to 2009, as well as the crude oil price in 1976 dollar s. The indices show that crude oil operating and equipment costs track the price of oil over thi s time period, while operating costs have risen more quickly than equipment costs. Operating and e quipment costs and oil prices rose steeply in the late 1970s, but generally decreased from about 1980 until the late 1990s.

Figure 2-11 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976 dollars), 1976-2009

Oil costs and prices again generally rose between 2 000 to present, with a peak in 2008. The 2009 index values for crude oil operating and equip ment costs are 154 and 107, respectively. 0 20 40 60 80 100 120 140 160 180 200

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

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

Crude Oil Operating Costs Crude Oil Equipment Cost Index Crude Oil Price ($/bbl, 1976 Dollars)2-36

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

Figure 2-12 depicts natural gas operating and equip ment costs indices, as well as natural gas prices. Similar to the cost trends for crude oil, natural gas operating and equipment costs track the price of natural gas over this time period, whi le operating costs have risen more quickly than equipment costs. Operating and equipment costs and gas prices also rose steeply in the late 1970s, but generally decreased from about 1980 unti l the mid 1990s. The 2009 index values for natural gas operating and equipment costs are 137 a nd 112, respectively.

2.6 Firm Characteristics A regulatory action to reduce pollutant discharges from facilities producing crude oil and natural gas will potentially affect the business en tities that own the regulated facilities. In the oi l and natural gas production industry, facilities com prise those sites where plant and equipment extract, process, and transport extracted streams r ecovered 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 dec isions that affect the facility.

2.6.1 Ownership Enterprises in the oil and natural gas industry may be divided into different groups that include producers, transporters, and distributors. The producer segment may be further divided between major and independent producers. Major pro ducers 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 2009Cost Index (1976=100)

0 1 1 2 2 3 3 4 4 5 5Natural Gas Price ($/MMcf, 1976 Dollars)

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

that are involved in each of the five industry segm ents: drilling and exploration, production, transportation, refining, and marketing. Independe nt producers include smaller firms that are involved in some but not all of the five activities

. According to the Independent Petroleum Association of America (IPAA), independent companies produce approximately 68 percent of domes tic crude oil production of our oil, 85 percent of domestic natural gas, and drill almost 9 0 percent of the wells in the U.S (IPAA, 2009). Through the mid-1980s, natural gas was a secondary fuel for many producers. However, now it is of primary importance to many producers. IPAA r eports that about 50 percent of its members’ spending in 2007 was directed toward natural gas pr oduction, largely toward production of unconventional gas (IPAA, 2009). Meanwhile, transp orters are comprised of the pipeline companies, while distributors are comprised of the local distribution companies.

2.6.2 Size Distribution of Firms in Affected
As of 2007, there were 6,563 firms within the 21111 1 and 211112 NAICS codes, of which 6427 (98 percent) were considered small busin esses (Table 2-16). Within NAICS 211111 and 211112, large firms compose about 2 percent of the firms, but account for 59 percent of employment and generate about 80 percent of estimat ed receipts listed under the NAICS.2-38

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

NAICS NAICS Description SBA Size Standard Small

Firms Large Firms Total Firms Number of Firms by Firm Size 211111 Crude Petroleum and Natural Gas Extraction 5 00 6,329 95 6,424 211112 Natural Gas Liquid Extraction 500 98 41 139 213111 Drilling Oil and Gas Wells 500 2,010 49 2,05 9 486210 Pipeline Transportation of Natural Gas $7.0 million 61* 65* 126
Total Employment by Firm Size 211111 Crude Petroleum and Natural Gas Extraction 5 00 55,622 77,664 133,286 211112 Natural Gas Liquid Extraction 500 1,875 6,64 8 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 5 00 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 mil lion in receipts, rather than the $7 million required by th e SBA Size Standard. We used this value because U. S. Census reports firm counts for firms with receipts less th an $7.5 million. **Employment and receipts could n ot be split between small and large businesses because of non-d isclosure requirements faced by the U.S. Census Bur eau. Source: U.S. Census Bureau. 2010. “Number of Firms, Number of Establishments, Employment, Annual Payro ll, and Estimated Receipts by Enterprise Receipt Size f or the United States, All Industries: 2007.” <http://www.census.gov/econ/susb/>

The small and large firms within NAICS 21311 are si milarly distributed, with large firms accounting for about 2 percent of firms, but 66 per cent and 69 percent of employment and estimated receipts, respectively. Because there ar e relatively few firms within NAICS 486210, the Census Bureau cannot release breakdowns of firm s by size in sufficient detail to perform similar calculation.2-39

2.6.3 Trends in National Employment and Wages As well as producing much of the U.S. energy supply , the oil and natural gas industry directly employs a significant number of people. T able 2-17 shows employment in oil and natural gas-related NAICS codes from 1990 to 2009. The overall trend shows a decline in total industry employment throughout the 1990s, hitting a low of 313,703 in 1999, but rebounding to a 2008 peak of 511,805. Crude Petroleum and Natural Gas Extraction (NAICS 211111) and Support Activities for Oil and Gas Operations (NAIC S 213112) employ the majority of workers in the industry.
Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-09

Year Crude

Petroleum and Natural Gas Extraction (211111) Natural Gas

Liquid Extraction (211112) Drilling of

Oil and Natural Gas Wells (213111) Support

Activities for Oil and Gas Ops. (213112) Pipeline

Trans. of Crude Oil (486110) Pipeline

Trans. of Natural Gas (486210) Total 1990 182,848 8,260 52,365 109,497 11,112 47,533 411 ,615 1991 177,803 8,443 46,466 116,170 11,822 48,643 409 ,347 1992 169,615 8,819 39,900 99,924 11,656 46,226 376, 140 1993 159,219 7,799 42,485 102,840 11,264 43,351 366 ,958 1994 150,598 7,373 44,014 105,304 10,342 41,931 359 ,562 1995 142,971 6,845 43,114 104,178 9,703 40,486 347, 297 1996 139,016 6,654 46,150 107,889 9,231 37,519 346, 459 1997 137,667 6,644 55,248 117,460 9,097 35,698 361, 814 1998 133,137 6,379 53,943 122,942 8,494 33,861 358, 756 1999 124,296 5,474 41,868 101,694 7,761 32,610 313, 703 2000 117,175 5,091 52,207 108,087 7,657 32,374 322, 591 2001 119,099 4,500 62,012 123,420 7,818 33,620 30,4 69 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 Natur al Gas Wells (NAICS 213111), and Total Oil and Natural Gas Wells Drilled, 1990-2009

Figure 2-13 compares employment in Drilling of Oil and Natural Gas Wells (NAICS 213111) with the total number of oil and natural ga s wells drilled from 1990 to 2009. The figure depicts a strong positive correlation between emplo yment in the sector with drilling activity. This correlation also holds throughout the period c overed by the data. 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000

Employment: Drilling of Oil and Natural Gas Wells ( NAICS

213111)2-41

Figure 2-14 Employment in Crude Petroleum and Natur al Gas Extraction (NAICS 211111) and Total Crude Oil and Natural Gas Product ion (boe), 1990-2009

Figure 2-14 compares employment in Crude Petroleum and Natural Gas Extraction (NAICS 211111) with total domestic oil and natural gas production from 1990 to 2009 in barrels of oil equivalent terms. While until 2003, employm ent in this sector and total production declined gradually, employment levels declined more rapidly. However, from 2004 to 2009 employment in Extraction recovered, rising to level s similar to the early 1990s.

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000

1990 1991 1992 1993 199 4 199 5 1996 199 7 1998 199 9 2000 2 001 2002 2 003 2004 2005 2 006 2007 2008 2009Employment

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000Total Oil and Gas Production (boe)

Employment: Crude Petroleum and Natural Gas Extract ion (NAICS 211111) Total Oil and Gas Production (boe)2-42

Figure 2-15 Employment in Natural Gas Liquid Extrac tion (NAICS 211112), Employment in Pipeline Transportation of Natural Ga s (NAICS 486210), and Total Natural Gas Production, 1990-2009

Figure 2-15 depicts employment in Natural Gas Liqu id Extraction (NAICS 211112), Employment in Pipeline Transportation of Natural Ga s (NAICS 486210), and Total Natural Gas Production, 1990-2009. While total natural gas pro duction has risen slightly over this time period, employment in natural gas pipeline transpor tation has steadily declined to almost half of its 1991 peak. Employment in natural gas liquid ex traction declined from 1992 to a low in 2005, then rebounded slightly from 2006 to 2009. Overall , however, these trends depict these sectors becoming decreasingly labor intensive, unlike the t rends depicted in Figure 2-13 and Figure 2-14.
From 1990 to 2009, average wages for the oil and n atural gas industry have increased. Table 2-18 and Figure 2-16 show real wages (in 2008 dollars) from 1990 to 2009 for the NAICS codes associated with the oil and natural gas indus try. 0 10,000 20,000 30,000 40,000 50,000 60,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2 0 00 2 0 01 2002 2003 2004 2005 2006 2007 2008 2009

Employment: Natural Gas Liquid Extraction (NAICS 21 1112) Employment: Pipeline Trans. of Natural Gas (NAICS 4 86210) Natural Gas Production (bcf)2-43

Table 2-18 Oil and Natural Gas Industry Average Wag es by NAICS, 1990-2009 (2008 dollars)

Year Crude

Petroleum and Natural Gas Extraction (211111) Natural

Gas Liquid Extraction (211112) Drilling

of Oil and Natural Gas Wells (213111) Support

Activities for Oil and Gas Operations (213112) Pipeline

Transportation of Crude Oil (486110) Pipeline

Transportation of Natural Gas (486210) Total 1990 71,143 66,751 42,215 45,862 68,044 61,568 59,4 60 1991 72,430 66,722 43,462 47,261 68,900 65,040 60,9 01 1992 76,406 68,846 43,510 48,912 74,233 67,120 64,2 26 1993 77,479 68,915 45,302 50,228 72,929 67,522 64,6 18 1994 79,176 70,875 44,577 50,158 76,136 68,516 64,9 41 1995 81,433 67,628 46,243 50,854 78,930 71,965 66,4 46 1996 84,211 68,896 48,872 52,824 76,841 76,378 68,3 91 1997 89,876 79,450 52,180 55,600 78,435 82,775 71,8 13 1998 93,227 89,948 53,051 57,578 79,089 84,176 73,7 22 1999 98,395 89,451 54,533 59,814 82,564 94,471 79,0 78 2000 109,744 112,091 60,862 60,594 81,097 130,630 8 6,818 2001 111,101 111,192 61,833 61,362 83,374 122,386 8 5,333 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 9 6,216 2008 144,542 125,126 81,961 74,021 101,772 99,215 9 9,106 2009 133,575 123,922 80,902 70,277 100,063 100,449 96,298 Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2011 , <http://www.bls.gov/cew/>
Employees in the NAICS 211 codes enjoy the highest average wages in the industry, while employees in the NAICS 213111 code have relatively lower wages. Average wages in natural gas pipeline transportation show the highest variat ion, with a rapid climb from 1990 to 2000, more than doubling in real terms. However, since 2 000 wages have declined in the pipeline transportation sector, while wages have risen in th e other NAICS.2-44

Figure 2-16 Oil and Natural Gas Industry Average W ages by NAICS, 1990-2009 ($2008)

2.6.4 Horizontal and Vertical Integration

Because of the existence of major companies, the in dustry possesses a wide dispersion of vertical and horizontal integration. The vertical aspects of a firm’s size reflect the extent to which goods and services that can be bought from ou tside are produced in house, while the horizontal aspect of a firm’s size refers to the sc ale of production in a single-product firm or its scope in a multiproduct one. Vertical integration is a potentially important dimension in analyzing firm-level impacts because the regulation could affect a vertically integrated firm on more than one level. The regulation may affect com panies for whom oil and natural gas production is only one of several processes in whic h the firm is involved. For example, a company that owns oil and natural gas production fa cilities may ultimately produce final petroleum products, such as motor gasoline, jet fue l, or kerosene. This firm would be considered vertically integrated because it is involved in mor e than one level of requiring crude oil and natural gas and finished petroleum products. A reg ulation that increases the cost of oil and natural gas production will ultimately affect the c ost of producing final petroleum products.

Horizontal integration is also a potentially import ant dimension in firm-level analyses for any of the following reasons. A horizontally integ rated firm may own many facilities of which

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2 004 2005 2006 2007 2 008 2009Average Wage (2008 dollars)

Crude Petroleum and Natural Gas Extraction (211111) Natural Gas Liquid Extraction (211112) Drilling of Oil and Natural Gas Wells (213111) Support Activities for Oil and Gas Ops. (213112) Pipeline Trans. of Crude Oil (486110) Pipeline Trans. of Natural Gas (486210) Total2-45

only some are directly affected by the regulation. Additionally, a horizontally integrated firm may own facilities in unaffected industries. This type of diversification would help mitigate the financial impacts of the regulation. A horizontall y integrated firm could also be indirectly as well as directly affected by the regulation.

In addition to the vertical and horizontal integrat ion that exists among the large firms in the industry, many major producers often diversify within the energy industry and produce a wide array of products unrelated to oil and gas pro duction. As a result, some of the effects of regulation of oil and gas production can be mitigat ed if demand for other energy sources moves inversely compared to petroleum product demand.

In the natural gas sector of the industry, vertical integration is less predominant than in
the oil sector. Transmission and local distributio n 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. Howe ver, natural gas wells are not exclusive to natural gas firms only. Typically wells produce bot h oil and gas and can be owned by a natural gas firm or an oil company.

Unlike the large integrated firms that have several profit centers such as refining, marketing, and transportation, most independents ha ve to rely only on profits generated at the wellhead from the sale of oil and natural gas or th e provision of oil and gas production-related engineering or financial services. Overall, indepe ndent producers typically sell their output to refineries or natural gas pipeline companies and ar e not vertically integrated. Independents may also own relatively few facilities, indicating limi ted horizontal integration.

2.6.5 Firm-level Information

The annual Oil and Gas Journal (OGJ) survey, the OGJ150, reports financial and operating results for top 150 public oil and natura l gas companies with domestic reserves and headquarters in the U.S. In the past, the survey r eported information on the top 300 companies, now the top 150. In 2010, only 137 companies are l isted 3 . Table 2-19 lists selected statistics for

3 Oil and Gas Journal. “OGJ150 Financial Results Dow n in '09; Production, Reserves Up.” September 6, 20 10.2-46

the top 20 companies in 2010. The results presented in the table reflect relatively lower production and financial figures as a result of the economic recession of this period.

Total earnings for the top 137 companies fell from 2008 to 2009 from $71 billion to $27 billion, reflecting the weak economy. Revenues for these companies also fell 35 percent during this period. 69 percent of the firms posted net lo sses 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 i ncreased about 3 percent to a total of 16.5 tcf ( Oil and Gas Journal , September 6, 2010). Meanwhile, the 137 firms on the OGJ list increased both oil and natural gas production and reserves fr om 2008 to 2009. Domestic production of liquids increased about 7 percent to 1.1 billion bb l, and natural gas production increased to 10.1 tcf. For context, the OGJ150 domestic crude produc tion represents about 57 percent of total domestic production (1.9 billion bbl, according to EIA). The OGJ150 natural gas production represents about 54 percent of total domestic produ ction (18.8 tcf, according to EIA).

The OGJ also releases a period report entitled “Wor ldwide Gas Processing Survey”, which provides a wide range of information on exist ing processing facilities. We used a recent list of U.S. gas processing facilities ( Oil and Gas Journal , June 7, 2010) and other resources, such as the American Business Directory and company websites, to best identify the parent company of the facilities. As of 2009, there are 5 79 gas processing facilities in the U.S., with a processing capacity of 73,767 million cubic feet pe r 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 als o showing a degree of concentration, as large firms own multiple facilities, which also tend to be relatively large facilities (Table 2-20). While we estimate 142 companies own the 5 79 facilities, the top 20 companies (in terms of total throughput) own 264 or 46 percent of the f acilities. That larger companies tend to own larger facilities is indicated by these top 20 firm s owning 86 percent of the total capacity and 88 percent of actual throughput.2-47Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2010WorldwideProduction U.S. ProductionRank byTotalAssets Company EmployeesTotal Assets($ millions)TotalRev. ($millions)Net Inc.($millions)Liquids(Millionbbl)NaturalGas(Bcf)Liquids(Millionbbl)NaturalGas(Bcf)NetWellsDrilled1ExxonMobil Corp.102,700 233,323 310,586 19,280 725 2,383 112 5664662Chevron Corp.64,000 164,621 171,636 10,563 674 1,821 177 511 5943ConocoPhillips30,000 152,588 152,840 4,858 341 1,906 153 850 6924Anadarko Petroleum Corp.4,300 50,123 9,000 -103 88 817 63 817 6305Marathon Oil Corp.28,855 47,052 54,139 1,463 90 351 23 146 1156Occidental Petroleum Corp.10,100 44,229 15,531 2,915 179 338 99 232 2607XTO Energy Inc.3,129 36,255 9,064 2,019 32 855 32 855 1,0598Chesapeake Energy Corp.8,200 29,914 7,702 -5,805 12 835 12 835 1,0039Devon Energy Corp.5,400 29,686 8,015 -2,479 72 966 43 743 52110Hess Corp.13,300 29,465 29,569 740 107 270 26 39 4811Apache Corp.3,452 28,186 8,615 -284 106 642 35 243 12412El Paso Corp.4,991 22,505 4,631 -539 6 219 6 215 13413EOG Resources Inc.2,100 18,119 14,787 547 29 617 26 422 65214Murphy Oil Corp.8,369 12,756 18,918 838 48 68 6 20 315Noble Energy Inc.1,630 11,807 2,313 -131 29 285 17 145 54016Williams Cos. Inc.4,801 9,682 2,219 400 0 3,435 0 3,435 48817Questar Corp.2,468 8,898 3,054 393 4 169 4 169 19418Pioneer Nat. Resources Co.1,888 8,867 1,712 -52 19 157 17 148 6719Plains Expl. & Prod. Co.808 7,735 1,187 136 18 78 18 78 5320Petrohawk Energy Corp.469 6,662 41,084 -1,025 2 174 2 174 162Source: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 (Bas ed on Throughput), 2009

Rank Company Processing Plants (No.) Natural Gas

Capacity (MMcf/day) Natural Gas

Throughput (MMcf/day) 1 BP PLC 19 13,378 11,420 2 DCP Midstream Inc. 64 9,292 5,586 3 Enterprise Products Operating LP— 23 10,883 5,347 4 Targa Resources 16 4,501 2,565 5 Enbridge Energy Partners LP— 19 3,646 2,444 6 Williams Cos. 10 4,826 2,347 7 Martin Midstream Partners 16 3,384 2,092 8 Chevron Corp. 23 1,492 1,041 9 Devon Gas Services LP 6 1,038 846 10 ExxonMobil Corp. 6 1,238 766 11 Occidental Petroleum Corp 7 776 750 12 Kinder Morgan Energy Partners 9 1,318 743 13 Enogex Products Corp. 8 863 666 14 Hess Corp. 3 1,060 613 15 Norcen Explorer 1 600 500 16 Copano Energy 1 700 495 17 Anadarko 18 816 489 18 Oneok Field Services 10 1,751 472 19 Shell 4 801 446 20 DTE Energy 1 800 400 TOTAL FOR TOP 20 264 63,163 40,028 TOTAL FOR ALL COMPANIES 579 73,767 45,472 Source: Oil and Gas Journal . “Special Report: Worldwide Gas Processing: New Pl ants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010, w ith additional analysis to determine ultimate owner ship of plants.

The OGJ also issues a periodic report on the econom ics of the U.S. pipeline industry. This report examines the economic status of all maj or and non-major natural gas pipeline companies, which amounts to 136 companies in 2010 ( Oil and Gas Journal , November 1, 2010). Table 2-21 presents the pipeline mileage, volumes o f natural gas transported, operating revenue, and net income for the top 20 U.S. natural gas pipe line companies in 2009. Ownership of gas pipelines is mostly independent from ownership of o il and gas production companies, as is seen from the lack of overlap between the OGJ list of pi peline companies and the OGJ150. This observation shows that the pipeline industry is sti ll largely based upon firms serving regional
market.

The top 20 companies maintain about 63 percent of t he total pipeline mileage and transport about 54 percent of the volume of the ind ustry (Table 2-21). Operating revenues of the2-49

top 20 companies equaled $11.5 billion, representin g 60 percent of the total operating revenues for major and non-major companies. The top 20 comp anies also account for 64 percent of the net income of the industry.

Table 2-21 Performance of Top 20 Gas Pipeline Compa nies (Based on Net Income), 2009

Rank Company Transmission (miles) Vol. trans

for others (MMcf) Op. Rev.

(thousand $) Net

Income 1 Natural Gas Pipeline Co of America 9,312 1,966,77 4 1,131,548 348,177 2 Dominion Transmission Inc. 3,452 609,193 831,7 73 212,365 3 Columbia Gas Transmission LLC 9,794 1,249,188 7 96,437 200,447 4 Panhandle Eastern Pipe Line Co. LP 5,894 675,616 377,563 196,825 5 Transcontinental Gas Pipe Line Co. LLC 9,362 2,45 3,295 1,158,665 192,830 6 Texas Eastern Transmission LP 9,314 1,667,593 8 70,812 179,781 7 Northern Natural Gas Co. 15,028 922,745 690,863 171,427 8 Florida Gas Transmission Co. LLC 4,852 821,297 52 0,641 164,792 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 37 1,951 103,430 17 Trunkline LNG Co. LLC — — 134,150 101,920 18 Northwest Pipeline GP 3,895 817,832 434,379 99,3 40 19 Texas Gas Transmission LLC 5,881 1,006,906 361 ,406 91,575 20 Algonquin Gas Transmission LLC 1,128 388,366 237 ,291 82,472 TOTAL FOR TOP 20 124,903 21,097,914 11,510,401 3,0 21,774 TOTAL FOR ALL COMPANIES 198,381 38,793,532 18,934 ,674 4,724,456
Source: Oil and Gas Journal . “Natural Gas Pipelines Continue Growth Despite Lo wer Earnings; Oil Profits Grow.” November 1, 2010.

2.6.6 Financial Performance and Condition From a broad industry perspective, the EIA Financia l Reporting System (FRS) collects financial and operating information from a subset o f the U.S. major energy producing companies. This information is used in annual repo rt to Congress, as well as is released to the public in aggregate form. While the companies that report information to FRS each year changes, EIA makes an effort to retain sufficient c onsistency such that trends can be evaluated.2-50

For 2008, there are 27 companies in the FRS 4 that accounted for 41 percent of total U.S. crude oil and NGL production, 43 percent of natural gas p roduction, 77 percent of U.S. refining capacity, and 0.2 percent of U.S. electricity net g eneration (U.S. EIA, 2010). Table 2-22 shows a
series of financial trends in 2008 dollars selected and aggregated from FRS firms’ financial statements. The table shows operating revenues and expenses rising significantly from 1990 to 2008, with operating income (the difference between operating revenues and expenses) rising as well. Interest expenses remained relatively flat d uring this period. Meanwhile, recent years have shown that other income and income taxes have playe d a more significant role for the industry. Net income has risen as well, although 2008 saw a d ecline from previous periods, as oil and natural gas prices declined significantly during th e latter half of 2008.

Table 2-22 Selected Financial Items from Income Sta tements (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 in cludes other revenue and expense (excluding interest expen se), discontinued operations, extraordinary items, and accounting changes. Totals may not sum due to inde pendent rounding.

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

Table 2-23 shows in percentage terms the estimated return on investments for a variety of business lines, in 1998, 2003, and 2008, for FRS co mpanies. 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 pipelin es, sustaining a return on investment greater than 10 percent for the three years evaluated. Ret urns to foreign oil and natural gas production rose above domestic production in 2008. Electric p ower generation and sales emerged in 2008 as a highly profitable line of business for the FRS companies.

Table 2-23 Return on Investment for Lines of Business (all FRS ), for 1998, 2003, and 2008 (percent) Line of Business 1998 2003 2008
Petroleum 10.8 13.4 12.0 U.S. Petroleum 10 13.7 8.2 Oil and Natural Gas Production 12.5 16.5 10. 7 Refining/Marketing 6.6 9.3 2.6 Pipelines 6.7 11.5 2.4 Foreign Petroleum 11.9 13.0 17.8 Oil and Natural Gas Production 12.5 14.2 16. 3 Refining/Marketing 10.6 8.0 26.3 Downstream Natural Gas* - 8.8 5.1 Electric Power* - 5.2 181.4 Other Energy 7.1 2.8 -2.1 Non-energy 10.9 2.4 -5.3 Source: Energy Information Administration, Form EIA -28 (Financial Reporting System). Note: Return on investment measured as contribution to net income/n et investment in place. * The downstream natural g as and electric power lines of business were added to the EIA-28 survey form beginning with the 2003 reportin g year.

The oil and natural gas industry also produces sig nificant tax revenues for local, state,
and federal authorities. Table 2-24 shows income a nd production tax trends from 1990 to 2008 for FRS companies. The column with U.S. federal, s tate, and local taxes paid or accrued
includes deductions for the U.S. Federal Investment Tax Credit ($198 million in 2008) and the effect of the Alternative Minimum Tax ($34 million in 2008). Income taxes paid to state and local authorizes were $3,060 million in 2008, about 13 percent of the total paid to U.S.
authorities.2-52

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

Year U.S. Federal, State,

and Local Taxes Paid or Accrued Total Current Total Deferred Total Income Tax Expense Other NonIncome Production Taxes Paid 1990 9,568 25,056 -230 24,826 4,341 1991 6,672 18,437 -3,027 15,410 3,467 1992 4,994 16,345 -4,116 12,229 3,097 1993 3,901 13,983 -1,302 12,681 2,910 1994 3,348 13,556 887 14,443 2,513 1995 6,817 17,474 -510 16,965 2,476 1996 8,376 22,493 3,626 26,119 2,922 1997 7,643 20,764 3,141 23,904 2,743 1998 1,199 7,375 -1,401 5,974 1,552 1999 2,626 13,410 140 13,550 2,147 2000 14,308 36,187 6,674 42,861 3,254 2001 10,773 28,745 4,351 33,097 3,042 2002 814 17,108 46 17,154 2,617 2003 9,274 30,349 6,879 37,228 3,636 2004 19,661 50,185 4,024 54,209 3,990 2005 29,993 72,595 4,529 77,125 5,331 2006 29,469 85,607 9,226 94,834 5,932 2007 28,332 84,119 2,188 86,306 7,501 2008 23,199 95,590 2,866 98,456 12,507 Source: Energy Information Administration, Form EIA -28 (Financial Reporting System).

The difference between total current taxes and U.S . federal, state, and local taxes in includes taxes and royalties paid to foreign countr ies. As can be seen in Table 2-24, foreign taxes paid far exceeds domestic taxes paid. Other non-income production taxes paid, which have risen almost three-fold between 1990 and 2008, incl ude windfall profit and severance taxes, as well as other production-related taxes.2-53

2.7 References

Andrews, et al. 2009. Unconventional Gas Shales: De velopment, Technology, and Policy Issues. Congressional Research Service. R40894.
Argonne National Laboratory. 2009. Produced Water Volumes and Management Practices in the United States. ANL/EVS/R-09/1.
Hyne, N.J. 2001. Nontechnical Guide to Petroleum Geology, Exploratio n, Drilling and Production. Tulsa, OK: Penwell Books.

Independent Petroleum Association of America. 2009. Profile of Independent Producers. <http://www.ipaa.org/news/docs/IPAAProfile2009.pdf> Accessed March 30, 2011.

Manning, F.S. and R.E. Thompson. 1991. Oil Field Processing of Petroleum – Volume 3: Produced and Injection Waters . Tulsa, OK: Penn Well Books.

Oil and Gas Journal . “Natural Gas Pipelines Continue Growth Despite Lo wer 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 Pl ants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010.

U.S. Energy Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial Link between Natural Gas Production and Its Transpo rtation to Market. <http://www.eia.doe.gov/pub/oil_gas/natural_gas/fea ture_articles/2006/ngprocess/ngproc ess.pdf> Accessed February 2, 2011.
U.S. Department of Energy. 2009. Modern Shale Gas D evelopment in the United States: APrimer. <http://www.netl.doe.gov/technologies/oilgas/publications/EPreports/Shale_Gas_Primer_2009.pd f> 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_pu blications/cost_indices_equipment_ production/current/coststudy.html> Accessed March 30, 2011.2-54

U.S. Energy Information Administration (U.S. EIA). 2010. Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves 2009. <http://www.eia.doe.gov/oil_gas/natural_gas/data_pu blications/crude_oil_natural_gas_re serves/cr.html> Accessed March 30, 2011.

U.S. Energy Information Administration (U.S. EIA). 2010. Performance Profiles of Major Energy Producers 2008. <http://www.eia.gov/finance/ performanceprofiles> Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2011. Annual Energy Outlook 2011. <http://www.eia.gov/forecasts/aeo> June 2, 2011.

U.S. Environmental Protection Agency (U.S. EPA), Of fice of Air Quality Planning and Standards. 1996. Economic Analysis of Air Pollution Regulations: Oil and Natural Gas Production

. <http://www.epa.gov/ttnecas1/regdata/IPs/Oil%20and% 20NG%20Production%20and%2 0NG%20Transmission_IP.pdf> Accessed March 30, 2011

. U.S. Environmental Protection Agency (U.S. EPA). 20 04. Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed M ethane Reservoirs. EPA/816-R-04- 003.

U.S. Environmental Protection Agency. 2000. EPA Off ice of Compliance Sector Notebook Project: Profile of the Oil and Gas Extraction Indu stry. EPA/310-R-99-006. <http://www.epa.gov/compliance/resources/publicatio ns/assistance/sectors/notebooks/oil. html> Accessed March 30, 2011.3-1 3 EMISSIONS AND ENGINEERING COSTS

3.1 Introduction

This section includes three sets of discussions for both the proposed NSPS and NESHAP amendments:

• Emission Sources and Points

• Emissions Control Options

• Engineering Cost Analysis

3.2 Emissions Points, Controls, and Engineering Costs A nalysis This section discusses the emissions points and po llution control options for the proposed NSPS and NESHAP amendments. This discussion of emi ssions points and control options is meant to assist the reader of the RIA in better und erstanding the economic impact analysis. However, we provide reference to the detailed techn ical memoranda prepared by the Office of Air Quality Planning and Standards (OAQPS) for the reader interested in a greater level of detail. This section also presents the engineering cost ana lysis, which provides a cost basis for the energy system, welfare, employment, and small busin ess analyses.
Before going into detail on emissions points and po llution controls, it is useful to provide
estimates of overall emissions from the crude oil a nd natural industry to provide context for estimated reductions as a result of the regulatory options evaluated. To estimate VOC emissions from the oil and gas sector, we modified the emissi ons estimate for the crude oil and natural gas sector in the 2008 National Emissions Inventory (NE I). During this review, EPA identified VOC emissions from natural gas sources which are likely relatively under-represented in the NEI, natural gas well completions primarily. Crude oil and natural gas sector VOC emissions estimated in the 2008 NEI total approximately 1.76 million tons. Of these emissions, the NEI
identifies about 21 thousand tons emitted from natu ral gas well completion processes. We
substituted the estimates of VOC emissions from nat ural gas well completions estimated as part of the engineering analysis (510,000 tons, which is discussed in more detail in the next section), bringing the total estimated VOC emissions from the crude oil and natural gas sector to about
2.24 million tons VOC.3-2

The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009 (published April 2011) estimates 2009 methane emissions from Petrole um and Natural Gas Systems (not including petroleum refineries and petroleum transp ortation) to be 251.55 (MMtCO 2 -e). It is important to note that the 2009 emissions estimates from well completions and recompletions exclude a significant number of wells completed in tight sand plays and the Marcellus Shale, due to availability of data when the 2009 Inventory was developed. The estimate in this proposal includes an adjustment for tight sand plays and the Marcellus Shale, and such an adjustment is also being considered as a planned improvement in n ext year's Inventory. This adjustment would increase the 2009 Inventory estimate by about 80 MM tCO 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 pa rt of the NSPS review. This section provides a basic description of possible emissions sources a nd the controls evaluated for each source to facilitate the reader’s understanding of the econom ic impact and benefit analyses. The reader
who is interested in more technical detail on the e ngineering and cost basis of the analysis is referred to the relevant chapters within the Techni cal Support Document (TSD) which is published in the Docket. The chapters are also ref erenced below. EPA is soliciting public
comment and data relevant to several emissions-rela ted issues related to the proposed NSPS. The comments we receive during the public comment p eriod will help inform the rule development process as we work toward promulgating a final action.

Centrifugal and reciprocating compressors (TSD Chapter 6) : There are many locations throughout the oil and gas sector where compression of natural gas is required to move the gas along the pipeline. This is accomplished by compre ssors powered by combustion turbines, reciprocating internal combustion engines, or elect ric motors. Turbine-powered compressors use a small portion of the natural gas that they compre ss to fuel the turbine. The turbine operates a centrifugal compressor, which compresses and pumps the natural gas through the pipeline.
Sometimes an electric motor is used to turn a centr ifugal compressor. This type of compression does not require the use of any of the natural gas from the pipeline, but it does require a source of electricity. Reciprocating spark ignition engines are also used to power many compressors,3-3

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

Both centrifugal and reciprocating compressors are sources of VOC emissions, and EPA evaluated compressors for coverage under the NSPS. Centrifugal compressors require seals around the rotating shaft to prevent gases from esc aping where the shaft exits the compressor casing. The seals in some compressors use oil, whic h 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, bu t considerable gas is absorbed by the oil. Seal oil is purged of the absorbed gas (using heaters, f lash tanks, and degassing techniques) and recirculated, and the gas is commonly vented to the atmosphere. These are commonly called “wet” seals. An alternative to a wet seal system i s the mechanical dry seal system. This seal system does not use any circulating seal oil. Dry seals operate mechanically under the opposing force created by hydrodynamic grooves and static pr essure. Fugitive VOC is emitted from dry seals around the compressor shaft. The use of dry gas seals substantially reduces emissions. In addition, they significantly reduce operating costs and enhance compressor efficiency.

Reciprocating compressors in the natural gas indust ry leak natural gas during normal operation. The highest volume of gas loss is assoc iated with piston rod packing systems. Packing systems are used to maintain a tight seal a round the piston rod, preventing the gas compressed to high pressure in the compressor cylin der from leaking, while allowing the rod to move freely. Monitoring and replacing compressor r od packing systems on a regular basis can greatly reduce VOC emissions.

Equipment leaks (TSD Chapter 8) : Equipment leaks are fugitive emissions emanating f rom valves, pump seals, flanges, compressor seals, pres sure relief valves, open-ended lines, and other process and operation components. There are sever al potential reasons for equipment leak emissions. Components such as pumps, valves, press ure relief valves, flanges, agitators, and compressors are potential sources that can leak due to seal failure. Other sources, such as openended lines, and sampling connections may leak for reasons other than faulty seals. In addition, corrosion of welded connections, flanges, and valve s may also be a cause of equipment leak emissions. Because of the large number of valves, pumps, and other components within an oil3-4

and gas production, processing, and transmission fa cility, equipment leaks of volatile emissions from these components can be significant. Natural gas processing plants, especially those using refrigerated absorption, and transmission stations tend to have a large number of components. These types of equipment also exist at production s ites and gas transmission/compressor stations. While the number of components at individual transm ission/compressor stations is relatively smaller than at processing plants, collectively the re are many components that can result in significant emissions. Therefore, EPA evaluated NS PS for equipment leaks for facilities in the production segment of the industry, which includes everything from the wellhead to the point that the gas enters the processing plant or refiner y.

Pneumatic controllers (TSD Chapter 5): Pneumatic controllers are automat ed instruments used for maintaining a process condition such as liquid level, pressure, delta-pressure, and temperature. Pneumatic controllers are widely used in the oil and natural gas sector. In many situations, the pneumatic controllers used in the o il 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” pneum atic 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 inclu de solar, electric, and instrument air. At oil and gas locations with electrical service, non gas- driven controllers are typically used. Gasdriven pneumatic controllers are typically characte rized as “high-bleed” or “low-bleed”, where a high-bleed device releases at least 6 cubic feet of gas per hour. EPA evaluated the impact of requiring low-bleed controllers.

Storage vessels (TSD Chapter 7): Crude oil, condensate, and produ ced water are typically stored in fixed-roof storage vessels. Some vessels used for storing produced water may be opentop tanks. These vessels, which are operated at or near atmospheric pressure conditions, are typically located at tank batteries. A tank batter y refers to the collection of process equipment used to separate, treat, and store crude oil, conde nsate, natural gas, and produced water. The extracted products from productions wells enter the tank battery through the production header, which may collect product from many wells. Emissio ns from storage vessels are a result of3-5

working, breathing, and flash losses. Working loss es occur due to the emptying and filling of storage tanks. Breathing losses are the release of gas associated with daily temperature fluctuations and other equilibrium effects. Flash losses occur when a liquid with entrained gases is transferred from a vessel with higher pressure t o a vessel with lower pressure, thus allowing entrained gases or a portion of the liquid to vapor ize or flash. In the oil and natural gas production segment, flashing losses occur when live crude oils or condensates flow into a storage tank from a processing vessel operated at a higher pressure. Typically, the larger the pressure drop, the more flashing emission will occur in the storage stage. The two ways of controlling tanks with significant emissions would be to instal l a vapor recovery unit (VRU) and recover all the vapors from the tanks or to route the emissions from the tanks to a control device.

Well completions (TSD Chapter 4): In the oil and natural gas sector , well completions contain multi-phase processes with various sources of emiss ions. 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 s pecific 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 im proving gas production where the reservoir rock is fractured with very high pressure fluid, typically water emulsion with proppant (generally sand) that “props open” the fractures af ter fluid pressure is reduced. Emissions are a
result of the backflow of the fracture fluids and r eservoir gas at high velocity necessary to lift excess proppant to the surface. This multi-phase m ixture is often directed to a surface impoundment where natural gas and VOC vapors escape to the atmosphere during the collection of water, sand, and hydrocarbon liquids. As the fr acture fluids are depleted, the backflow eventually contains more volume of natural gas from the formation. Thus, we estimate completions involving hydraulic fracturing vent sub stantially more natural gas, approximately 230 times more, than completions not involving hydr aulic fracturing. Specifically, we estimate3-6

that uncontrolled well completion emissions for a h ydraulically fractured well are about 23 tons of VOC, where emissions for a conventional gas well completion are around 0.1 ton VOC. Our data indicate that hydraulically fractured wells ha ve higher emissions but we believe some wells that are not hydraulically fractured may have highe r emissions than our data show, or in some cases, hydraulically fractured wells could have low er emissions that our data show.

Reduced emission completions, which are sometimes referred to as “green completions” or “flareless completions,” use equipment at the we ll site to capture and treat gas so it can be
directed into the sales line and avoid emissions fr om venting. Equipment required to conduct a reduced emissions completion may include tankage, s pecial gas-liquid-sand separator traps, and gas dehydration. Equipment costs associated with r educed emission completions will vary from well to well. Based on information provided to the EPA Natural Gas STAR program, 90 percent of gas potentially vented during a completion can b e recovered during a reduced emission completion.

3.2.1.2 NESHAP Emission Points and Pollution Controls

A series of emissions controls will be required und er the proposed NESHAP Amendments. This section provides a basic descript ion of potential sources of emissions and the
controls intended for each to facilitate the reader ’s understanding of the economic impacts and subsequent benefits analysis section. The reader w ho is interested in more technical detail on the engineering and cost basis of the analysis is refer red to the relevant technical memos which are published in the Docket. The memos are also refere nced below.

Glycol dehydrators 5 : Once natural gas has been separated from any liq uid materials or products (e.g., crude oil, condensate, or produced water), r esidual entrained water is removed from the natural gas by dehydration. Dehydration is necessa ry because water vapor may form hydrates, which are ice-like structures, and can cause corros ion in or plug equipment lines. The most widely used natural gas dehydration processes are g lycol dehydration and solid desiccant

5 Memorandum. Brown, Heather, EC/R Incorporated, to Bruce Moore and Greg Nizich, EPA/OAQPS/SPPD/FIG. Oil and Natural Gas Production MACT and Natural Gas Transmission and Storage MACT - Glycol Dehydrators : Impacts of MACT Review Options. July 17,2011.3-7

dehydration. Solid desiccant dehydration, which is typically only used for lower throughputs, uses adsorption to remove water and is not a source of HAP emissions. Glycol dehydration is an absorption process in which a liquid absorbent, gly col, directly contacts the natural gas stream and absorbs any entrained water vapor in a contact tower or absorption column. The rich glycol, which has absorbed water vapor from the natural gas stream, leaves the bottom of the absorption column and is directed either to (1) a gas condensa te glycol separator (GCG separator or flash tank) and then a reboiler or (2) directly to a rebo iler where the water is boiled off of the rich glycol. The regenerated glycol (lean glycol) is ci rculated, by pump, into the absorption tower. The vapor generated in the reboiler is directed to the reboiler vent. The reboiler vent is a source of HAP emissions. In the glycol contact tower, gly col not only absorbs water but also absorbs selected hydrocarbons, including BTEX and n-hexane. The hydrocarbons are boiled off along
with the water in the reboiler and vented to the at mosphere or to a control device.

The most commonly used control device is a condense r. Condensers not only reduce emissions, but also recover condensable hydrocarbon vapors that can be recovered and sold. In addition, the dry non-condensable off-gas from the condenser may be used as fuel or recycled into the production process or directed to a flare, incinerator, or other combustion device.

If present, the GCG separator (flash tank) is also a potential source of HAP emissions. Some glycol dehydration units use flash tanks prior to the reboiler to separate entrained gases, primarily methane and ethane from the glycol. The flash tank off-gases are typically recovered as fuel or recycled to the natural gas production h eader. However, the flash tank may also be vented directly to the atmosphere. Flash tanks typ ically enhance the reboiler condenser’s emission reduction efficiency by reducing the conce ntration of non-condensable gases present in the stream prior to being introduced into the conde nser.

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

3.2.2 Engineering Cost Analysis In this section, we provide an overview of the engi neering cost analysis used to estimate the additional private expenditures industry may ma ke in order to comply with the proposed3-8

NSPS and NESHAP amendments. A detailed discussion of the methodology used to estimate cost impacts is presented in series of memos publis hed in the Docket as part of the TSD.

3.2.2.1 NSPS Sources
Table 3-1 shows the emissions sources, points, and controls analyzed in three NSPS regulatory options, which we term Option 1, Option 2, and Option 3. Option 2 was selected for proposal. The proposed Option 2 contains reduced e mission completion (REC) and completion combustion requirements for a subset of newly drill ed natural gas wells that are hydraulically fractured. Option 2 also requires a subset of well s that are worked over, or recompleted, using hydraulic fracturing to implement RECs. The propos ed Option 2 requires emissions reductions from reciprocating compressors at gathering and boo sting stations, processing plants, transmission compressor stations, and underground s torage facilities. The proposed Option 2 also requires emissions reductions from centrifugal compressors, processing plants, and transmission compressor stations. Finally, the pro posed Option 2 requires emissions reductions from pneumatic controllers at oil and gas productio n facilities and natural gas transmission and storage and reductions from high throughput storage vessels.3-9

Table 3-1 Emissions Sources, Points, and Controls I ncluded in NSPS Options Emissions Sources and Points Emissions Control Opti on 1 Option 2 (proposed) Option 3 Well Completions of Post-NSPS Wells Hydraulically Fractured Gas Wells that Meet Criteria for Reduced Emissions Completion (REC) REC X X X
Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC Combustion X X X

Conventional Gas Wells Combustion Oil Wells Combustion Well RecompletionsHydraulically Fractured Gas Wells (postNSPS wells) REC X X XHydraulically Fractured Gas Wells (preNSPS wells) REC X X

Conventional Gas Wells Combustion Oil Wells Combustion Equipment Leaks Well Pads NSPS Subpart VV X Gathering and Boosting Stations NSPS Subpart VV X Processing Plants NSPS Subpart VVa X X Transmission Compressor Stations NSPS Subpart VV X Reciprocating Compressors
Well Pads Annual Monitoring/ Maintenance (AMM) Gathering/Boosting Stations AMM X X X Processing Plants AMM X X X Transmission Compressor Stations AMM X X X Underground Storage Facilities AMM X X X Centrifugal Compressors Processing Plants Dry Seals/Route to Process or Control X X X
Transmission Compressor Stations Dry Seals/Route to Process or Control X X X
Pneumatic Controllers - Oil and Gas Production Low Bleed/Route to Process X X X Natural Gas Transmission and Storage Low Bleed/Ro ute to Process X X X Storage Vessels High Throughput 95% control X X X Low Throughput 95% control3-10

The distinction between Option 1 and the proposed O ption 2 is the inclusion of completion combustion and REC requirements for reco mpletions at existing wells and an equipment leak standard for natural gas processing plants in Option 2. Option 2 requires the implementation of completion combustion and REC for existing wells as well as wells completed after the implementation date of the prop osed NSPS. Option 1 applies the requirement only to new wells, not existing wells. The main distinction between proposed Option 2 and Option 3 is the inclusion of a suite o f equipment leak standards. These equipment leak standards would apply at well pads, gathering and boosting stations, and transmission compressor stations. Option 1 differs from Option 3 in that it does not include the combustion and REC requirements at existing wells or the full suite of equipment leak standards.

Table 3-2 summarizes the unit level capital and ann ualized costs for the evaluated NSPS emissions sources and points. The detailed descrip tion of costs estimates is provided in the
series of technical memos included in the TSD in th e document, as referenced in Section 3.2.1 of this RIA. The table also includes the projected nu mber of affected units. Four issues are important to note on Table 3-2: the approach to ann ualizing costs, the projection of affected units in the baseline; that capital and annualized costs are equated for RECs; and additional natural gas and hydrocarbon condensates that would otherwise be emitted to the environment are recovered from several control options evaluated in the NSPS review.

First, engineering capital costs were annualized us ing a 7 percent interest rate. However, different emissions control options were annualized using expected lifetimes that were determined to be most appropriate for individual op tions. For control options evaluated for the NSPS, the following lifetimes were used:

• Reduced emissions completions and combustion device s: 1 year (more discussion of the selection of a one-year lifetime follows in this se ction momentarily)

• Reciprocating compressors: 3 years

• Centrifugal compressors and pneumatic controllers: 10 years

• Storage vessels: 15 years

• Equipment leaks: 5 to 10 years, depending on specif ic control3-11

To estimate total annualized engineering compliance costs, we added the annualized costs of each item without accounting for different expec ted lifetimes. An alternative approach would be to establish an overall, representative project time horizon and annualize costs after consideration of control options that would need to be replaced periodically within the given time horizon. For example, a 15 year project would require replacing reciprocating compressorrelated controls five times, but only require a sin gle installation of controls on storage vessels. This approach, however, is equivalent to the approa ch selected; that is to sum the annualized costs across options, without establishing a repres entative project time horizon.

Second, the projected number of affected units is t he number of units that our analysis shows would be affected in 2015, the analysis year. The projected number of affected units accounts for estimates of the adoption of controls in absence of Federal regulation. While the procedures used to estimate adoption in absence of Federal regulation are presented in detail within the TSD, because REC requirements provide a significant component of the estimated emissions reductions and engineering compliance cos ts, it is worthwhile to go into some detail on the projected number of RECs within the RIA. We use EIA projections consistent with the Annual Energy Outlook 2011 to estimate the number o f natural gas well completions with hydraulic fracturing in 2015, assuming that success ful wells drilled in coal bed methane, shale, and tight sands used hydraulic fracturing. Based o n this assumption, we estimate that 11,403 wells were successfully completed and used hydrauli c fracturing. To approximate the number of wells that would not be required to perform RECs be cause of the absence of sufficient infrastructure, we draw upon the distinction in EIA analysis between exploratory and developmental wells. We assume exploratory wells d o not have sufficient access to infrastructure to perform a REC and are exempt from the REC requirement. These 446 wells are
removed from the REC estimate and are assumed to co mbust emissions using pit flares.

The number of hydraulically fractured recompletions of existing wells was approximated using assumptions found in Subpart W’s TSD 6 and applied to well count data found in the proprietary HPDI ® database. The underlying assumption is that wells found in coal bed

6 U.S. Environmental Protection Agency (U.S. EPA). 2 010. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry: Background Tech nical Support Document. Climate Change Division. Washington, DC.3-12

methane, shale, and tight sand formations require r e-fracture, on average, every 10 years. In other words, 10 percent of the total wells classifi ed as being performed with hydraulic fracturing would perform a recompletion in any given year. Na tural gas well recompletions performed without hydraulic fracturing were based only on 200 8 well data from HPDI ®

.

The number of completions and recompletions already controlling emissions in absence of a Federal regulation was estimated based on exis ting State regulations that require applicable control measures for completions and workovers in s pecific geographic locations. Based on this criterion, 15 percent of natural gas completions wi th hydraulic fracturing and 15 percent of existing natural gas workovers with hydraulic fract uring are estimated to be controlled by either flare or REC in absence of Federal regulations. Co mpletions and recompletions without hydraulic fracturing were assumed as having no cont rols in absence of a Federal regulation. Following these procedures leads to an estimate of 9,313 completions of new wells and 12,050 recompletions of existing wells that will require e ither a REC under the proposed NSPS in 2015.

It should be noted that natural gas prices are stoc hastic and, historically, there have been periods where prices have increased or decreased ra pidly. These price changes would be expected to affect adoption of emission reduction t echnologies in absence of regulation, particularly control measures such as RECs that cap ture emission significantly over short periods
of time.

Third, for well completion requirements, annualized costs are set equal to capital costs. We chose to equate the capital and annualized cost because the completion requirements (combustion and RECs) are essentially one-shot even ts; the emissions controls are applied over the course of a well completion, which will typical ly range over a few days to a couple of weeks. After this relatively short period of time, there i s no continuing control requirement, unless the well is again completed at a later date, sometimes years later. We reasoned that the absence of a continuing requirement makes it appropriate to equa te capital and annualized costs.

Fourth, for annualized cost, we present two figures , the annualized costs with revenues from additional natural gas and condensate recovery and annualized costs without additional revenues this product recovery. Several emission c ontrols for the NSPS capture VOC emissions3-13

that otherwise would be vented to the atmosphere. Since methane is co-emitted with VOCs, a large proportion of the averted methane emissions c an be directed into natural gas production streams and sold. When including the additional na tural gas recovery in the cost analysis, we assume that producers are paid $4 per thousand cubi c feet (Mcf) for the recovered gas at the wellhead. RECs also capture saleable condensates t hat would otherwise be lost to the environment. The engineering analysis assumes a RE C will capture 34 barrels of condensate per REC and that the value of this condensate is $70/ba rrel.

The assumed price for natural gas is within the ran ge of variation of wellhead prices for the 2010-11 period. The $4/Mcf is below the 2015 E IA-forecasted wellhead price, $4.22/Mcf in 2008 dollars. The $4/Mcf payment rate does not ref lect any taxes or tax credits that might apply to producers implementing the control technologies. As natural gas prices can increase or decrease rapidly, the estimated engineering complia nce costs can vary when revenue from additional natural gas recovery is included. There is also geographic variability in wellhead prices, which can also influence estimated engineer ing costs. A $1/Mcf change in the wellhead price causes a change in estimated engineering comp liance costs of about $180 million in 2008 dollars.
As will be seen in subsequent analysis, the estimat e of revenues from additional product recovery is critical to the economic impact analysi s. However, before discussing this assumption in more depth, it is important to further develop t he engineering estimates to contextualize the discussion and to provide insight into why, if it i s profitable to capture natural gas emissions that are otherwise vented, producers may not already be doing so.
Table 3-3 presents the estimated nationwide complia nce costs, emissions reductions, and VOC reduction cost-effectiveness broken down by emi ssions sources and points for those sources and points evaluated in the NSPS analysis. The reporting and recordkeeping costs for the proposed NSPS Option 2 are estimated at $18,805 ,398 and are included in Table 3-3. Because of time constraints, we were unable to esti mate reporting and recordkeeping costs customized for Options 1 and 3; for these options, we use the same $18,805,398 for reporting and recordkeeping costs for these options.

As can be seen from Table 3-3 controls associated w ith well completions and recompletions of hydraulically fractured wells prov ide the largest potential for emissions3-14

reductions from evaluated emissions sources and poi nts, as well as present the most significant compliance costs if revenue from additional natural gas recovery is not included. Emissions reductions from conventional natural gas wells and crude oil wells are clearly not as significant as the potential from hydraulically fractured wells , as was discussed in Section 3.2.1.1.

Several evaluated emissions sources and points are estimated to have net financial savings when including the revenue from additional natural gas recovery. These sources form the core of the three NSPS options evaluated in thi s RIA. Table 3-4 presents the estimated engineering costs, emissions reductions, and VOC re duction cost-effectiveness for the three NSPS options evaluated in the RIA. The resulting t otal national annualized cost impact of the proposed NSPS rule (Option 2) is estimated at $740 million per year without considering revenues from additional natural gas recovery. Ann ual costs for the proposed NSPS are estimated at -$45 million when revenue from additio nal natural gas recovery is included. All figures are in 2008 dollars.3-15

Table 3-2 Summary of Capital and Annualized Costs p er Unit for NSPS Emissions Points

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

Capital Costs (2008$) Without

Revenues from Additional Product Recovery With

Revenues from Additional Product Recovery Well Completions Hydraulically Fractured Gas Wells that Meet Criteria for REC 9,313 $33,237 $33,237 -$ 2,173 Hydraulically Fractured Gas Wells that Do Not Meet Criteria for REC (Completion Combustion) 446 $3,523 $3,523 $3,523 Conventional Gas Wells 7,694 $3,523 $3,523 $3,523 Oil Wells 12,193 $3,523 $3,523 $3,523 Well Recompletions Hydraulically Fractured Gas Wells (existing wells) 12,050 $33,237 $33,237 -$2,173 Conventional Gas Wells 42,342 $3,523 $3,523 $3,523 Oil Wells 39,375 $3,523 $3,523 $3,523 Equipment Leaks Well Pads 4,774 $68,970 $23,413 $21,871 Gathering and Boosting Stations 275 $239,494 $57,06 3 $51,174 Processing Plants 29 $7,522 $45,160 $33,884 Transmission Compressor Stations 107 $96,542 $25,35 0 $25,350 Reciprocating Compressors Well Pads 6,000 $6,480 $3,701 $3,664 Gathering/Boosting Stations 210 $5,346 $2,456 $870 Processing Plants 209 $4,050 $2,090 -$2,227 Transmission Compressor Stations 20 $5,346 $2,456 $ 2,456 Underground Storage Facilities 4 $7,290 $3,349 $3,3 49 Centrifugal Compressors Processing Plants 16 $75,000 $10,678 -$123,730 Transmission Compressor Stations 14 $75,000 $10,678 -$77,622 Pneumatic Controllers - Oil and Gas Production 13,632 $165 $23 -$1,519 Natural Gas Trans. and Storage 67 $165 $23 $23 Storage Vessels High Throughput 304 $65,243 $14,528 $13,946 Low Throughput 17,086 $65,243 $14,528 $13,9463-16Table 3-3 Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction Cost-Effectiveness byEmissions Sources and Points, NSPS, 2015Source/Emissions Point Emissions ControlNationwide Annualized Costs(2008$)Nationwide EmissionsReductions (tons/year)VOC Emissions ReductionCost-Effectiveness(2008$/ton)WithoutAddl.RevenuesWith Addl.Revenues VOC MethaneHAPWithoutAddl.RevenuesWith Addl.RevenuesWell Completions (New Wells)Hydraulically Fractured Gas Wells REC $309,553,517-$20,235,748204,1341,399,13914,831$1,516-$99Hydraulically Fractured Gas Wells Combustion $1,571,188$1,571,1889,80167,178712$160$160Conventional Gas Wells Combustion $27,104,761$27,104,7618575,87562$31,619$31,619Oil Wells Combustion $42,954,036$42,954,03683880$520,580$520,580Well Recompletions (Existing Wells)Hydraulically Fractured Gas Wells (existingwells) REC $400,508,928-$26,181,572264,1151,810,24519,189$1,516-$99Conventional Gas Wells Combustion $149,164,257$149,164,2573162,16523$472,227$472,227Oil Wells Combustion $138,711,979$138,711,97944470$3,134,431$3,134,431Equipment LeaksWell Pads NSPS Subpart VV $111,773,662$104,412,15410,64638,287401$10,499$9,808Gathering and Boosting Stations NSPS Subpart VV $15,692,325$14,072,8502,3408,41588$6,705$6,013Processing Plants NSPS Subpart VVa $1,309,650$982,6483921,41115$3,343$2,508Transmission Compressor Stations NSPS Subpart VV $2,712,450$2,712,4502619,4278$10,389$10,389Reciprocating CompressorsWell PadsAnnual Monitoring/Maintenance (AMM) $22,204,209$21,984,76326394710$84,379$83,545Gathering/Boosting Stations AMM $515,764$182,5974001,43715$1,291$457Processing Plants AMM $436,806-$465,3541,0823,89241$404-$430Transmission Compressor Stations AMM $47,892$47,892124230$4,093$4,093Underground Storage Facilities AMM $13,396$13,3962870$5,542$5,5423-17Table 3-3 (continued) Estimated Nationwide Compliance Costs, Emissions Reductions, and VOC Reduction CostEffectiveness by Emissions Sources and Points, NSPS, 2015Source/Emissions Point Emissions ControlNationwide Annualized Costs(2008$)Nationwide EmissionsReductions (tons/year)VOC Emissions ReductionCost-Effectiveness(2008$/ton)WithoutAddl.RevenuesWith Addl.Revenues VOC Methane HAPWithoutAddl.RevenuesWith Addl.RevenuesCentrifugal CompressorsProcessing PlantsDry Seals/Route toProcess or Control $170,853-$1,979,6872883,18310$593-$6,874Transmission Compressor StationsDry Seals/Route toProcess or Control $149,496-$1,086,704431,5461$3,495-$25,405Pneumatic Controllers -Oil and Gas ProductionLow Bleed/Route toProcess $320,071-$20,699,91825,21090,685952$13-$821Natural Gas Trans. and StorageLow Bleed/Route toProcess $1,539$1,53962120$262$262Storage VesselsHigh Throughput 95% control $4,411,587$4,234,85629,6546,490876$149$143Low Throughput 95% control $248,225,012$238,280,9766,8381,497202$36,298$34,8443-18

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

Option 1 Option 2 (Proposed) Option 3 Capital Costs $337,803,930 $738,530,998 $1,143,984,622
Annualized Costs Without Revenues from Additional Natural Gas Product Recovery $336,163,858 $737,982,436 $868,160,873
With Revenues from Additional Natural Gas Product Recovery -$19,496,449 -$44,695,374 $76,502,080

VOC Reductions (tons per year) 270,695 535,201 548,449 Methane Reduction (tons per year) 1,574,498 3,386,154 3,442,283 HAP Reductions (tons per year) 17,442 36,645 37,142

VOC Reduction Cost-Effectiveness ($/ton without additional product revenues) $1,241.86 $1,378.89 $1,582.94
VOC Reduction Cost-Effectiveness ($/ton with additional product revenues) -$72.02 -$83.51 $139.49

Note: the VOC reduction cost-effectiveness estimate assumes there is no benefit to reducing methane an d HAP, which is not the case. We however present the per ton costs of reducing the single pollutant for illu strative purposes. As product prices can increase or decrea se rapidly, the estimated engineering compliance co sts 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 wellhea d price causes a change in estimated engineering compliance costs of about $180 million in 2008 dollars. The cost estimates for each regulatory option also include r eporting and recordkeeping costs of $18,805,398.

As mentioned earlier, the single difference betwee n Option 1 and the proposed Option 2 is the inclusion of RECs for recompletions of exist ing wells in Option 2. The implication of this inclusion in Option 2 is clear in Table 3-4, as the estimated engineering compliance costs without additional product revenue more than double and VOC emissions reductions also more than double. Meanwhile, the addition of equipment leaks standards in Option 3 increases engineering costs more than $400 million dollars in 2008 dollar s, but only marginally increase estimates of emissions reductions of VOCs, methane, and HAPS.

As the price assumption is very influential on esti mated impacts, we performed a simple sensitivity analysis of the influence of the assume d wellhead price paid to natural gas producers on the overall engineering costs estimate of the pr oposed NSPS. Figure 3-1 plots the annualized costs after revenues from natural gas product recov ery have been incorporated (in millions of 2008 dollars) as a function of the assumed price of natural gas paid to producers at the wellhead3-19

for the recovered natural gas (represented by the s loped, dotted line). The vertical solid lines in the figure represent the natural gas price assumed in the RIA ($4.00/Mcf) for 2015 and the 2015 forecast by EIA in the 2011 Annual Energy Outlook ( $4.22/Mcf) in 2008 dollars.

Figure 3-1 Sensitivity Analysis of Proposed NSPS An nualized Costs after Revenues from Additional Product Recovery are Included
As shown in Table 3-4, at the assumed $4/Mcf, the a nnualized costs are estimated at -$45 million. At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy Outlook, the annualized costs are estimated at about -$90 millio n, which would approximately double the estimate of net cost savings of the proposed NSPS. As indicated by this difference, EPA has chosen a relatively conservative assumption (leadin g to an estimate of few savings and higher net costs) for the engineering costs analysis. The nat ural gas price at which the proposed NSPS breaks-even is around $3.77/Mcf. As mentioned earl ier, a $1/Mcf change in the wellhead natural gas price leads to about a $180 million change in t he annualized engineering costs of the proposed NSPS. Consequently, annualized engineerin g costs estimates would increase to about $140 million under a $3/Mcf price or decrease to ab out -$230 million under a $5/Mcf price.

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

$- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 Annualized Costs after Product Recovery ($ Millions) Natural Gas Price ($/Mcf) in 2015

RIA Assumed

Price in 2015 ($4.00/Mcf

) EIA Forecast Price in 2015 ($4.22/Mcf) Annualized Costs as Function of Natural Gas Price Assumption3-20

It is additionally helpful to put the quantity of n atural gas and condensate potentially recovered in the context of domestic production lev els. To do so, it is necessary to make two adjustments. First, not all emissions reductions c an be directed into production streams to be ultimately consumed by final consumers. Several co ntrols require combustion of the natural gas rather than capture and direction into product stre ams. After adjusting estimates of national
emissions reductions in Table 3-3 for these combust ion-type controls, Options 1, 2, and 3 are estimated to capture about 83, 183, and 185 bcf of natural gas and 317,000, 726,000, and 726,000 barrels of condensate, respectively. For c ontrol options that are expected to recover natural gas products. Estimates of unit-level and nation-level product recovery are presented in Section 3 of the RIA. Note that completion-related requirements for new and existing wells generate all the condensate recovery for all NSPS r egulatory options. For natural gas recovery, RECs contribute 77 bcf (92 percent) for Option 1, 1 76 bcf (97 percent) for Option 2, and 176 bcf (95 percent) for Option 3.3-21Table 3-5 Estimates of Control Unit-level and National Level Natural Gas and Condensate Recovery, NSPSOptions, 2015ProjectedNo. ofAffectedUnitsUnit-level Product Recovery Total Product RecoverySource/ Emissions Points Emissions ControlNSPSOptionNatural GasSavings(Mcf/unit)Condensate(bbl/unit)Natural GasSavings (Mcf)Condensate(bbl)Well CompletionsHydraulically Fractured Gas Wells REC 1, 2, 3 9,3138,258 34 76,905,813 316,657Hydraulically Fractured Gas Wells Combustion 1, 2,3 446 0 0 0 0Hydraulically Fractured Gas Wells(existing wells)REC 2, 3 12,050 8,258 34 99,502,875 409,700Equipment LeaksWell Pads NSPS Subpart VV3 4,774 386 0 1,840,377 0Gathering and Boosting Stations NSPS Subpart VV3 275 1,472 0 404,869 0Processing Plants NSPS Subpart VVa 2, 3 29 2,819 081,750 0Reciprocating CompressorsGathering/Boosting Stations AMM 1, 2, 3 210 397 083,370 0Processing Plants AMM 1, 2, 3 375 1,079 0 404,6770Trans. Compressor Stations AMM 1, 2, 3 199 1,122 0223,374 0Underground Storage Facilities AMM 1, 2, 3 9 1,1300 9,609 0Centrifugal CompressorsProcessing PlantsDry Seals/Route to Processor Ctrl1, 2, 3 16 11,527 0 184,435 0Trans. Compressor StationsDry Seals/Route to Processor Ctrl1, 2, 3 14 5,716 0 80,018 0Pneumatic Controllers -Oil and Gas ProductionLow Bleed/Route toProcess1, 2, 3 13,632 386 0 5,254,997 0Natural Gas Trans. and StorageLow Bleed/Route toProcess1, 2, 3 67 0 0 0 0Processing Plants Instrument Air 1, 2, 3 15 871.0 013,064 0Storage VesselsHigh Throughput 95% control 1, 2, 3 304 146 0 44,189 0Option 1 Total (Mcf)83,203,546 316,657Option 2 Total (Mcf)182,788,172 726,357Option 3 Total (Mcf) 185,033,417 726,3573-22

A second adjustment to the natural gas quantities i s necessary to account for nonhydrocarbon gases removed and gas that reinjecte d to repressurize wells, vented or flared, or consumed in production processes. Generally, wellh ead production is metered at or near the wellhead and payments to producers are based on the se metered values. In most cases, the natural gas is minimally processed at the meter and still contains impurities or co-products that must be processed out of the natural gas at process ing plants. This means that the engineering
cost estimates of revenues from additional natural gas recovery arising from controls implemented at the wellhead include payment for the impurities, such as the VOC and HAP content of the unprocessed natural gas. According to EIA, in 2009 the gross withdrawal of natural gas totaled 26,013 bcf, but 20,580 bcf was ultimately considered dry production (these figures exclude EIA estimates of flared and vented natural gas). Using these numbers, we apply a factor of 0.79 (20,580 bcf divided by 26,013 bcf) to the adjusted sums in the previous paragraph to estimate the volume of gas that is cap tured by controls that may ultimately by consumed by final consumers.

After making these adjustments, we estimate that O ption 1 will potentially recover approximately 66 bcf, proposed Option 2 will potent ially recover about 145 bcf, and Option 3 will potentially recover 146 bcf of natural gas tha t will ultimately be consumed by natural gas

consumers. 7 EIA forecasts that the domestic dry natural gas p roduction in 2015 will be 20,080 bcf. Consequently, Option 1, proposed Option 2, an d Option 3 may recover production representing about 0.29 percent, 0.64 percent and 0 .65 percent of domestic dry natural gas production predicted in 2015, respectively. These estimates, however, do not account for adjustments producers might make, once compliance c osts and potential revenues from additional natural gas recovery factor into economi c decisionmaking. Also, as discussed in the previous paragraph, these estimates do not include the nonhydrocarbon gases removed, natural gas reinjected to repressurize wells, and natural g as consumed in production processes, and therefore will be lower than the estimates of the g ross natural gas captured by implementing
controls.

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

Clearly, this discussion raises the question as to why, if emissions can be reduced profitably using environmental controls, more produ cers 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 tha t, using the engineering compliance costs estimates, the estimates of natural gas product rec overy, and assumed product prices (Table 3-6). The rates of return presented in are for evaluated controls where estimated revenues from additional product recovery exceed the costs. The rate of return is calculated using the simple formula: product recovery, and assumed product pric es (Table 3-6). The rates of return presented in are for evaluated controls where estim ated revenues from additional product recovery exceed the costs. The rate of return is c alculated using the simple formula:

estimated revenues rate of return 1 100

estimated costs   = − ×     . Table 3-6 Simple Rate of Return Estimate for NSPS C ontrol Options

Emission Point Control Option Rate of Return

New Completions of Hydraulically Fractured Wells Reduced Emissions Completions 6.5%

Re-completions of Existing Hydraulically Fractured Wells Reduced Emissions Completions 6.5%

Reciprocating Compressors (Processing Plants) Replace Packing Every 3 Years of Operation 208.3% Centrifugal Compressors (Processing Plants) Convert to Dry Seals 1158.7% Centrifugal Compressors (Transmission Compressor Stations) Convert to Dry Seals 726.9% Pneumatic Controllers (Oil and Gas Production ) Low Bleed 6467.3% Overall Proposed NSPS Low Bleed 6.1% Note: The table presents only control options wher e estimated revenues from natural gas product recov ery exceeds estimated annualized engineering costs Recall from Table 2-23 in the Industry Profile, tha t EIA estimates an industry-level rate of return on investments for various segments of th e oil and natural gas industry. While the numbers varies greatly over time because of industr y and economic factors, EIA estimates a 10.7 percent rate of return on investments for oil and n atural gas production in 2008. While this amount is higher than the 6.5 percent rate estimate d for RECs, it is significantly lower than the
rate of returns estimated for other controls antici pated to have net savings. Assuming financially rational producers, standard e conomic theory suggests that all oil and natural gas firms would incorporate all cost-ef fective improvements, which they are aware3-24

of, without government intervention. The cost anal ysis of this draft RIA nevertheless is based on the observation that emission reductions that appea r to be profitable in our analysis have not been generally adopted. One possible explanation m ay be the difference between the average profit margin garnered by productive capital and th e environmental capital where the primary motivation for installing environmental capital wou ld be to mitigate the emission of pollutants and confer social benefits as discussed in Chapter 4.

Another explanation for why there appear to be nega tive cost control technologies that are not generally adopted is imperfect information. If emissions from the oil and natural gas sector are not well understood, firms may underesti mate the potential financial returns to capturing emissions. Quantifying emissions is diff icult and has been done in relatively few studies. Recently, however, advances in infrared i magery 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 indu stry and among environmental groups and the public at large about the large number of emiss ions sources and possible scale of emissions from oil and natural gas production activities. Si nce, as discussed in the TSD chapter referenced above, 15 percent of new natural gas well completio ns with hydraulic fracturing and 15 percent of existing natural gas well recompletions with hyd raulic fracturing are estimated to be controlled by either flare or REC in the baseline, it is unlikely that a lack of information will be a significant reason for these emission points to not be addressed in the absence of Federal regulation in 2015. However, for other emission po ints, a lack of information, or the cost associated with doing a feasibility study of potent ial emission capture technologies, may continue to prevent firms from adopting these impro vements in the absence of regulation.

Another explanation is the cost associated with irr eversibility associated with implementing these environmental controls are not r eflected in the engineering cost estimates above. Due to the high volatility of natural gas p rices, it is important to recognize the value of flexibility taken away from firms when requiring th em to install and use a particular emissions capture technology. If a firm has not adopted the technology on its own, then a regulation mandating its use means the firm loses the option t o postpone investment in the technology in order to pursue alternative investments today, and the option to suspend use of the technology if it becomes unprofitable in the future. Therefore, the full cost of the regulation to the firm is the3-25

engineering cost and the lost option value minus th e revenues from the sale of the additional recovered product. In the absence of quantitative estimates of this option value for each emission point affected by the NSPS and NESHAP impr ovements, the costs presented in this RIA may underestimate the full costs faced by the a ffected firms. With these caveats in mind, EPA believes it is analytically appropriate to anal yze costs and economic impacts costs presented in Table 3-2 and Table 3-3 using the additional pro duct recovery and associated revenues.

3.2.2.2 NESHAP Sources

As discussed in Section 3.2.1.2, EPA examined three emissions points as part of its analysis for the proposed NESHAP amendments. Unlik e the controls for the proposed NSPS, the controls evaluated under the proposed NESHAP am endments do not direct significant quantities of natural gas that would otherwise be f lared or vented into the production stream. Table 3-7 shows the projected number of controls re quired, estimated unit-level capital and annualized costs, and estimated total annualized co sts. The table also shows estimated emissions reductions for HAPs, VOCs, and methane, as well as a cost-effectiveness estimate for HAP reduction, based upon engineering (not social) cost s.3-26

Table 3-7 Summary of Estimated Capital and Annual C osts, Emissions Reductions, and HAP Reduction Cost-Effectiveness for Proposed N ESHAP Amendments

Source/Emissions Point Projected

No. of Controls Required Emission Reductions (tons per year)

Capital Costs/ Unit (2008$) Annualized

Cost/Unit (2008$) Total

Annualized Cost (2008$) HAP VOC Methane HAP ReductionCostEffectiveness (2008$/ton) Production - Small Glycol Dehydrators 115 65,793 30,409 3,497,001 548 893 324 6,377 Transmission - Small Glycol Dehydrators 19 19,537 19,000 361,000 243 475 172 1 ,483 Storage Vessels 674 65,243 14,528 9,791,872 589 7,8 12 4,364 16,618 Reporting and Recordkeeping --- 196 2,933 2,369,755 --- --- --- - -- Total 808 16,019,871 1,381 9,243 4,859 10,576 Note: Totals may not sum due to independent roundin g. Under the Proposed NESHAP Amendments, about 800 con trols will be required, costing a total of $16.0 million (Table 3-7). We include rep orting and recordkeeping costs as a unique line item showing these costs for the entire set of prop osed amendments. These controls will reduce HAP emissions by about 1,400 tons, VOC emissions by about 9,200 tons, and methane by about 4,859 tons. The cost-per-ton to reduce HAP emissio ns is estimated at about $11,000 per ton. All figures are in 2008 dollars.

3.3 References

Oil and Gas Journal . “Natural Gas Pipelines Continue Growth Despite Lo wer 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 Pl ants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010.4-1 4 BENEFITS OF EMISSIONS REDUCTIONS

4.1 Introduction The proposed Oil and Natural Gas NSPS and NESHAP am endments are expected to result in significant reductions in existing emissi ons and prevent new emissions from expansions of the industry. While we expect that these avoide d emissions will result in improvements in air quality and reduce health effects associated with e xposure to HAPs, ozone, and fine particulate matter (PM 2.5 ), we have determined that quantification of those health benefits cannot be accomplished for this rule in a defensible way. Th is is not to imply that there are no health benefits of the rules; rather, it is a reflection o f the difficulties in modeling the direct and indir ect impacts of the reductions in emissions for this ind ustrial sector with the data currently available. For the proposed NSPS, the HAP and climate benefits can be considered “co-benefits”, and for the proposed NESHAP amendments, the ozone and 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 HA Ps and methane.

The proposed NSPS is anticipated to prevent 37,000 tons of HAPs, 540,000 tons of VOCs, and 3.4 million tons of methane from new sour ces, while the proposed NESHAP amendments is anticipated reduce 1,400 tons of HAPs , 9,200 tons of VOCs, and 4,900 tons of methane from existing sources. The specific contro l technologies for the proposed NSPS is also anticipated to have minor secondary disbenefits, in cluding an increase of 990,000 tons of CO 2 , 510 tons of NOx, 2,800 tons of CO, 7.6 tons of PM, and 1,000 tons of THC, and proposed NESHAP is anticipated to have minor secondary disbe nefits, including an increase of 5,500 tons
of CO 2 , 2.9 tons of NOx, 16 tons of CO, and 6.0 tons of T HC. Both rules would have additional emission changes associated with the energy system impacts. The net CO 2 -equivalent emission reductions are 62 million metric tons for the propo sed NSPS and 93 thousand metric tons for the proposed NESHAP. As described in the subsequent se ctions, these pollutants are associated with substantial health effects, welfare effects, a nd climate effects. With the data available, we are not able to provide a credible benefits estimat es for any of these pollutants for these rules,
due to the differences in the locations of oil and natural gas emission points relative to existing information, and the highly localized nature of air quality responses associated with HAP and VOC reductions. In addition, we do not yet have in teragency agreed upon valuation estimates4-2

for greenhouse gases other than CO 2 that could be used to value the climate co-benefits associated with avoiding methane emissions. Instea d, we provide a qualitative assessment of the
benefits and co-benefits as well as a break-even an alysis in Chapter 6 of this RIA. A break-even analysis answers the question, “What would the bene fits need to be for the benefits to exceed the costs.” While a break-even approach is not equivale nt to a benefits analysis, we feel the results are illustrative, particularly in the context of pr evious benefit per ton estimates.

4.2 Direct Emission Reductions from the Oil and Natural Gas Rules As described in Section 2 of this RIA, oil and natu ral gas operations in the U.S. include a variety of emission points for VOCs and HAPs includ ing wells, processing plants, compressor stations, storage equipment, and transmission and d istribution lines. These emission points are located throughout much of the country with signifi cant concentrations in particular regions. For example, wells and processing plants are largely co ncentrated in the South Central, Midwest, and Southern California regions of the U.S., whereas ga s compression stations are located all over the country. Distribution lines to customers are f requently 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 St andards (NAAQS) in some areas and assist other areas with attaining the NAAQS. Due to the hi gh 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 s tatus without air quality modeling data. 8 Because the NAAQS RIAs also calculate ozone and PM benefits, there are important differences worth noting in the design and analytical objective s of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that Sta tes may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly res ult in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not inte nded to be added to the costs and benefits of other regulations that result in specific costs of control and emission reductions. However,

8 The responsiveness of ozone and PM 2.5 formation is discussed in greater detail in section s 4.4.1 and 4.5.1 of this RIA.4-3

some costs and benefits estimated in this RIA accou nt for the same air quality improvements as estimated in an illustrative NAAQS RIA.

By contrast, the emission reductions for this rule are from a specific class of wellcharacterized sources. In general, EPA is more conf ident in the magnitude and location of the emission reductions for these rules. It is importan t to note that emission reductions anticipated
from these rules do not result in emission increase s elsewhere (other than potential energy disbenefits). Emission reductions achieved under th ese and other promulgated rules will ultimately be reflected in the baseline of future N AAQS analyses, which would reduce the
incremental costs and benefits associated with atta ining the NAAQS. EPA remains forward looking towards the next iteration of the 5-year re view 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 r elationship between the NAAQS and rules such as analyzed here, please see Section 1.2 .4 of the SO 2 NAAQS RIA (U.S. EPA, 2010d). Table 4-1 shows the direct emission reduct ions anticipated for these rules by option. It is important to note that these benefits accrue at different spatial scales. HAP emission reductions reduce exposure to carcinogens and other toxic pollutants primarily near the emission source. Reducing VOC emissions would reduce precur sors to secondary formation of PM 2.5 and ozone, which reduces exposure to these pollutants o n a regional scale. Climate effects associated with long-lived greenhouse gases like methane are p rimarily at a global scale, but methane is also a precursor to ozone, a short-lived climate fo rcer that exhibits spatial and temporal variability.

Table 4-1 Direct Emission Reductions Associated wit h Options for the Oil and Natural Gas NSPS and NESHAP amendments in 2015 (short tons per year)

Pollutant NESHAP

Amendments NSPS Option 1 NSPS

Option 2 (Proposed) NSPS Option 3 HAPs 1,381 17,442 36,645 37,142 VOCs 9,243 270,695 535,201 548,449 Methane 4,859 1,574,498 3,386,154 3,442,2834-4

4.3 Secondary Impacts Analysis for Oil and Gas Rules The control techniques to avert leaks and vents of VOCs and HAPs are associated with several types of secondary impacts, which may parti ally offset the direct benefits of this rule. In this RIA, we refer to the secondary impacts associa ted with the specific control techniques as “producer-side” impacts. 9 For example, by combusting VOCs and HAPs, combust ion increases emissions of carbon monoxide, NOx, particulate matt er and other pollutants. In addition to “producer-side” impacts, these control techniques w ould also allow additional natural gas recovery, which would contribute to additional comb ustion of the recovered natural gas and ultimately a shift in the national fuel mix. We re fer to the secondary impacts associated with the combustion of the recovered natural gas as “consume r-side” secondary impacts. We provide a conceptual diagram of both categories of secondary impacts in Figure 4-1.

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

Figure 4-1 Conceptual Diagram of Secondary Impacts from Oil and Gas NSPS and NESHAP Amendments
Table 4-2 shows the estimated secondary impacts fo r the selected option for the “producer-side” impacts. Relative to the direct em ission reductions anticipated from these rules, the magnitude of these secondary air pollutant impa cts is small. Because the geographic distribution of these emissions from the oil and ga s sector is not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009), we ar e 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 increa sed CO 2 emissions without monetizing the averted methane emissions because the overall globa l warming potential (GWP) is actually4-6

lower. Through the combustion process, methane emi ssions are converted to CO 2 emissions, which have 21 times less global warming potential c ompared to methane (IPCC, 2007). 10

Table 4-2 Secondary Air Pollutant Impacts Associate d with Control Techniques by Emissions Category (“Producer-Side”) (tons per year )

Emissions Category CO 2 NOx PM CO THC Completions of New Wells (NSPS) 587,991 302 5 1,644 622 Recompletions of Existing Wells (NSPS) 398,341 205 - 1,114 422 Pneumatic Controllers (NSPS) 22 1.0 2.6 - - Storage Vessels (NSPS) 856 0.5 0.0 2.4 0.9 Total NSPS 987,210 508 7.6 2,760 1,045 Total NESHAP (Storage Vessels) 5,543 2.9 0.1 16 6
For the “consumer-side” impacts associated with the NSPS, we modeled the impact of the regulatory options on the national fuel mix and associated CO 2 -equivalent emissions (Table 4-3). 11 We provide the modeled results of the “consumer-s ide” CO 2 -equivalent emissions in
Table 7-12 Error! Reference source not found.

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 1.6 million metric tons for the proposed NSPS option in 2015. This is in addition to the other secondary impacts and directly avoided emissions, for a total 62 million metric to ns of CO 2 -equivalent emissions averted as
shown in Table 4-4. Due to time limitations under the court-ordered schedule, we did not estimate the other emissions (e.g., NOx, PM, SOx) a ssociated with the additional national gas consumption or the change in the national fuel mix.

10 This issue is discussed in more detail in Section 4.7 of this RIA. 11 A full discussion of the energy modeling is availa ble 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 Proposed Oil and Gas NSPS in 2015 (million metric tons) ("Consumer-Side") 1

Fuel Type NSPS Option 1 (million metric tons change in CO 2 -e) NSPS Option 2 (million metric

tons change in CO 2 -e) (Proposed) NSPS Option 3 (million metric tons change in CO 2 -e)
Petroleum -0.51 -0.14 -0.18
Natural Gas 2.63 1.35 1.03
Coal -3.04 0.36 0.42
Other 0.00 0.00 0.00 Total modeled Change in CO 2 -e Emissions -0.92 1.57 1.27

1 These estimates reflect the modeled change in CO 2 -e emissions 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 f or the Proposed Oil and Gas NSPS in 2015 (million metr ic tons)

Emissions Source NSPS Option 1 NSPS Option 2

(Proposed) NSPS

Option 3 NESHAP

Amendments
Averted CO 2 -e Emissions from New Sources 1 -30.00 -64.51 -65.58 -0.09
Additional CO 2 -e Emissions from Combustion and Supplemental Energy (Producer-side) 2 0.90 0.90 0.90 0.01
Total Modeled Change in Energy-related CO 2 -e Emissions (Consumer-side) 3 -0.92 1.57 1.27 --
Total Change in CO 2 -e Emissions after Adjustment for Secondary Impacts -30.02 -62.04 -63.41 -0.09

1 This estimate reflects the GWP of the avoided meth ane emissions from new sources shown in Table 4-1 a nd has been converted from short tons to metric tons.

2 This estimate represents the secondary producer-si de impacts associated with additional CO 2 emissions from combustion and from additional electricity requirem ents shown in Table 4-2 and has been converted from short tons to metric tons. We use the producer-side secondary impacts associated with the proposed NSPS option as a surrogate for the impacts of the other options.
3 This estimate reflects the modeled change in the en ergy–related consumer-side impacts shown in Table 4 -3. Totals may not sum due to independent rounding.

Based on these analyses, the net impact of both the direct and secondary impacts of these rules would be an improvement in ambient air qualit y, which would reduce exposure to various harmful pollutants, improve visibility impairment, reduce vegetation damage, and reduce potency of greenhouse gas emissions. Table 4-5 pro vides a summary of the direct and secondary emissions changes for each option.4-8

Table 4-5 Summary of Emissions Changes for the Prop osed Oil and Gas NSPS and NESHAP in 2015 (short tons per year)

Pollutant NSPS Option 1 NSPS Option 2

(Proposed) NSPS Option 3 NESHAP

Change in Direct Emissions VOC -270,000 -540,000 -550,000 -9,200 Methane -1,600,000 -3,400,000 -3,400,000 -4,900 HAP -17,000 -37,000 -37,000 -1,400

Change in Secondary Emissions (Producer-Side) 1 CO 2 990,000 990,000 990,000 5,500
NOx 510 510 510 2.9
PM 7.6 7.6 7.6 0.1 CO 2,800 2,800 2,800 16 THC 1,000 1,000 1,000 6.0 Change in Secondary Emissions (Consumer-Side) CO 2 -e -1,000,000 1,700,000 1,400,000 N/A
Net Change in CO 2 -equivalent Emissions CO 2 -e -33,000,000 -68,000,000 -70,000,000 -96,000

1 We use the producer-side secondary impacts associat ed with the proposed option as a surrogate for the impacts of the other options. Totals may not sum due to indepe ndent rounding.

4.4 Hazardous Air Pollutant (HAP) Benefits
Even though emissions of air toxics from all source s 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 concentration s of air toxics at levels that have the potential to cause adverse health effects (U.S. EPA , 2011d). 12 The levels of air toxics to which people are exposed vary depending on where people l ive and work and the kinds of activities in which they engage. In order to identify and priori tize air toxics, emission source types and locations that are of greatest potential concern, U .S. EPA conducts the NATA. 13 The most recent NATA was conducted for calendar year 2005 an d was released in March 2011. NATA includes four steps:

12 The 2005 NATA is available on the Internet at http ://www.epa.gov/ttn/atw/nata2005/.
13 The NATA modeling framework has a number of limita tions that prevent its use as the sole basis for se tting regulatory standards. These limitations and uncert ainties are discussed on the 2005 NATA website. Ev en so, this modeling framework is very useful in identifyi ng air toxic pollutants and sources of greatest con cern, setting regulatory priorities, and informing the decision m aking process. U.S. EPA. (2011) 2005 National-Sca le Air Toxics Assessment. http://www.epa.gov/ttn/atw/nata 2005/4-9

1) Compiling a national emissions inventory of air toxics emissions from outdoor sources
2) Estimating ambient and exposure concentrations o f air toxics across the United States
3) Estimating population exposures across the Unite d States
4) Characterizing potential public health risk due to inhalation of air toxics including both
cancer and noncancer effects
Based on the 2005 NATA, EPA estimates that about 5 percent of census tracts nationwide have increased cancer risks greater than 100 in a million. The average national cancer risk is about 50 in a million. Nationwide, the key pollutants that contribute most to the overall cancer risks are formaldehyde and benzene. 14,15 Secondary formation (e.g., formaldehyde forming from other emitted pollutants) was the larg est contributor to cancer risks, while stationary, mobile and background sources contribut e almost equal portions of the remaining
cancer risk.

Noncancer health effects can result from chronic, 16 subchronic, 17 or acute 18 inhalation exposures to air toxics, and include neurological, cardiovascular, liver, kidney, and respiratory effects as well as effects on the immune and reprod uctive systems. According to the 2005 NATA, about three-fourths of the U.S. population wa s 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 i s the primary driver for noncancer respiratory risk.

14 Details on EPA’s approach to characterization of c ancer risks and uncertainties associated with the 2 005 NATA risk estimates can be found at http://www.epa.gov/t tn/atw/nata1999/riskbg.html#Z2. 15 Details about the overall confidence of certainty ranking of the individual pieces of NATA assessment s including both quantitative (e.g., model-to-monitor ratios) a nd qualitative (e.g., quality of data, review of em ission inventories) judgments can be found at http://www.e pa.gov/ttn/atw/nata/roy/page16.html. 16 Chronic exposure is defined in the glossary of the Integrated Risk Information (IRIS) database (http://www.epa.gov/iris) as repeated exposure by t he oral, dermal, or inhalation route for more than approximately 10% of the life span in humans (more than approximately 90 days to 2 years in typically used laboratory animal species).
17 Defined in the IRIS database as repeated exposure by the oral, dermal, or inhalation route for more t han 30 days, up to approximately 10% of the life span in humans (more than 30 days up to approximately 90 days in t ypically used laboratory animal species).
18 Defined in the IRIS database as exposure by the or al, dermal, or inhalation route for 24 hours or les s.4-10

Figure 4-2 and Figure 4-3 depict the estimated cens us tract-level carcinogenic risk and noncancer respiratory hazard from the assessment. It is important to note that large reductions in HAP emissions may not necessarily translate into si gnificant reductions in health risk because toxicity varies by pollutant, and exposures may or may not exceed levels of concern. For example, acetaldehyde mass emissions are more than double acrolein emissions on a national basis, according to EPA’s 2005 National Emissions I nventory (NEI). However, the Integrated Risk Information System (IRIS) reference concentrat ion (RfC) for acrolein is considerably lower than that for acetaldehyde, suggesting that acrolei n could be potentially more toxic than acetaldehyde. 19 Thus, it is important to account for the toxicity and exposure, as well as the mass of the targeted emissions.

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

19 Details on the derivation of IRIS values and avai lable supporting documentation for individual chemi cals (as well as chemical values comparisons) can be found at htt p://cfpub.epa.gov/ncea/iris/compare.cfm.4-11

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

Due to methodology and data limitations, we were un able to estimate the benefits associated with the hazardous air pollutants that w ould be reduced as a result of these rules.. In a few previous analyses of the benefits of reductions in HAPs, EPA has quantified the benefits of potential reductions in the incidences of cancer an d non-cancer risk (e.g., U.S. EPA, 1995). In those analyses, EPA relied on unit risk factors (UR F) developed through risk assessment procedures. 20 These URFs are designed to be conservative, and as such, are more likely to represent the high end of the distribution of risk rather than a best or most likely estimate of risk. As the purpose of a benefit analysis is to describe the benefits most likely to occur from a reduction in pollution, use of high-end, conservati ve risk estimates would overestimate the

20 The unit risk factor is a quantitative estimate of the carcinogenic potency of a pollutant, often expr essed as the probability of contracting cancer from a 70-year li fetime continuous exposure to a concentration of on e μg/m 3 of a pollutant.4-12

benefits of the regulation. While we used high-end risk estimates in past analyses, advice from the EPA’s Science Advisory Board (SAB) recommended that we avoid using high-end estimates in benefit analyses (U.S. EPA-SAB, 2002). Since thi s time, EPA has continued to develop better methods for analyzing the benefits of reductions in HAPs.

As part of the second prospective analysis of the b enefits and costs of the Clean Air Act (U.S. EPA, 2011a), EPA conducted a case study analy sis of the health effects associated with reducing exposure to benzene in Houston from implem entation of the Clean Air Act (IEc, 2009). While reviewing the draft report, EPA’s Advisory Co uncil on Clean Air Compliance Analysis concluded that “the challenges for assessing progre ss in health improvement as a result of reductions in emissions of hazardous air pollutants (HAPs) are daunting...due to a lack of exposure-response functions, uncertainties in emiss ions inventories and background levels, the difficulty of extrapolating risk estimates to low d oses and the challenges of tracking health progress for diseases, such as cancer, that have lo ng latency periods” (U.S. EPA-SAB, 2008).

In 2009, EPA convened a workshop to address the inh erent complexities, limitations, and uncertainties in current methods to quantify the be nefits of reducing HAPs. Recommendations from this workshop included identifying research pr iorities, focusing on susceptible and vulnerable populations, and improving dose-response relationships (Gwinn et al., 2011).

In summary, monetization of the benefits of reducti ons in cancer incidences requires several important inputs, including central estimat es of cancer risks, estimates of exposure to carcinogenic HAPs, and estimates of the value of an avoided case of cancer (fatal and non-fatal). Due to methodology and data limitations, we did not attempt to monetize the health benefits of reductions in HAPs in this analysis. Instead, we pr ovide a qualitative analysis of the health effects associated with the HAPs anticipated to be reduced by these rules and we summarize the
results of the residual risk assessment for the Ris k and Technology Review (RTR). EPA remains committed to improving methods for estimating HAP b enefits by continuing to explore additional concepts of benefits, including changes in the distribution of risk.

Available emissions data show that several differen t HAPs are emitted from oil and natural gas operations, either from equipment leaks , processing, compressing, transmission and distribution, or storage tanks. Emissions of eight HAPs make up a large percentage the total4-13

HAP emissions by mass from the oil and gas sector: toluene, hexane, benzene, xylenes (mixed), ethylene glycol, methanol, ethyl benzene, and 2,2,4 -trimethylpentane (U.S. EPA, 2011a). In the subsequent sections, we describe the health effects associated with the main HAPs of concern from the oil and natural gas sector: benzene, tolue ne, carbonyl sulfide, ethyl benzene, mixed xylenes, and n-hexane. These rules combined are an ticipated to avoid or reduce 58,000 tons of HAPs per year. With the data available, it was not possible to estimate the tons of each
individual HAP that would be reduced.

EPA conducted a residual risk assessment for the NE SHAP rule (U.S. EPA, 2011c). The results for oil and gas production indicate that ma ximum lifetime individual cancer risks could be 30 in-a-million for existing sources before and aft er controls with a cancer incidence of 0.02 before and after controls. For existing natural ga s transmission and storage, the maximum
individual cancer risk decreases from 90-in-a-milli on before controls to 20-in-a-million after
controls with a cancer incidence that decreases fro m 0.001 before controls to 0.0002 after controls. Benzene is the primary cancer risk drive r. The results also indicate that significant noncancer impacts from existing sources are unlikel y, especially after controls. EPA did not
conduct a risk assessment for new sources affected by the NSPS. However, it is important to note that the magnitude of the HAP emissions avoide d by new sources with the NSPS are more than an order of magnitude higher than the HAP emis sions reduced from existing sources with
the NESHAP.

4.4.1 Benzene The EPA’s IRIS database lists benzene as a known hu man carcinogen (causing leukemia) by all routes of exposure, and concludes that expos ure is associated with additional health effects, including genetic changes in both humans a nd animals and increased proliferation of
bone marrow cells in mice. 21,22,23 EPA states in its IRIS database that data indicat e a causal

21 U.S. Environmental Protection Agency (U.S. EPA). 2 000. Integrated Risk Information System File for Be nzene. Research and Development, National Center for Envir onmental Assessment, Washington, DC. This material is available electronically at: http://www.epa.gov/iri s/subst/0276.htm.
22 International Agency for Research on Cancer, IARC m onographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 29, Some industrial che micals and dyestuffs, International Agency for Rese arch on Cancer, World Health Organization, Lyon, France, p. 345-389, 1982.
23 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; He nry, V.A. (1992) Synergistic action of the benzene metabolite hydroquinone on myelopoietic stimulating activity o f granulocyte/macrophage colony-stimulating factor in vitro, Proc. Natl. Acad. Sci. 89:3691-3695.4-14

relationship between benzene exposure and acute lym phocytic leukemia and suggest a relationship between benzene exposure and chronic n on-lymphocytic leukemia and chronic lymphocytic leukemia. The International Agency for Research on Carcinogens (IARC) has determined that benzene is a human carcinogen and t he U.S. Department of Health and Human Services (DHHS) has characterized benzene as a know n human carcinogen. 24 , 25 A number of adverse noncancer health effects including blood di sorders, such as preleukemia and aplastic anemia, have also been associated with long-term ex posure to benzene. 26,27 The most sensitive noncancer effect observed in humans, based on curre nt data, is the depression of the absolute lymphocyte count in blood. 28,29 In addition, recent work, including studies spons ored by the Health Effects Institute (HEI), provides evidence t hat biochemical responses are occurring at lower levels of benzene exposure than previously kn own. 30,31,32,33 EPA’s IRIS program has not yet evaluated these new data.

24 International Agency for Research on Cancer (IARC) . 1987. Monographs on the evaluation of carcinogen ic risk of chemicals to humans, Volume 29, Supplement 7, So me industrial chemicals and dyestuffs, World Health Organization, Lyon, France.
25 U.S. Department of Health and Human Services Natio nal Toxicology Program 11th Report on Carcinogens available at: http://ntp.niehs.nih.gov/go/16183.
26 Aksoy, M. (1989). Hematotoxicity and carcinogenic ity of benzene. Environ. Health Perspect. 82: 193 -197.
27 Goldstein, B.D. (1988). Benzene toxicity. Occupa tional medicine. State of the Art Reviews. 3: 541 -554.
28 Rothman, N., G.L. Li, M. Dosemeci, W.E. Bechtold, G .E. Marti, Y.Z. Wang, M. Linet, L.Q. Xi, W. Lu, M.T

. Smith, N. Titenko-Holland, L.P. Zhang, W. Blot, S.N . Yin, and R.B. Hayes (1996) Hematotoxicity among Chinese workers heavily exposed to benzene. Am. J. Ind. Med. 29: 236-246.
29 U.S. Environmental Protection Agency (U.S. EPA). 20 00. Integrated Risk Information System File for Ben zene (Noncancer Effects). Research and Development, Nat ional Center for Environmental Assessment, Washingt on, DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm.
30 Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; Coh en, B.; Melikian, A.; Eastmond, D.; Rappaport, S.; Li, H.; Rupa, D.; Suramaya, R.; Songnian, W.; Huifant, Y.; Me ng, M.; Winnik, M.; Kwok, E.; Li, Y.; Mu, R.; Xu, B.; Zhang, X.; Li, K. (2003). HEI Report 115, Validati on & Evaluation of Biomarkers in Workers Exposed to Benzene in China.
31 Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohe n, et al. (2002). Hematological changes among Chin ese workers with a broad range of benzene exposures. A m. J. Industr. Med. 42: 275-285.
32 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels of Benzene. Science 306: 1774-1776.
33 Turtletaub, K.W. and Mani, C. (2003). Benzene meta bolism in rodents at doses relevant to human exposu re from Urban Air. Research Reports Health Effect Inst. Re port No.113.4-15

4.4.2 Toluene 34
Under the 2005 Guidelines for Carcinogen Risk Asses sment, there is inadequate information to assess the carcinogenic potential of toluene because studies of humans chronically exposed to toluene are inconclusive, toluene was no t carcinogenic in adequate inhalation cancer bioassays of rats and mice exposed for life, and in creased incidences of mammary cancer and leukemia were reported in a lifetime rat oral bioas say.
The central nervous system (CNS) is the primary tar get for toluene toxicity in both humans and animals for acute and chronic exposures. CNS dysfunction (which is often reversible) and narcosis have been frequently obser ved in humans acutely exposed to low or moderate levels of toluene by inhalation: symptoms include fatigue, sleepiness, headaches, and nausea. Central nervous system depression has been reported to occur in chronic abusers exposed to high levels of toluene. Symptoms includ e ataxia, tremors, cerebral atrophy, nystagmus (involuntary eye movements), and impaired speech, hearing, and vision. Chronic inhalation exposure of humans to toluene also cause s irritation of the upper respiratory tract, eye irritation, dizziness, headaches, and difficulty wi th sleep.

Human studies have also reported developmental effe cts, such as CNS dysfunction, attention deficits, and minor craniofacial and limb anomalies, in the children of women who abused toluene during pregnancy. A substantial dat abase examining the effects of toluene in subchronic and chronic occupationally exposed human s exists. The weight of evidence from these studies indicates neurological effects (i.e., impaired color vision, impaired hearing, decreased performance in neurobehavioral analysis, changes in motor and sensory nerve conduction velocity, headache, and dizziness) as th e most sensitive endpoint.

4.4.3 Carbonyl sulfide

Limited information is available on the health effe cts of carbonyl sulfide. Acute (shortterm) inhalation of high concentrations of carbonyl sulfide may cause narcotic effects and irritate

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

the eyes and skin in humans. 35 No information is available on the chronic (long-t erm), reproductive, developmental, or carcinogenic effect s of carbonyl sulfide in humans. Carbonyl sulfide has not undergone a complete evaluation and determination under U.S. EPA's IRIS program for evidence of human carcinogenic potentia l. 36

4.4.4 Ethylbenzene
Ethylbenzene is a major industrial chemical produce d by alkylation of benzene. The pure chemical is used almost exclusively for styrene pro duction. It is also a constituent of crude petroleum and is found in gasoline and diesel fuels . Acute (short-term) exposure to ethylbenzene in humans results in respiratory effects such as th roat irritation and chest constriction, and irritation of the eyes, and neurological effects su ch as dizziness. Chronic (long-term) exposure of humans to ethylbenzene may cause eye and lung ir ritation, with possible adverse effects on the blood. Animal studies have reported effects on the blood, liver, and kidneys and endocrine system from chronic inhalation exposure to ethylben zene. No information is available on the developmental or reproductive effects of ethylbenze ne in humans, but animal studies have reported developmental effects, including birth def ects in animals exposed via inhalation. Studies in rodents reported increases in the percen tage of animals with tumors of the nasal and oral cavities in male and female rats exposed to et hylbenzene via the oral route. 37 , 38 The reports of
these studies lacked detailed information on the in cidence of specific tumors, statistical analysis, survival data, and information on historical contro ls, thus the results of these studies were considered inconclusive by the International Agency for Research on Cancer (IARC, 2000) and the National Toxicology Program (NTP). 39 , 40 The NTP (1999) carried out a chronic inhalation

35 Hazardous Substances Data Bank (HSDB), online data base). US National Library of Medicine, Toxicology Data Network, available online at http://toxnet.nlm.nih. gov/. Carbonyl health effects summary available at http://toxnet.nlm.nih.gov/cgi-bin/sis/search/r?dbs+ hsdb:@term+@rn+@rel+463-58-1.
36 U.S. Environmental Protection Agency (U.S. EPA). 2 000. Integrated Risk Information System File for Ca rbonyl Sulfide. Research and Development, National Center for Environmental Assessment, Washington, DC. Thi s material is available electronically at http://www. epa.gov/iris/subst/0617.htm.
37 Maltoni C, Conti B, Giuliano C and Belpoggi F, 198 5. Experimental studies on benzene carcinogenicity at the Bologna Institute of Oncology: Current results and ongoing research. Am J Ind Med 7:415-446.
38 Maltoni C, Ciliberti A, Pinto C, Soffritti M, Belp oggi F and Menarini L, 1997. Results of long-term e xperimental carcinogenicity studies of the effects of gasoline, correlated fuels, and major gasoline aromatics on rats. Annals NY Acad Sci 837:15-52.
39 International Agency for Research on Cancer (IARC), 2000. Monographs on the Evaluation of Carcinogenic Risks to Humans. Some Industrial Chemicals. Vol. 77, p. 2 27-266. IARC, Lyon, France.4-17

bioassay in mice and rats and found clear evidence of carcinogenic activity in male rats and some evidence in female rats, based on increased inciden ces 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 incid ences of lung alveolar/bronchiolar adenoma or carcinoma were observed in male mice and liver hepa tocellular adenoma or carcinoma in female mice, which provided some evidence of carcinogenic activity in male and female mice (NTP, 1999). IARC (2000) classified ethylbenzene as Group 2B, possibly carcinogenic to humans,
based on the NTP studies.

4.4.5 Mixed xylenes
Short-term inhalation of mixed xylenes (a mixture o f three closely-related compounds) in humans may cause irritation of the nose and throat, nausea, vomiting, gastric irritation, mild transient eye irritation, and neurological effects. 41 Other reported effects include labored breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and kidneys. 42 Long-term inhalation exposure to xylenes in human s has been associated with a number of effects in the nervous system including h eadaches, dizziness, fatigue, tremors, and impaired motor coordination. 43 EPA has classified mixed xylenes in Category D, no t classifiable with respect to human carcinogenicity.

4.4.6 n-Hexane

The studies available in both humans and animals in dicate that the nervous system is the primary target of toxicity upon exposure of n-hexan e via inhalation. There are no data in humans and very limited information in animals about the p otential effects of n-hexane via the oral route. Acute (short-term) inhalation exposure of humans to high levels of hexane causes mild central

40 National Toxicology Program (NTP), 1999. Toxicolog y and Carcinogenesis Studies of Ethylbenzene (CAS N o. 100-41-4) in F344/N Rats and in B6C3F1 Mice (Inhala tion Studies). Technical Report Series No. 466. NIH Publication No. 99-3956. U.S. Department of Health and Human Services, Public Health Service, National Institutes of Health. NTP, Research Triangle Park, NC.
41 U.S. Environmental Protection Agency (U.S. EPA). 2 003. Integrated Risk Information System File for Mi xed Xylenes. Research and Development, National Center for Environmental Assessment, Washington, DC. Thi s material is available electronically at http://www. epa.gov/iris/subst/0270.htm.
42 Agency for Toxic Substances and Disease Registry ( ATSDR), 2007. The Toxicological Profile for xylene is available electronically at http://www.atsdr.cdc.go v/ToxProfiles/TP.asp?id=296&tid=53.
43 Agency for Toxic Substances and Disease Registry ( ATSDR), 2007. The Toxicological Profile for xylene is available electronically at http://www.atsdr.cdc.go v/ToxProfiles/TP.asp?id=296&tid=53.4-18

nervous system effects, including dizziness, giddin ess, slight nausea, and headache. Chronic (long-term) exposure to hexane in air causes numbne ss in the extremities, muscular weakness, blurred vision, headache, and fatigue. Inhalation studies in rodents have reported behavioral effects, neurophysiological changes and neuropathol ogical effects upon inhalation exposure to nhexane. Under the Guidelines for Carcinogen Risk A ssessment (U.S. EPA, 2005), the database for n-hexane is considered inadequate to assess hum an carcinogenic potential, therefore the EPA has classified hexane in Group D, not classifiable as to human carcinogenicity. 44

4.4.7 Other Air Toxics
In addition to the compounds described above, other toxic compounds might be affected by these rules, including hydrogen sulfide (H 2 S). Information regarding the health effects of those compounds can be found in EPA’s IRIS database

. 45

4.5 VOCs

4.5.1 VOCs as a PM2.5 precursor
This rulemaking would reduce emissions of VOCs, whi ch are a precursor to PM 2.5. Most VOCs emitted are oxidized to carbon dioxide (CO 2 ) rather than to PM, but a portion of VOC
emission contributes to ambient PM 2.5 levels as organic carbon aerosols (U.S. EPA, 2009a)

. Therefore, reducing these emissions would reduce PM 2.5 formation, human exposure to PM 2.5 , and the incidence of PM 2.5 -related health effects. However, we have not quan tified the PM 2.5 - related benefits in this analysis. Analysis of organic car bon measurements suggest only a fraction of secondarily formed organic carbon aeros ols are of anthropogenic origin. The current state of the science of secondary organic carbon ae rosol formation indicates that anthropogenic VOC contribution to secondary organic carbon aeroso l is often lower than the biogenic (natural) contribution. Given that a fraction of secondarily formed organic carbon aerosols is from anthropogenic VOC emissions and the extremely small amount of VOC emissions from this sector relative to the entire VOC inventory it is u nlikely this sector has a large contribution to

44 U.S. EPA. 2005. Guidelines for Carcinogen Risk Ass essment. EPA/630/P-03/001B. Risk Assessment Forum, Washington, DC. March. Available on the Internet a t <http://www.epa.gov/ttn/atw/cancer_guidelines_fin al_3- 25-05.pdf>.
45 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris4-19

ambient secondary organic carbon aerosols. Photoch emical 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 sch edule, we were unable to perform air quality modeling for this rule. Due to the high de gree of variability in the responsiveness of
PM 2.5 formation to VOC emission reductions, we are unable to estimate the effect that reducing
VOCs 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 avoidi ng mortality and respiratory morbidity.
Researchers have associated PM 2.5 - exposure with adverse health effects in numerous toxicological, clinical and epidemiological studies (U.S. EPA, 2009a). When adequate data and resources are available, EPA generally quantifies s everal health effects associated with exposure
to PM 2.5 (e.g., U.S. EPA (2010c)). These health effects inc lude premature mortality for adults and infants, cardiovascular morbidity such as heart attacks, hospital admissions, and respiratory morbidity such as asthma attacks, acute and chronic bronchitis, hospital and ER visits, work loss days, restricted activity days, and respiratory sym ptoms. Although EPA has not quantified these effects in previous benefits analyses, the scientif ic literature suggests that exposure to PM 2.5 is also associated with adverse effects on birth weigh t, pre-term births, pulmonary function, other cardiovascular effects, and other respiratory effec ts (U.S. EPA, 2009a).

EPA assumes that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the s cientific evidence is not yet sufficient to allow differentiation of effect estimates by partic le type (U.S. EPA, 2009a). Based on our review of the current body of scientific literature , EPA estimates PM-related mortality without applying an assumed concentration threshold. This decision is supported by the data, which are quite consistent in showing effects down to the low est measured levels of PM 2.5 in the underlying epidemiology studies.4-20

Previous studies have estimated the monetized benef its-per-ton of reducing VOC
emissions associated with effect that those emissio ns have on ambient PM 2.5 levels and the health
effects associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009). Using the estimates in Fann, Fulcher, and Hubbell (2009), the monetized benefit-per-ton of reducing VOC emissions in nine urban areas of the U.S. ranges from $560 in Seattle, WA to $5,700 in San Joaquin, CA, with a national average of $2,400. These estimates assume a 50 percent reduction in VOCs, the Laden et al. (2006) mortality function (based on th e Harvard Six City Study, a large cohort epidemiology study in the Eastern U.S.), an analysi s year of 2015, and a 3 percent discount rate.

Based on the methodology from Fann, Fulcher, and Hu bbell (2009), we converted their estimates to 2008$ and applied EPA’s current VSL es timate. 46 After these adjustments, the range of values increases to $680 to $7,000 per ton of VO C reduced for Laden et al. (2006). Using alternate assumptions regarding the relationship be tween PM 2.5 exposure and premature mortality from empirical studies and supplied by experts (Pop e et al., 2002; Laden et al., 2006; Roman et al., 2008), additional benefit-per-ton estimates ar e available from this dataset, as shown in Table 4-6. EPA generally presents a range of benefits es timates derived from Pope et al. (2002) to Laden et al. (2006) because they are both well-desi gned 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 th e range of benefits based on epidemiology studies, this study also provided a range of benefi ts associated with reducing emissions in eight specific urban areas. The range of VOC benefits th at 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 pro vide useful context for the break-even analysis, the geographic distribution of VOC emissi ons from the oil and gas sector are not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition, the benefit-per-ton estimates for VOC emission reductio ns in that study are derived from total VOC emissions across all sectors. Coupled with the lar ger uncertainties about the relationship

46 For more information regarding EPA’s current VSL e stimate, please see Section 5.4.4.1 of the RIA for the proposed Federal Transport Rule (U.S. EPA, 2010a). EPA continues to work to update its guidance on va luing mortality risk reductions.4-21

between VOC emissions and PM 2.5 , these factors lead us to conclude that the availa ble VOC benefit per ton estimates are not appropriate to ca lculate monetized benefits of these rules, even as a bounding exercise.4-22Table 4-6 Monetized Benefits-per-Ton Estimates forVOCs (2008$)AreaPope etal.Laden etal.ExpertAExpertBExpertCExpertDExpertEExpertFExpertGExpertHExpertIExpertJExpertKExpertLAtlanta $620 $1,500 $1,600 $1,200 $1,200 $860 $2,000 $1,100 $730 $920 $1,200$980 $250 $940Chicago $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 $2,400Dallas $300 $740 $780 $610 $590 $420 $960 $540 $360$450 $590 $480 $120 $460Denver $720 $1,800 $1,800 $1,400 $1,400 $1,000 $2,300 $1,300 $850 $1,100 $1,400$1,100 $280 $850NYC/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 $3,100Phoenix $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 $1,500Salt 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 $2,000San 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 $4,400Seattle $280 $680 $720 $530 $550 $390 $890 $500 $330 $420 $550 $450 $110 $330National 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 inVOC emissions, an analysis year of 2015, and a 3 percent discount rate. All estimates are rounded totwosignificant digits. These estimates have been updated from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currency year and EPA’s current VSLestimate. Using a discount rate of 7 percent, thebenefit-per-ton estimates would be approximately 9percent lower. Assuming a 75 percent reduction inVOCemissions would increase the benefit-per-ton estimates by approximately 4 percent to 52 percent. Assuming a 25 percent reduction in VOC emissions woulddecrease the benefit-per-ton estimates by 5 percentto 52 percent. EPA generally presents a range ofbenefits estimates derived from Pope et al. (2002)toLaden et al. (2006) and provides the benefits estimates derived from the expert functions from Roman et al. (2008) as a characterization of uncertainty.4-23

4.5.3 Organic PM welfare effects According to the residual risk assessment for this sector (U.S. EPA, 2011a), persistent and bioaccumulative HAP reported as emissions from oil and gas operations include polycyclic organic matter (POM). POM defines a broad class of compounds that includes the polycyclic aromatic hydrocarbon compounds (PAHs). Several sig nificant ecological effects are associated with deposition of organic particles, including per sistent organic pollutants, and PAHs (U.S. EPA, 2009a).

PAHs can accumulate in sediments and bioaccumulate in freshwater, flora, and fauna. The uptake of organics depends on the plant species , site of deposition, physical and chemical properties of the organic compound and prevailing e nvironmental conditions (U.S. EPA, 2009a). PAHs can accumulate to high enough concentrations i n some coastal environments to pose an
environmental health threat that includes cancer in fish populations, toxicity to organisms living in the sediment and risks to those (e.g., migratory birds) that consume these organisms. Atmospheric deposition of particles is thought to b e the major source of PAHs to the sediments of coastal areas of the U.S. Deposition of PM to s urfaces in urban settings increases the metal and organic component of storm water runoff. This atmospherically-associated pollutant burden can then be toxic to aquatic biota. The contributi on of atmospherically deposited PAHs to aquatic food webs was demonstrated in high elevatio n mountain lakes with no other anthropogenic contaminant sources.

The recently completed Western Airborne Contaminant s Assessment Project (WACAP) is the most comprehensive database on contaminant t ransport and PM depositional effects on sensitive ecosystems in the Western U.S. (Landers e t al., 2008). In this project, the transport, fate, and ecological impacts of anthropogenic conta minants from atmospheric sources were assessed from 2002 to 2007 in seven ecosystem compo nents (air, snow, water, sediment, lichen, conifer needles, and fish) in eight core national p arks. The study concluded that bioaccumulation of semi-volatile organic compounds occurred through out park ecosystems, an elevational gradient in PM deposition exists with greater accum ulation in higher altitude areas, and contaminants accumulate in proximity to individual agriculture and industry sources, which is4-24

counter to the original working hypothesis that mos t of the contaminants would originate from Eastern Europe and Asia.

4.5.4 Visibility Effects
Reducing secondary formation of PM 2.5 would improve visibility throughout the U.S. Fine particles with significant light-extinction ef ficiencies include sulfates, nitrates, organic carbon, elemental carbon, and soil (Sisler, 1996). Suspended particles and gases degrade visibility by scattering and absorbing light. Highe r visibility impairment levels in the East are due to generally higher concentrations of fine part icles, particularly sulfates, and higher average relative humidity levels. Visibility has direct si gnificance to people’s enjoyment of daily activities and their overall sense of wellbeing. G ood visibility increases the quality of life where individuals live and work, and where they engage in recreational activities. Previous analyses (U.S. EPA, 2006b; U.S. EPA, 2010c; U.S. EPA, 2011a) show that visibility benefits are a significant welfare benefit category. Without air quality modeling, we are unable to estimate visibility related benefits, nor are we able to det ermine whether VOC emission reductions would be likely to have a significant impact on visibilit y in urban areas or Class I areas.

4.6 VOCs as an Ozone Precursor
This rulemaking would reduce emissions of VOCs, whi ch are also precursors to secondary formation of ozone. Ozone is not emitted directly into the air, but is created when its two primary components, volatile organic compounds (VOC) and oxides of nitrogen (NOx), combine in the presence of sunlight. In urban area s, compounds representing all classes of VOCs and CO are important compounds for ozone forma tion, but biogenic VOCs emitted from vegetation tend to be more important compounds in n on-urban vegetated areas (U.S. EPA, 2006a). Therefore, reducing these emissions would reduce ozone formation, human exposure to ozone, and the incidence of ozone-related health ef fects. However, we have not quantified the
ozone-related benefits in this analysis for several reasons. Fir st, previous rules have shown that the monetized benefits associated with reducing ozo ne exposure are generally smaller than PMrelated benefits, even when ozone is the pollutant targeted for control (U.S. EPA, 2010a). Second, the complex non-linear chemistry of ozone f ormation introduces uncertainty to the development and application of a benefit-per-ton es timate. Third, the impact of reducing VOC4-25

emissions is spatially heterogeneous depending on l ocal air chemistry. Urban areas with a high population concentration are often VOC-limited, whi ch means that ozone is most effectively reduced by lowering VOCs. Rural areas and downwind suburban areas are often NOx-limited,
which means that ozone concentrations are most effe ctively reduced by lowering NOx emissions, rather than lowering emissions of VOCs. Between these areas, ozone is relatively insensitive to marginal changes in both NOx and VOC

.

Due to time limitations under the court-ordered sch edule, we were unable to perform air quality modeling for this rule. Due to the high de gree of variability in the responsiveness of

ozone formation to VOC emission reductions, we are unable to estimate the effect that reducing
VOCs will have on ambient ozone concentrations with out air quality modeling.

4.6.1 Ozone health effects and valuation
Reducing ambient ozone concentrations is associated with significant human health benefits, including mortality and respiratory morbi dity (U.S. EPA, 2010a). Epidemiological researchers have associated ozone exposure with adv erse health effects in numerous toxicological, clinical and epidemiological studies (U.S. EPA, 2006c). When adequate data and resources are available, EPA generally quantifies s everal 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 emer gency department visits, school loss days, as well as premature mortality. Although EPA has not q uantified these effects in benefits analyses previously, the scientific literature is suggestive that exposure to ozone is also associated with chronic respiratory damage and premature aging of t he lungs.

In a recent EPA analysis, EPA estimated that reduci ng 15,000 tons of VOCs from industrial boilers resulted in $3.6 to $15 million of monetized benefits from reduced ozone exposure (U.S. EPA, 2011b). 47 This implies a benefit-per-ton for ozone reductio ns of $240 to $1,000 per ton of VOCs reduced. While these ranges of benefit-per-ton estimates provide useful context, the geographic distribution of VOC emissio ns from the oil and gas sector are not
consistent with emissions modeled in the boiler ana lysis. Therefore, we do not believe that those

47 While EPA has estimated the ozone benefits for man y scenarios, most of these scenarios also reduce NO x emissions, which make it difficult to isolate the b enefits attributable to VOC reductions.4-26

estimates to provide useful estimates of the moneti zed benefits of these rules, even as a bounding
exercise.

4.6.2 Ozone vegetation effects
Exposure to ozone has been associated with a wide a rray of vegetation and ecosystem effects in the published literature (U.S. EPA, 2006 a). Sensitivity to ozone is highly variable across species, with over 65 plan species identifie d as “ozone-sensitive”, many of which occur in state and national parks and forests. These effect s include those that damage or impair the intended use of the plant or ecosystem. Such effec ts are considered adverse to the public welfare and can include reduced growth and/or biomass produ ction in sensitive plant species, including forest trees, reduced crop yields, visible foliar i njury, reduced plant vigor (e.g., increased susceptibility to harsh weather, disease, insect pe st infestation, and competition), species composition shift, and changes in ecosystems and as sociated ecosystem services.

4.6.3 Ozone climate effects
Ozone is a well-known short-lived climate forcing ( SLCF) greenhouse gas (GHG) (U.S. EPA, 2006a). Stratospheric ozone (the upper ozone layer) is beneficial because it protects life on Earth from the sun’s harmful ultraviolet (UV) radia tion. In contrast, tropospheric ozone (ozone in the lower atmosphere) is a harmful air pollutant that adversely affects human health and the environment and contributes significantly to region al and global climate change. Due to its short atmospheric lifetime, tropospheric ozone concentrat ions exhibit large spatial and temporal variability (U.S. EPA, 2009b). A recent United Nati ons 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 contribut ed climate change behind CO 2 and methane. This discernable influence of ground level ozone on climate leads to increases in global surface temperature and changes in hydrological cycles. Thi s study provides the most comprehensive analysis to date of the benefits of measures to red uce SLCF gases including methane, ozone, and black carbon assessing the health, climate, and agr icultural benefits of a suite of mitigation technologies. The report concludes that the climate is changing now, and these changes have the potential to “trigger abrupt transitions such as th e release of carbon from thawing permafrost and biodiversity loss” (UNEP 2011). While reducing lon g-lived GHGs such as CO 2 is necessary to4-27

protect against long-term climate change, reducing SLCF gases including ozone is beneficial and will slow the rate of climate change within the fir st half of this century (UNEP 2011).

4.7 Methane (CH 4 )

4.7.1 Methane as an ozone precursor
This rulemaking would reduce emissions of methane, a long-lived GHG and also a precursor to ozone. In remote areas, methane is a dominant precursor t o tropospheric ozone formation (U.S. EPA, 2006a). Unlike NOx and VOCs, which affect ozone concentrations regionally and at hourly time scales, methane emiss ion reductions require several decades for the ozone response to be fully realized, given methane’ s relatively long atmospheric lifetime (HTAP, 2010). Studies have shown that reducing methane ca n reduce global background ozone concentrations over several decades, which would be nefit both urban and rural areas (West et al., 2006). Therefore, reducing these emissions would r educe ozone formation, human exposure to ozone, and the incidence of ozone-related health ef fects. The health, welfare, and climate effects associated with ozone are described in the precedin g sections. Without air quality modeling, we are unable to estimate the effect that reducing met hane will have on ozone concentrations at particular locations.

4.7.2 Methane climate effects and valuation
Methane is the principal component of natural gas. Methane is also a potent greenhouse gas (GHG) that once emitted into the atmosphere abs orbs terrestrial infrared radiation which contributes to increased global warming and continu ing climate change. Methane reacts in the atmosphere to form ozone and ozone also impacts glo bal temperatures. According to the Intergovernmental Panel on Climate Change (IPCC) Fo urth Assessment Report (2007), in 2004 the cumulative changes in methane concentrations si nce preindustrial times contributed about 14 percent to global warming due to anthropogenic GHG sources, making methane the second leading long-lived climate forcer after CO 2 globally. Methane, in addition to other GHG emissions, contributes to warming of the atmosphere which over time leads to increased air and ocean temperatures, changes in precipitation patter ns, melting and thawing of global glaciers and ice, increasingly severe weather events, such as hu rricanes of greater intensity, and sea level rise, among other impacts.4-28

Processes in the oil and gas category emit signific ant amounts of methane. The Inventory
of U.S. Greenhouse Gas Emissions and Sinks: 1990-20 09 (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). In 2009, total methane emissions from the oil and gas industry represented nearly 40 perc ent 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 systems being the single largest c ontributor to U.S. anthropogenic methane emissions (U.S. EPA, 2011b, Table ES-2). It is imp ortant to note that the 2009 emissions estimates from well completions and recompletions e xclude a significant number of wells completed in tight sand plays and the Marcellus Sha le, due to availability of data when the 2009 Inventory was developed. The estimate in this prop osal includes an adjustment for tight sand plays and the Marcellus Shale, and such an adjustme nt is also being considered as a planned improvement in next year's Inventory. This adjustme nt would increase the 2009 Inventory estimate by about 80 MMtCO 2 -e. The total methane emissions from Petroleum and Natural Gas Systems based on the 2009 Inventory, adjusted for t ight sand plays and the Marcellus Shale, is approximately 330 MMtCO 2 -e.

This rulemaking proposes emission control technolog ies and regulatory alternatives that will significantly decrease methane emissions from the oil and natural gas sector in the United States. The regulatory alternative proposed for th is rule is expected to reduce methane emissions annually by about 3.4 million short tons or approxi mately 65 million metric tons CO 2 -e. These reductions represent about 26 percent of the GHG em issions 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 62 million metric tons when the secondary impacts a ssociated with increased combustion and supplemental energy use on the producer side and CO 2 -e emissions from changes in consumption patterns previously discussed are consi dered. However, it is important to note the emissions reductions are based upon predicted activ ities in 2015; EPA did not forecast sectorlevel emissions to 2015 for this rulemaking. The c limate co-benefit from these reductions are4-29

equivalent of taking approximately 11 million typic al passenger cars off the road or eliminating electricity use from about 7 million typical homes each year. 48

EPA estimates the social benefits of regulatory act ions 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 emissions in a given year (or from the alternative perspective, the benefit to society of reducing CO 2 emissions by one ton). The SCC includes (but is no t limited to) climate damages due to changes in net agricultural producti vity, human health, property damages from flood risk, and ecosystem services due to climate c hange. The SCC estimates currently used by the Agency were developed through an interagency pr ocess that included EPA and other executive branch entities, and concluded in Februar y 2010. The Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysi s Under Executive Order 12866 for the final joint EPA/Department of Transportation Rulema king to establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Ave rage Fuel Economy Standards provides a complete discussion of the methods used to develo p the SCC estimates (Interagency Working Group on 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 anal yses: $6, $25, $40, and $76 per metric ton of
CO 2 emissions in 2015, in 2008 dollars. The first thre e values are based on the average SCC estimated using three integrated assessment models (IAMs), at discount rates of 5.0, 3.0, and 2.5 percent, respectively. When valuing the impacts of climate change, IAMs couple economic and climate systems into a single model to capture impo rtant interactions between the components. SCCs estimated using different discount rates are i ncluded because the literature shows that the SCC is quite sensitive to assumptions about the dis count rate, and because no consensus exists on the appropriate rate to use in an intergeneratio nal context. The fourth value is the 95th percentile of the distribution of SCC estimates fro m all three models at a 3.0 percent discount rate. It is included to represent higher-than-expec ted damages from temperature change further
out in the tails of the SCC distribution.

48 US Environmental Protection Agency. Greenhouse Ga s Equivalency Calculator available at: http://www.epa.gov/cleanenergy/energy-resources/cal culator.html accessed 07/19/11.4-30

Although there are relatively few region- or countr y-specific estimates of SCC in the literature, the results from one model suggest the ratio of domestic to global benefits of emission reductions varies with key parameter assumptions. F or example, with a 2.5 or 3 percent discount rate, the U.S. benefit is about 7-10 percent of the global benefit, on average, across the scenarios analyzed. Alternatively, if the fraction of GDP los t due to climate change is assumed to be similar across countries, the domestic benefit woul d be proportional to the U.S. share of global GDP, which is currently about 23 percent. On the ba sis of this evidence, values from 7 to 23 percent should be used to adjust the global SCC to calculate domestic effects. It is recognized that these values are approximate, provisional, and highly speculative. There is no a priori reason why domestic benefits should be a constant fraction of net global damages over time. (Interagency Working Group on Social Cost of Carbon , 2010).

The interagency group noted a number of limitations to the SCC analysis, including the incomplete way in which the integrated assessment m odels capture catastrophic and noncatastrophic impacts, their incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk aversion. The limited amount of research linking cl imate impacts to economic damages makes estimating damages from climate change even more di fficult. The interagency group hopes that
over time researchers and modelers will work to fil l these gaps and that the SCC estimates used for regulatory analysis by the Federal government w ill continue to evolve with improvements in modeling. Additional details on these limitations a re discussed in the SCC TSD.

A significant limitation of the aforementioned inte ragency process particularly relevant to this rulemaking is that the social costs of non-CO 2 GHG emissions were not estimated. Specifically, the interagency group did not directl y estimate the social cost of non-CO 2 GHGs using the three models. Moreover, the group determ ined 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 is4-31

typically done using the GWPs for the non-CO 2 gas. The GWP is an aggregate measure that approximates the additional energy trapped in the a tmosphere over a given timeframe from a perturbation of a non-CO 2 gas relative to CO 2 . The time horizon most commonly used is 100 years. One potential problem with utilizing tempor ally aggregated statistics, such as the GWPs, is that the additional radiative forcing from the G HG perturbation is not constant over time and any differences in temporal dynamics between gases will be lost. This is a potentially confounding issue given that the social cost of GHG s is based on a discounted stream of damages that are non-linear in temperature. For exa mple, methane has an expected adjusted atmospheric lifetime of about 12 years and associat ed GWP of 21 (IPCC Second Assessment Report (SAR) 100-year GWP estimate). Gases with a shorter lifetime, such as methane, have impacts that occur primarily in the near term and t hus are not discounted as heavily as those caused by the longer-lived gases, while the GWP tre ats additional forcing the same independent of when it occurs in time. Furthermore, the baseli ne temperature change is lower in the near term and therefore the additional warming from rela tively short lived gases will have a lower marginal impact relative to longer lived gases that have an impact further out in the future when baseline warming is higher. The GWP also relies on an arbitrary time horizon and constant
concentration scenario. Both of which are inconsis tent with the assumptions used by the SCC interagency workgroup. Finally, impacts other than temperature change also vary across gases in ways that are not captured by GWP. For instance, C O 2 emissions, unlike methane will result in
CO 2 passive fertilization to plants.

In light of these limitations, and the significan t contributions of non-CO 2 emissions to climate change, further analysis is required to lin k non-CO 2 emissions to economic impacts and to develop social cost estimates for methane specif ically. Such work would feed into efforts to develop a monetized value of reductions in methane greenhouse gas emissions in assessing the co-benefits of this rulemaking. As part of ongoing work to further improve the SCC estimates, the interagency group hopes to develop methods to v alue greenhouse gases other than CO 2 , such as methane, by the time SCC estimates for CO 2 emissions are revised.

The EPA recognizes that the methane reductions pro posed in this rule will provide significant economic climate co-benefits to society . However, EPA finds itself in the position of4-32

having no interagency accepted monetary values to p lace on these co-benefits. The ‘GWP approach’ of converting methane to CO 2 -e using the GWP of methane, as previously describe d, is one approximation method for estimating the mone tized value of the methane reductions anticipated from this rule. This calculation uses the GWP of the non-CO 2 gas to estimate CO 2 equivalents and then multiplies these CO 2 equivalent emission reductions by the SCC to gener ate monetized estimates of the co-benefits. If one mak es these calculations for the proposed Option 2 (including expected methane emission reductions f rom the NESHAP amendments and NSPS and considers secondary impacts) of the oil and gas rule, the 2015 co-benefits vary by discount rate and range from about $373 million to over $4.7 billion; the SCC at the 3 percent discount rate ($25 per metric ton) results in an estimate of $1.6 billion in 2015. These co-benefits equate to a range of approximately $110 to $1,400 per shor t ton of methane reduced depending upon the discount rate assumed with a per ton estimate of $4 80 at the 3 percent discount rate

As previously stated, these co-benefit estimates a re not the same as would be derived using a directly computed social cost of methane (u sing the integrated assessment models employed to develop the SCC estimates) for a variet y of reasons including the shorter atmospheric lifetime of m ethane relative to CO 2 (about 12 years compared to CO 2 whose concentrations in the atmosphere decay on timescale s of decades to millennia). The climate impacts also differ between the pollutants for reas ons other than the radiative forcing profiles and atmospheric lifetimes of these gases. Methane is a precursor to ozone and ozone is a short-lived climate forcer as previously discussed. This use of the SAR GWP to approximate benefits may underestimate the direct radiative forcing benefits of reduced ozone levels, and does not capture any secondary climate co-benefits involved with ozo ne-ecosystem interactions. In addition, a recent NCEE working paper suggests that this quick ‘GWP approach’ to benefits estimation will likely understate the climate benefits of methane r eductions in most cases (Marten and Newbold, 2011). This conclusion is reached using the 100 ye ar GWP for methane of 25 as put forth in the IPCC Fourth Assessment Report as opposed to the low er value of 21 used in this analysis. Using the higher GWP estimate of 25 would increase these reported methane climate co-benefit estimates by about 19 percent. Although the IPCC F ourth Assessment Report suggested a GWP of 25, EPA has used GWP of 21 consistent with the I PCC SAR to estimate the methane climate co-benefits for this oil and gas proposal. The use of the SAR GWP values allows comparability4-33

of data collected in this proposed rule to the nati onal GHG inventory that EPA compiles annually
to meet U.S. commitments to the United Nations Fram ework Convention on Climate Change ( UNFCCC). To comply with international reporting sta ndards under the UNFCCC, official emission estimates are to be reported by the U.S. a nd other countries using SAR GWP values. The UNFCCC reporting guidelines for national invent ories were updated in 2002 but continue to require the use of GWPs from the SAR. The parties t o the UNFCCC have also agreed to use GWPs based upon a 100-year time horizon although ot her time horizon values are available. The SAR GWP value for methane is also currently use d to establish GHG reporting requirements as mandated by the GHG Reporting Rule (2010e) and i s used by the EPA to determine Title V and Prevention of Significant Deterioration GHG per mitting requirements as modified by the GHG Tailoring Rule (2010f).

EPA also undertook a literature search for estimat es of the marginal social cost of methane. A range of marginal social cost of methan e benefit estimates are available in published literature (Fankhauser (1994), Kandlikar (1995), Ha mmitt 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 inconsisten t with the current SCC estimates. Some of these studies focused on marginal methane reduction s in the 1990s and early 2000s and report estimates for only the single year of interest spec ific to the study. The assumptions underlying
the social cost of methane estimates available in t he literature differ from those agreed upon by the SCC interagency group and in many cases use old er versions of the IAMs. Without additional analysis, the methane climate benefit es timates available in the current literature are not acceptable to use to value the methane reductio ns proposed in this rulemaking.

Due to the uncertainties involved with ‘GWP approa ch’ estimates presented and estimates available in the literature, EPA chooses not to compare these co-benefit estimates to the costs of the rule for this proposal. Rather, t he EPA presents the ‘GWP approach’ climate cobenefit estimates as an interim method to produce l ower-bound estimates until the interagency group develops values for non-CO 2 GHGs. EPA requests comments from interested parti es and the public about this interim approach specifically and more broadly about appropriate methods
to monetize the climate co-benefits of methane redu ctions. In particular, EPA seeks public comments to this proposed rulemaking regarding soci al cost of methane estimates that may be4-34

used to value the co-benefits of methane emission r eductions anticipated for the oil and gas industry from this rule. Comments specific to whet her GWP is an acceptable method for generating a placeholder value for the social cost of methane until interagency modeled estimates become available are welcome. Public comments may b e provided in the official docket for this proposed rulemaking in accordance with the process outlined in the preamble for the rule. These comments will be considered in developing the final rule for this rulemaking.

4.8 References

Fankhauser, S. 1994. “The social costs of greenhous e gas emissions: an expected value approach.” Energy Journal 15(2):157–184.

Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. “The in fluence of location, source, and emission type in estimates of the human health benefits of r educing a ton of air pollution.” Air Qual Atmos Health 2:169-176.
Forster, P. et al. 2007. Changes in Atmospheric Constituents and in Radiativ e Forcing. In: Climate Change 2007. The Physical Science Basis. Contribution of Working Group I to the Fourth Assessment Report of the Intergovernment al Panel on Climate Change [Solomon, S., D. Qin, M. Manning, Z. Chen, M. Marqu is, K.B. Averyt, M. Tignor and H.L. Miller (eds.)]. Cambridge University Press, Ca mbridge, United Kingdom and New York, NY, USA.
Gwinn, M.R., J. Craig, D.A. Axelrad, R. Cook, C. Do ckins, 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 cons iderations.” Environ Health Perspect . 119(1): p. 125-30.
Hammitt, J.K., A.K. Jain, J.L. Adams, and D.J. Wueb bles. 1996. “A welfare-based index for assessing environmental effects of greenhouse-gas e missions.” Nature , 381(6580):301– 303, 1996. Hope, C. 2005. “The climate change benefits of redu cing methane emissions.” Climatic Change 68(1):21–39.

Hope, C. and D. Newbery. 2006. “Calculating the Soc ial Cost of Carbon” Forthcoming in Delivering a Low Carbon Electricity System: Technol ogies, Economics and Policy Editors: Michael Grubb, Tooraj Jamasb and Michael G . Pollitt (University of Cambridge) Cambridge University Press. Available on the Inter net at <http://www.dspace.cam.ac.uk/handle/1810/194738> Ac cessed March 30, 2011.4-35

Industrial Economics, Inc (IEc). 2009. Section 812 Prospective Study of the Benefits and C osts of the Clean Air Act: Air Toxics Case Study—Health Ben efits of Benzene Reductions in Houston, 1990–2020. Final Report , July 14, 2009. <http://www.epa.gov/air/sect812/dec09/812CAAA_Benze ne_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 Impa ct Analysis Under Executive Order 12866. Docket ID EPA-HQ-OAR-2009-0472-114577. Participatio n by Council of Economic Advisers, Council on Environmental Quality , Department of Agriculture, Department of Commerce, Department of Energy, Depar tment of Transportation, Environmental Protection Agency, National Economic Council, Office of Energy and Climate Change, Office of Management and Budget, Of fice 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 (IPCC). 2 007. Climate Change 2007: Synthesis 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, Switze rland, 104 pp. <http://www.ipcc.ch/publications_and_data/publicati ons_ipcc_fourth_assessment_report _synthesis_report.htm>. Accessed March 30, 2011/
Intergovernmental Panel on Climate Change (IPCC). 2 007. IPCC Fourth Assessment Report: Climate Change 2007. Working Group II, Chapter 20 ‘ Perspectives on Climate Change and Sustainability.’ <http://www.ipcc.ch/publications_and_data/ar4/wg2/ en/ch20s20-6-1.html> Accessed March 30, 2011.
Kandlikar, M. 1995. “The relative role of trace gas emissions in greenhouse abatement policies.” Energy Policy 23(10): 879–883.
Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dock ery. 2006. “Reduction in Fine Particulate Air Pollution and Mortality.” American Journal of Respiratory and Critical Care Medicine 173:667-672.
Landers DH; Simonich SL; Jaffe DA; Geiser LH; Campb ell DH; Schwindt AR; Schreck CB; Kent ML; Hafner WD; Taylor HE; Hageman KJ; Usenko S ; Ackerman LK; Schrlau JE; Rose NL; Blett TF; Erway MM. 2008. The Fate, Transport and Ecological Impacts of Airborne Contaminants in Western National Parks (US A) . EPA/600/R-07/138. U.S. Environmental Protection Agency, Office of Research and Development, NHEERL, Western Ecology Division. Corvallis, Oregon.
Marten, A. and S. Newbold. 2011. “Estimating the So cial Cost of Non-CO 2 GHG Emissions: Methane and Nitrous Oxide.” NCEE Working Paper Series # 11-01. <http://yosemite.epa.gov/ee/epa/eed.nsf/WPNumber/20 11- 01?opendocument>. Accessed March 30, 2011.4-36

Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Call e, D. Krewski, K. Ito, and G.D. Thurston. 2002. “Lung Cancer, Cardiopulmonary Mortality, and Long-term Exposure to Fine Particulate Air Pollution.” Journal of the American Medical Association 287:1132-1141.
Roman, H.A., K.D. Walker, T.L. Walsh, L. Conner, H. M. Richmond, .J. Hubbell, and P.L. Kinney. 2008. “Expert Judgment Assessment of the Mo rtality Impact of Changes in Ambient Fine Particulate Matter in the U.S.” Environ. Sci. Technol . 42(7):2268-2274.
Task Force on Hemispheric Transport of Air Pollutio n (HTAP). 2010. Hemispheric Transport of Air Pollution 2010 . Informal Document No.10. Convention on Long-range Transboundary Air Pollution Executive Body 28th Ses sion. ECE/EB.AIR/2010/10 (Corrected). Chapter 4, pp. 148-149.
Tol, R. (2006). NEEDS Project 502687 ‘New Energy Ex ternalities Developments for Sustainability Integrated Project’ < http://www.needsproject.org/RS1b/NEEDS_RS1B_TP_T5.4_T5.5.pdf>. Acc essed March 30, 2011.

Tol, R, R.J. Heintz, and P.E.M. Lammers. 2003. “Met hane emission reduction: An application of FUND.” Climatic Change 57(1):71–98.
U.S. Environmental Protection Agency (U.S. EPA). 2 006a . Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington, DC: U.S. EPA. <http://cfpub.epa.gov/ncea/CFM/recordisp lay.cfm?deid=149923>. Accessed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 2 006b. Regulatory Impact Analysis, 2006 National Ambient Air Quality Standards for Particul ate Matter , Chapter 5. Office of Air Quality Planning and Standards, Research Triangle P ark, NC. <http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%2 05--Benefits.pdf>. Accessed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 19 95. Regulatory Impact Analysis for the Petroleum Refinery NESHAP. Revised Draft for Promul gation . Office of Air Quality Planning and Standards, Research Triangle Park, N.C . <http://www.regmarkets.org/admin/authorpdfs/page.php?id=705>. Acce ssed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 20 09a. Integrated Science Assessment for Particulate Matter

(Final Report). EPA-600-R-08-139F. National Center for Environmental Assessment—RTP Division. <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?dei d=216546>. Accessed March 30, 2011. U.S. Environmental Protection Agency (U.S. EPA). 20 09b. Technical Support Document for Proposed Endangerment and Cause or Contribute Findi ngs for Greenhouse Gases under Section 202(a) of the Clean Air Act

. <http://www.epa.gov/climatechange/endangerment/down loads/Endangerment%20TSD.p d>. Accessed March 30, 2011.4-37

U.S. Environmental Protection Agency (U.S. EPA). 20 10a. Regulatory Impact Analysis, National Ambient Air Quality Standards for Ozone. Office of Air Quality Planning and Standards, Research Triangle Park, NC. <http://www. epa.gov/ttn/ecas/regdata/RIAs/s1- supplemental_analysis_full.pdf>. Accessed March 30, 2011. U.S. Environmental Protection Agency (U.S. EPA). 20 11b. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009. EPA 430-R-11-005. Office of Atmospheric Programs, Washington, DC. <http://epa.gov/climatechange/emis sions/usinventory.html >. Accessed July 21, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 20 10c. Regulatory Impact Analysis for the Proposed Federal Transport Rule. Office of Air Quality Planning and Standards, Research Triangle Park, NC. <http://www.epa.gov/ttn/ecas/regdata/RIAs/proposalt rria_final.pdf>. Accessed March 30, 2011. U.S. Environmental Protection Agency (U.S. EPA). 20 10d. Regulatory Impact Analysis for the SO 2 NAAQS. Office of Air Quality Planning and Standards, Rese arch Triangle Park, NC. < http://www.epa.gov/ttn/ecas/regdata/RIAs/fso2ria1 00602full.pdf>. Accessed March 30, 2011. U.S Environmental Protection Agency (U.S. EPA). 201 1a. 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). 20 10e. 40 CFR Part 98 Mandatory Reporting of Greenhouse Gases: Petroleum and Natura l Gas Systems; Final Rule. Federal Register Vol. 75, No. 229, November 30, 2010. 74458 -74515. r< <http://edocket.access.gpo.gov/2010/pdf/2010-28655. pdf> Accessed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 2 010f. Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule. Federal Register Vol. 75, No. 106, June 3, 2010. 31514-31608 <http://www.gpo.gov /fdsys/pkg/FR-2010-06- 03/pdf/2010-11974.pdf#page=1> Accessed March 30, 20 11.
U.S. Environmental Protection Agency (U.S. EPA). 20 11a. The Benefits and Costs of the Clean Air Act from 1990 to 2020 . Office of Air and Radiation, Washington, DC. Mar ch. <http://www.epa.gov/air/sect812/feb11/fullreport.pd f>. Accessed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 20 11b. Regulatory Impact Analysis : National Emission Standards for Hazardous Air Pollu tants for Industrial, Commercial, and Institutional Boilers and Process Heaters. Office of Air Quality Planning and Standards, Research Triangle Park, NC. February. <http://www.epa.gov/ttn/ecas/regdata/RIAs/boilersri afinal110221_psg.pdf>. Accessed March 30, 2011.4-38

U.S. Environmental Protection Agency (U.S. EPA). 20 11c. Draft Residual Risk Assessment for the Oil and Gas Production and Natural Gas Transmis sion and Storage Source Categories. Office of Air Quality Planning and Standards, Rese arch Triangle Park, NC. April.
U.S. Environmental Protection Agency (U.S. EPA). 20 11d. 2005 National-Scale Air Toxics Assessment. Office of Air Quality Planning and Standards, Rese arch Triangle Park, NC. March. < http://www.epa.gov/ttn/atw/nata2005/> Acce ssed March 30, 2011.
U.S. Environmental Protection Agency (U.S. EPA). 20 11e. Draft Inventory of the U.S. Greenhouse Gas Emissions and Sinks 1990. Report No. 430-R-11-005. February. <http://www.epa.gov/climatechange/emissions/downloa ds11/US-GHG-Inventory-2011- Complete_Report.pdf>. Accessed March 30, 2011.
U.S. Environmental Protection Agency—Science Adviso ry Board (U.S. EPA-SAB). 2002. Workshop on the Benefits of Reductions in Exposure to Hazardous Air Pollutants: Developing Best Estimates of Dose-Response Function s An SAB Workshop Report of an EPA/SAB Workshop (Final Report). EPA-SAB-EC-WKSHP-02-001. January. <http://yosemite.epa.gov/sab%5CSABPRODUCT.NSF/34355 712EC011A358525719A0 05BF6F6/$File/ecwkshp02001%2Bappa-g.pdf>. Accessed March 30, 2011.
U.S. Environmental Protection Agency—Science Adviso ry Board (U.S. EPA-SAB). 2008. Benefits of Reducing Benzene Emissions in Houston, 1990–2020 . EPA-COUNCIL-08- 001. July. <http://yosemite.epa.gov/sab/sabproduct.nsf/D4D7EC9 DAEDA8A548525748600728A8 3/$File/EPA-COUNCIL-08-001-unsigned.pdf>. Accessed March 30, 2011.
West et al. 2006. “Global health benefits of mitiga ting ozone pollution with methane emission controls.” PNAS

103:11:3988-3993.5-1 5 STATUTORY AND EXECUTIVE ORDER REVIEWS

5.1 Executive Order 12866, Regulatory Planning and Revi ew and Executive Order 13563, Improving Regulation and Regulatory Review

Under Executive Order 12866 (58 FR 51735, October 4 , 1993), this action is an
“economically significant regulatory action” becaus e it is likely to have an annual effect on the
economy of $100 million or more. Accordingly, the E PA submitted this action to OMB for
review under Executive Orders 12866 and 13563 (76 F R 3821, January 21, 2011) and any
changes made in response to OMB recommendations hav e been documented in the docket for

this action.
In addition, the EPA prepared a RIA of the potentia l costs and benefits associated with

this action. The RIA available in the docket descri bes in detail the empirical basis for the EPA’s
assumptions and characterizes the various sources o f uncertainties affecting the estimates below.

Table 5-1 shows the results of the cost and benefit s analysis for these proposed rules.5-2

Table 5-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed Oil and Natural Gas NSPS and NESHAP Amendm ents in 2015 (millions of 2008$) 1

Proposed NSPS Proposed NESHAP Amendments Proposed NSPS and NESHAP Amendments Combined
Total Monetized Benefits 2 N/A N/A N/A
Total Costs 3 -$45 million $16 million -$29 million
Net Benefits N/A N/A N/A
Non-monetized Benefits 37,000 tons of HAPs 1,400 tons of HAPs 38,000 tons of HAPs 540,000 tons of VOCs 9,200 tons of VOCs 540,000 t ons of VOCs 3.4 million tons of methane 4,900 tons of methane 3.4 million tons of methane Health effects of HAP exposure 5 Health effects of HAP exposure 5 Health effects of HAP exposure 5
Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Visibility impairment Visibility impairment Visibi lity impairment Vegetation effects Vegetation effects Vegetation e ffects Climate effects 5 Climate effects 5 Climate effects 5

1 All estimates are for the implementation year (2015 ) and include estimated revenue from additional nat ural gas recovery as a result of the NSPS.

2 While we expect that these avoided emissions will r esult in improvements in air quality and reductions in health effects associated with HAPs, ozone, and particulat e matter (PM) as well as climate effects associated with methane, we have determined that quantification of those benefi ts and co-benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there ar e no benefits or co-benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect im pacts of the reductions in emissions for this indus trial sector with the data currently available. The specific control tec hnologies for the proposed NSPS are anticipated to have minor secondary disbenefits, including an increase of 990 ,000 tons of CO 2 , 510 tons of NOx, 7.6 tons of PM, 2,800 tons of CO, and 1,000 tons of total hydrocarbons (THC) as w ell as emission reductions associated with the ener gy system impacts. The net CO 2 -equivalent emission reductions are 62 million metr ic tons.

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

4 The negative cost for the NSPS Options 1 and 2 refl ects the inclusion of revenues from additional natu ral gas and hydrocarbon condensate recovery that are estimated as a result of the proposed NSPS. Possible explana tions for why there appear to be negative cost control technologi es are discussed in the engineering costs analysis section in the RIA.

5 Reduced exposure to HAPs and climate effects are co -benefits.5-3

5.2 Paperwork Reduction Act

The information collection requirements in this pro posed action have been submitted for approval to OMB under the PRA , 44 U.S.C. 3501, et seq . The ICR document prepared by the EPA has been assigned EPA ICR Numbers 1716.07 (40 C FR part 60, subpart OOOO), 1788.10 (40 CFR part 63, subpart HH), 1789.07 (40 CFR part 63, subpart HHH), and 1086.10 (40 CFR part 60, subparts KKK and subpart LLL).

The information to be collected for the proposed NS PS and the proposed NESHAP amendments are based on notification, recordkeeping , and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recor dkeeping and reporting requirements are specifically authorized by section 114 of the CAA ( 42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and report ing requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.

These proposed rules would require maintenance insp ections of the control devices, but would not require any notifications or reports beyo nd those required by the General Provisions. The recordkeeping requirements require only the spe cific information needed to determine compliance.

For sources subject to the proposed NSPS, the burde n represents labor hours and costs associated from annual reporting and recordkeeping for each affected facility. The estimated burden is based on the annual expected number of af fected operators for the first three years following the effective date of the standards. The burden is estimated to be 560,000 labor hours at a cost of around$18 million per year. This inclu des the labor and cost estimates previously estimated for sources subject to 40 CFR part 60, su bpart KKK and subpart LLL (which is being incorporated into 40 CFR part 60, subpart OOOO). Th e average hours and cost per regulated entity, which is assumed to be on a per operator ba sis except for natural gas processing plants (which are estimated on a per facility basis) subje ct to the NSPS for oil and natural gas production and natural gas transmissions and distri bution facilities would be 110 hours per response and $3,693 per response based on an averag e of 1,459 operators responding per year5-4

and 16 responses per year. The majority of response s are expected to be notifications of construction. One annual report is required that ma y include all affected facilities owned per each operator. Burden by for the proposed NSPS was based on EPA ICR Number 1716.07.

The estimated recordkeeping and reporting burden af ter the effective date of the proposed amendments is estimated for all affected major and area sources subject to the oil and natural gas production NESHAP (40 CFR 63, subpart HH) to be app roximately 63,000 labor hours per year at a cost of $2.1 million per year. For the natural gas transmission and storage NESHAP, the recordkeeping and reporting burden is estimated to be 2,500 labor hours per year at a cost of $86,800 per year. This estimate includes the cost o f reporting, including reading instructions, and information gathering. Recordkeeping cost estimates include reading instructions, planning activities, and conducting compliance monitoring. T he average hours and cost per regulated entity subject to the oil and natural gas productio n NESHAP would be 72 hours per year and $2,500 per year based on an average of 846 faciliti es per year and three responses per facility. For the natural gas transmission and storage NESHAP , the average hours and cost per regulated entity would be 50 hours per year and $1,600 per ye ar based on an average of 53 facilities per year and three responses per facility. Burden is de fined at 5 CFR 1320.3(b). Burden for the oil and natural gas production NESHAP is estimated unde r EPA ICR Number 1788.10. Burden for the natural gas transmission and storage NESHAP is estimated under EPA ICR Number 1789.07.

5.3 Regulatory Flexibility Act

The Regulatory Flexibility Act as amended by the Sm all Business Regulatory Enforcement Fairness Act (SBREFA) generally require s an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substan tial number of small entities. Small entities include small businesses, small governmental jurisd ictions, and small not-for-profit enterprises. For purposes of assessing the impact of this rule o n small entities, a small entity is defined as: (1) a small business whose parent company has no more t han 500 employees (or revenues of less than $7 million for firms that transport natural ga s via pipeline); (2) a small governmental jurisdiction that is a government of a city, county , town, school district, or special district with a5-5

population of less than 50,000; and (3) a small org anization that is any not-for-profit enterprise which is independently owned and operated and is no t dominant in its field.

5.3.1 Proposed NSPS

After considering the economic impact of the Propos ed NSPS on small entities, I certify that this action will not have a significant econom ic impact on a substantial number of small entities (SISNOSE). EPA performed a screening anal ysis for impacts on a sample of expected affected small entities by comparing compliance cos ts to entity revenues. Based upon the analysis in Section 7.4 in this RIA, EPA recognizes that a subset of small firms is likely to be significantly impacted by the proposed NSPS. Howev er, the number of significantly impacted small businesses is unlikely to be sufficiently lar ge to declare a SISNOSE. Our judgment in this determination is informed by the fact that the firm -level compliance cost estimates used in the small business impacts analysis are likely over-est imates of the compliance costs faced by firms under the Proposed NSPS; these estimates do not inc lude the revenues that producers are expected receive from the additional natural gas re covery engendered by the implementation of
the controls evaluated in this RIA. As much of the additional natural gas recovery is estimated to arise from well completion-related activities, we e xpect the impact on well-related compliance costs to be significantly mitigated, if not fully o ffset. Although this final rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless has tried to reduce the impact of this rule on small entities by the selection of highly cost-effective controls and specifying monitoring requirements tha t are the minimum to insure compliance.

5.3.2 Proposed NESHAP Amendments

After considering the economic impact of the Propos ed NESHAP Amendments on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. Based upon the analysis in Section 7.4 in this RIA, we estimate that 62 of the 118 firms (53 percent) that own potentially affected facilities are small entities. EPA performed a screening analysis for impacts on all e xpected affected small entities by comparing compliance costs to entity revenues. Among the smal l firms, 52 of the 62 (84 percent) are likely to have impacts of less than 1 percent in terms of the ratio of annualized compliance costs to5-6

revenues. Meanwhile 10 firms (16 percent) are like ly to have impacts greater than 1 percent. Four of these 10 firms are likely to have impacts g reater than 3 percent. While these 10 firms might receive significant impacts from the proposed NESHAP amendments, they represent a very small slice of the oil and gas industry in its entirety, less than 0.2 percent of the estimated 6,427 small firms in NAICS 211. Although this fina l rule will not impact a substantial number of small entities, EPA nonetheless has tried to red uce the impact of this rule on small entities by setting the final emissions limits at the MACT floo r, the least stringent level allowed by law.

5.4 Unfunded Mandates Reform Act

This proposed rule does not contain a federal manda te that may result in expenditures of $100 million or more for state, local, and tribal g overnments, in the aggregate, or to the private sector in any one year. Thus, this proposed rule is not subject to the requirements of sections 202
or 205 of UMRA. This proposed rule is also not subject to the requi rements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments because it contains no requirements tha t apply to such governments nor does it impose obligations upon them.

5.5 Executive Order 13132: Federalism

This proposed rule does not have federalism implica tions. It will not have substantial direct effects on the states, on the relationship b etween the national government and the states, or on the distribution of power and responsibilities a mong the various levels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to this proposed rule.

5.6 Executive Order 13175: Consultation and Coordinati on with Indian Tribal
Governments

Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) the EPA may not issue a regulation that has tribal implications , that imposes substantial direct compliance5-7

costs, and that is not required by statute, unless the federal government provides the funds necessary to pay the direct compliance costs incurr ed by tribal governments, or the EPA consults with tribal officials early in the process of devel oping the proposed regulation and develops a tribal summary impact statement. The EPA has conclu ded that this proposed rule will not have tribal implications, as specified in Executive Orde r 13175. It will not have substantial direct effect on tribal governments, on the relationship b etween the federal government and Indian tribes, or on the distribution of power and respons ibilities between the federal government and Indian tribes, as specified in Executive Order 1317 5. Thus, Executive Order 13175 does not apply to this action.

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

This proposed rule is subject to Executive Order 13 045 (62 FR 19885, April 23, 1997) because it is economically significant as defined i n Executive Order 12866. However, EPA does not believe the environmental health or safety risk s addressed by this action present a disproportionate risk to children. This action wou ld not relax the control measures on existing regulated sources. EPA’s risk assessments (include d in the docket for this proposed rule) demonstrate that the existing regulations are assoc iated with an acceptable level of risk and provide an ample margin of safety to protect public health.

5.8 Executive Order 13211: Actions Concerning Regulati ons That Significantly Affect Energy Supply, Distribution, or Use

Executive Order 13211, (66 FR 28,355, May 22, 2001 ), provides that agencies shall prepare and submit to the Administrator of the Offi ce of Information and Regulatory Affairs, OMB, a Statement of Energy Effects for certain acti ons identified as significant energy actions. Section 4(b) of Executive Order 13211 defines “sign ificant energy actions” as “any action by an agency (normally published in the Federal Register ) that promulgates or is expected to lead to the promulgation of a final rule or regulation, inc luding notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulema king: 1)(i) that is a significant regulatory action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant5-8

adverse effect on the supply, distribution, or use of energy; or 2) that is designated by the Administrator of the Office of Information and Regu latory Affairs as a significant energy
action.” The proposed rules will result in the addition of control equipment and monitoring systems for existing and new sources within the oil and natural gas industry. The proposed NESHAP amendments are unlikely to have a significan t adverse effect on the supply, distribution, or use of energy. As such, the propos ed NESHAP amendments are not “significant energy actions” as defined in Executive Order 13211 , (66 FR 28355, May 22, 2001). The proposed NSPS is also unlikely to have a signi ficant adverse effect on the supply, distribution, or use of energy. As such, the propos ed NSPS is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001). The basis for the determination
is as follows. We use the NEMS to estimate the impacts of the pro posed NSPS on the United States energy system. The NEMS is a publically available m odel of the United States energy economy developed and maintained by the Energy Information Administration of the U.S. DOE and is used to produce the Annual Energy Outlook, a refere nce publication that provides detailed forecasts of the United States energy economy. Proposed emission controls for the NSPS capture VO C emissions that otherwise would be vented to the atmosphere. Since methane is co-em itted with VOC, a large proportion of the
averted methane emissions can be directed into natu ral gas production streams and sold. One pollution control requirement of the proposed NSPS also captures saleable condensates. The revenues from additional natural gas and condensate recovery are expected to offset the costs of implementing the proposed NSPS. The analysis of energy impacts for the proposed NS PS that includes the additional product recovery shows that domestic natural gas pr oduction is estimated to increase (20 billion cubic feet or 0.1 percent) and natural gas prices t o decrease ($0.04/Mcf or 0.9 percent at the wellhead for producers in the lower 48 states) in 2 015, the year of analysis. Domestic crude oil production is not estimated to change, while crude oil prices are estimated to decrease slightly ($0.02/barrel or less than 0.1 percent at the wellh ead for producers in the lower 48 states) in 2015, the year of analysis. All prices are in 2008 dollars.5-9

Additionally, the NSPS establishes several perform ance standards that give regulated entities flexibility in determining how to best com ply with the regulation. In an industry that is geographically and economically heterogeneous, this flexibility is an important factor in reducing regulatory burden.

5.9 National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law No. 104-113 (15 U.S.C. 272 no te) directs the EPA to use VCS in its regulatory activities unless to do so would be inco nsistent with applicable law or otherwise impractical. Voluntary consensus standards are tech nical standards (e.g., materials specifications, test methods, sampling procedures, and business pra ctices) that are developed or adopted by VCS. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable VCS. The proposed rule involves technical standards. Th erefore, the requirements of the NTTAA apply to this action. We are proposing to rev ise 40 CFR part 63, subparts HH and HHH to allow ANSI/ASME PTC 19.10–1981, Flue and Exhaust Gas Analyses (Part 10, Instruments and Apparatus) to be used in lieu of EPA Methods 3B , 6 and 16A. This standard is available from the American Society of Mechanical Engineers ( ASME), Three Park Avenue, New York, NY 10016-5990. Also, we are proposing to revise 40 CFR part 63, subpart HHH, to allow ASTM D6420-99(2004), “Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass Spectromet ry” to be used in lieu of EPA Method 18. For a detailed discussion of this VCS, and its appr opriateness as a substitute for Method 18, see the final oil and natural gas production NESHAP (Ar ea Sources) (72 FR 36, January 3, 2007). As a result, the EPA is proposing ASTM D6420-99 fo r use in 40 CFR part 63, subpart HHH. The EPA also proposes to allow Method 18 as an option in addition to ASTM D6420- 99(2004). This would allow the continued use of GC configurations other than GC/MS. The EPA welcomes comments on this aspect of the pr oposed rulemaking and, specifically, invites the public to identify potent ially-applicable VCS and to explain why such standards should be used in this regulation.5-10

5.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629, February 16, 199 4) establishes federal executive policy on Environmental Justice (EJ). Its main prov ision directs federal agencies, to the greatest extent practicable and permitted by law, to make EJ part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. To examine the potential for any EJ issues that mig ht be associated with each source category, we evaluated the distributions of HAP-rel ated cancer and noncancer risks across different social, demographic, and economic groups within the populations living near the facilities where these source categories are locate d. The methods used to conduct demographic analyses for this rule are described in section VII .D of the preamble for this rule. The development of demographic analyses to inform the c onsideration of EJ issues in EPA rulemakings is an evolving science. The EPA offers the demographic analyses in this proposed rulemaking as examples of how such analyses might b e developed to inform such consideration, and invites public comment on the approaches used a nd the interpretations made from the results, with the hope that this will support the r efinement and improve utility of such analyses for future rulemakings. For the demographic analyses, we focused on the pop ulations within 50 km of any facility estimated to have exposures to HAP which r esult in cancer risks of 1-in-1 million or greater, or noncancer HI of 1 or greater (based on the emissions of the source category or the facility, respectively). We examined the distributi ons of those risks across various demographic groups, comparing the percentages of particular dem ographic groups to the total number of people in those demographic groups nationwide. The results, including other risk metrics, such as average risks for the exposed populations, are d ocumented in source category-specific technical reports in the docket for both source cat egories covered in this proposal. As described in the preamble, our risk assessments demonstrate that the regulations for the oil and natural gas production and natural gas transmission and storage source categories, are5-11

associated with an acceptable level of risk and tha t the proposed additional requirements will provide an ample margin of safety to protect public health. Our analyses also show that, for these source cate gories, there is no potential for an
adverse environmental effect or human health multi- pathway effects, and that acute and chronic noncancer health impacts are unlikely. The EPA has determined that although there may be an existing disparity in HAP risks from these sources between some demographic groups, no demographic group is exposed to an unacceptable lev el of risk.6-1 6 COMPARISON OF BENEFITS AND COSTS

Because we are unable to estimate the monetary valu e of the emissions reductions from the proposed rule, we have chosen to rely upon a br eak-even analysis to estimate what the monetary value benefits would need to attain in ord er to equal the costs estimated to be imposed by the rule. A break-even analysis answers the que stion, “What would the benefits need to be
for the benefits to exceed the costs.” While a bre ak-even approach is not equivalent to a benefits analysis or even a net benefits analysis, we feel t he results are illustrative, particularly in the context of previously modeled benefits.

The total cost of the proposed NSPS in the analysis year of 2015 when the additional natural gas and condensate recovery is included in the analysis is estimated at -$45 million for domestic producers and consumers. EPA anticipates that this rule would prevent 540,000 tons of VOC, 3.4 million tons of methane, and 37,000 tons o f HAPs in 2015 from new sources. In 2015,
EPA estimates the costs for the NESHAP amendments f loor option to be $16 million. 49 EPA anticipates that this rule would reduce 9,200 tons of VOC, 4,900 tons of methane, and 1,400 tons of HAPs in 2015 from existing sources. For the NES HAP amendments, a break-even analysis suggests that HAP emissions would need to be valued at $12,000 per ton for the benefits to exceed the costs if the health benefits, and ecosys tem and climate co-benefits from the reductions
in VOC and methane emissions are assumed to be zero . If we assume the health benefits from HAP emission reductions are zero, the VOC emissions would need to be valued at $1,700 per ton
or the methane emissions would need to be valued at $3,300 per ton for the benefits to exceed
the costs. All estimates are in 2008 dollars.

For the proposed NSPS, the revenue from additional natural gas recovery already exceeds the costs, which renders a break-even analysis unne cessary. However, as discussed in Section 3.2.2., estimates of the annualized engineering cos ts that include revenues from natural gas product recovery depend heavily upon assumptions ab out the price of natural gas and hydrocarbon condensates in analysis year 2015. Ther efore, we have also conducted a break-even analysis for the price of natural gas. For the NSP S, a break-even analysis suggests that the price

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

of natural gas would need to be at least $3.77 per Mcf in 2015 for the revenue from product recovery to exceed the annualized costs. EIA forec asts that the price of natural gas would be $4.26 per Mcf in 2015. In addition to the revenue from product recovery, the NSPS would avert emissions of VOCs, HAPs, and methane, which all hav e value that could be incorporated into the break-even analysis. Figure 6-1 illustrates one me thod of analyzing the break-even point with alternate natural gas prices and VOC benefits. If, as an illustrative example, the price of natural gas was only $3.00 per Mcf, VOCs would need to be v alued at $260 per ton for the benefits to
exceed the costs. All estimates are in 2008 dollars

.

Figure 6-1 Illustrative Break-Even Diagram for Alte rnate 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 (20 09), average PM 2.5 health-related benefits

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

$- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 VOC Cost-effectiveness ($/ton reduction) Natural Gas Price ($/Mcf) in 2015

EIA Forecast Price in 2015 ($4.22/Mcf) RIA Assumed Price in 2015 ($4.00/Mcf

)CostEffectiveness as Function of Natural Gas Price Assumption6-3

of VOC emissions are valued at $280 to $7,000 per t on across a range of eight urban areas. 50 In addition, ozone benefits have been previously value d at $240 to $1,000 per ton of VOC reduced. Using the GWP approach, the climate co-benefits ran ge from approximately $110 to $1,400 per short ton of methane reduced depending upon the dis count rate assumed with a per ton estimate of $760 at the 3 percent discount rate.

These break-even benefit-per-ton estimates assume t hat all other pollutants have zero value. Of course, it is inappropriate to assume th at the value of reducing any of these pollutants is zero. Thus, the real break-even estimate is act ually lower than the estimates provided above because the other pollutants each have non-zero ben efits that should be considered. Furthermore, a single pollutant can have multiple e ffects (e.g., VOCs contribute to both ozone
and PM 2.5 formation that each have health and welfare effects ) that would need to be summed in order to develop a comprehensive estimate of the mo netized benefits associated with reducing that pollutant.

As previously described, the revenue from additiona l natural gas recovery already exceeds the costs of the NSPS, but even if the pric e of natural gas was only $3.00 per Mcf, it is likely that the VOC benefits would exceed the costs , As a result, even if VOC emissions from oil and natural gas operations result in monetized benefits that are substantially below the average modeled benefits, there is a reasonable cha nce that the benefits of these rules would exceed the costs, especially if we were able to mon etize all of the benefits associated with ozone formation, visibility, HAPs, and methane.

Table 6-1 and Table 6-2 present the summary of the benefits, costs, and net benefits for the NSPS and NESHAP amendment options, respectively . Table 6-3 provides a summary of the direct and secondary emissions changes for each opt ion.

50 See Section 4.5 of this RIA for more information r egarding PM 2.5 benefits and Section 4.6 for more information regarding ozone benefits.6-4

Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed Oil and Natural Gas NSPS in 2015 (millions of 2008$) 1 Option 1: Alternative Option 2: Proposed 4 Option 3: Alternative

Total Monetized Benefits 2 N/A N/A N/A
Total Costs 3 -$19 million -$45 million $77 million
Net Benefits N/A N/A N/A
Non-monetized Benefits 17,000 tons of HAPs 5 37,000 tons of HAPs 5 37,000 tons of HAPs 5 270,000 tons of VOCs 540,000 tons of VOCs 550,00 0 tons of VOCs

1.6 million tons of methane 3.4 million tons of me thane 3.4 million tons of methane

Health effects of HAP exposure 5 Health effects of HAP exposure 5 Health effects of HAP exposure 5
Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Health effects of PM 2.5 and ozone exposure Visibility impairment Visibility impairment Visibi lity impairment Vegetation effects Vegetation effects Vegetation e ffects Climate effects 5 Climate effects 5 Climate effects 5

1 All estimates are for the implementation year (2015 ) and include estimated revenue from additional nat ural gas recovery as a result of the NSPS.

2 While we expect that these avoided emissions will r esult in improvements in air quality and reductions in health effects associated with HAPs, ozone, and particulat e matter (PM) as well as climate effects associated with methane, we have determined that quantification of those benefi ts and co-benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there ar e no benefits or co-benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect im pacts of the reductions in emissions for this indus trial sector with the data currently available. The specific control tec hnologies for the proposed NSPS are anticipated to have minor secondary disbenefits, including an increase of 990 ,000 tons of CO 2 , 510 tons of NOx, 7.6 tons of PM, 2,800 tons of CO, and 1,000 tons of total hydrocarbons (THC) as w ell as emission reductions associated with the ener gy system impacts. The net CO 2 -equivalent emission reductions are 62 million metr ic tons.

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

4 The negative cost for the NSPS Options 1 and 2 refl ects the inclusion of revenues from additional natu ral gas and hydrocarbon condensate recovery that are estimated as a result of the proposed NSPS. Possible explana tions for why there appear to be negative cost control technologi es are discussed in the engineering costs analysis section in the RIA.

5 Reduced exposure to HAPs and climate effects are co -benefits.6-5

Table 6-2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed Oil and Natural Gas NESHAP amendments in 2 015 (millions of 2008$) 1

Option 1: Proposed (Floor)

Total Monetized Benefits 2 N/A
Total Costs 3 $16 million
Net Benefits N/A
Non-monetized Benefits 1,400 tons of HAPs 9,200 tons of VOCs 4
4,900 tons of methane 4

Health effects of HAP exposure

Health effects of PM 2.5 and ozone exposure 4

Visibility impairment 4 Vegetation effects 4
Climate effects 4

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

2 While we expect that these avoided emissions will r esult in improvements in air quality and reductions in health effects associated with HAPs, ozone, and PM as well as climate effects associated with methane, we hav e determined that quantification of those benefits an d co-benefits cannot be accomplished for this rule in a defensible way. This is not to imply that there are no benefi ts or co-benefits of the rules; rather, it is a ref lection of the difficulties in modeling the direct and indirect im pacts of the reductions in emissions for this indus trial sector with the data currently available. The specific control technologies for the proposed NESHAP are anticipat ed to have minor secondary disbenefits, including an increase of 5,500 tons of CO 2 , 2.9 tons of NOx, 16 tons of CO, and 6.0 tons of THC as well as emission reductions associat ed with the energy system impacts. The net CO 2 -equivalent emission reductions are 93 thousand metric tons.

3 The cost estimates are assumed to be equivalent to the engineering cost estimates. The engineering co mpliance 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 effec ts, and climate effects are co-benefits.6-6

Table 6-3 Summary of Emissions Changes for the Prop osed Oil and Gas NSPS and NESHAP in 2015 (short tons per year)

Pollutant NSPS Option 1 NSPS Option 2

(Proposed) NSPS Option 3 NESHAP

Change in Direct Emissions VOC -270,000 -540,000 -550,000 -9,200 Methane -1,600,000 -3,400,000 -3,400,000 -4,900 HAP -17,000 -37,000 -37,000 -1,400

Change in Secondary Emissions (Producer-Side) 1 CO 2 990,000 990,000 990,000 5,500
NOx 510 510 510 2.9
PM 7.6 7.6 7.6 0.1 CO 2,800 2,800 2,800 16 THC 1,000 1,000 1,000 6.0 Change in Secondary Emissions (Consumer-Side) CO 2 -e -1,000,000 1,700,000 1,400,000 N/A
Net Change in CO 2 -equivalent Emissions CO 2 -e -33,000,000 -68,000,000 -70,000,000 -96,000

1 We use the producer-side secondary impacts associat ed with the proposed NSPS option as a surrogate for the impacts of the other options.7-1

7 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSM ENTS

7.1 Introduction This section includes three sets of analyses for bo th the NSPS and NESHAP amendments:

• Energy System Impacts

• Employment Impacts

• Small Business Impacts Analysis

7.2 Energy System Impacts Analysis of Proposed NSPS

We use the National Energy Modeling System (NEMS) t o estimate the impacts of the proposed NSPS on the U.S. energy system. The impac ts we estimate include changes in drilling activity, price and quantity changes in the product ion and consumption of crude oil and natural gas, and changes in international trade of crude oi l and natural gas. We evaluate whether and to what extent the increased production costs imposed by the NSPS might alter the mix of fuels
consumed at a national level. With this informatio n we estimate how the changed fuel mix
affects national level CO 2 -equivalent greenhouse gas emissions from energy so urces. We additionally combine these estimates of changes in CO 2 -equivalent greenhouse gas emissions from energy sources and emissions co-reductions of methane from the engineering analysis with NEMS analysis to estimate the net change in CO 2 -equivalent greenhouse gas emissions from energy-related sources, but this analysis is reserv ed for the secondary environmental impacts analysis within Section 4.

A brief conceptual discussion about our energy syst em impacts modeling approach is necessary before going into detail on NEMS, how we implemented the regulatory impacts, and results. Economically, it is possible to view the recovered natural gas as an explicit output or as contributing to an efficiency gain at the producer level. For example, the analysis for the

p r oposed NSPS shows that about 97 percent of the natu ral gas captured by emissions controls suggested by the rule is captured by performing REC s on new and existing wells that are7-2

completed after being hydraulically fractured. The assumed $4/Mcf price for natural gas is the price paid to producers at the wellhead. In the na tural gas industry, production is metered at or very near to the wellhead, and producers are paid b ased upon this metered production. Depending on the situation, the gas captured by REC s is sent through a temporary or permanent meter. Payments for the gas are typically made wit hin 30 days. To preview the energy systems modeling using NEMS, results show that after economic adjustments to the new regulations are made by prod ucers, the captured natural gas represents both increased output (a slight increment in aggreg ate production) and increased efficiency (producing slightly more for less). However, becau se of differing objectives for the regulatory analysis we treat the associated savings differentl y in the engineering cost analysis (as an explicit output) and in NEMS (as an efficiency gain). In the engineering cost analysis, it is necessary t o estimate the expected costs and revenues from implementing emissions controls at th e unit level. Because of this, we estimate the net costs as expected costs minus expected reve nues for representative units. On the other hand, NEMS models the profit maximizing behavior of representative project developers at a drilling project level. The net costs of the regula tion alter the expected discounted cash flow of drilling and implementing oil and gas projects, and the behavior of the representative drillers adjusts accordingly. While in the regulatory case natural gas drilling has become more efficient because of the gas recovery, project developers sti ll interact with markets for which supply and demand are simultaneously adjusting. Consequently, project development adjusts to a new equilibrium. While we believe the cost savings as measured by revenues from selling recovered gas (engineering costs) and measured by cost saving s from averted production through efficiency gains (energy economic modeling) are approximately the same, it is important to note that the engineering cost analysis and the national-level co st estimates do not incorporate economic feedbacks such as supply and demand adjustments.

7.2.1 Description of the Department of Energy National En ergy Modeling System

NEMS is a model of U.S. energy economy developed an d maintained by the Energy Information Administration of the U.S. Department o f Energy. NEMS is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the energy7-3

economy from the current year to 2035. DOE first d eveloped NEMS in the 1980s, and the model has been undergone frequent updates and expan sion since. DOE uses the modeling system extensively to produce issue reports, legisl ative analyses, and respond to Congressional inquiries.

EIA is legally required to make the NEMS system sou rce code available and fully documented for the public. The source code and acc ompanying documentation is released annually when a new Annual Energy Outlook is produc ed. Because of the availability of the NEMS model, numerous agencies, national laboratorie s, research institutes, and academic and private-sector researchers have used NEMS to analyz e a variety of issues.

NEMS models the dynamics of energy markets and thei r interactions with the broader U.S. economy. The system projects the production o f energy resources such as oil, natural gas, coal, and renewable fuels, the conversion of resour ces through processes such as refining and electricity generation, and the quantity and prices for final consumption across sectors and regions. The dynamics of the energy system are gov erned by assumptions about energy and environmental policies, technological developments, resource supplies, demography, and
macroeconomic conditions. An overview of the model and complete documentation of NEMS
can be found at < http://www.eia.doe.gov/oiaf/aeo/overview/index.html >.7-4

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

NEMS is a large-scale, deterministic mathematical p rogramming model. NEMS iteratively solves multiple models, linear and non- linear, using nonlinear Gauss-Seidel methods (Gabriel et al. 2001). What this means is that NEM S solves a single module, holding all else constant at provisional solutions, then moves to th e next model after establishing an updated provisional solution.

NEMS provides what EIA refers to as “mid-term” proj ections to the year 2035. However, as this RIA is concerned with estimating r egulatory impacts in the first year of full implementation, our analysis focuses upon estimated impacts in the year 2015, with regulatory costs first imposed in 2011. For this RIA, we draw upon the same assumptions and model used in the Annual Energy Outlook 2011. 51 The RIA baseline is consistent with that of the Annual Energy Outlook 2011 which is used extensively in Se ction 2 in the Industry Profile.

51 Assumptions for the 2011 Annual Energy Outlook can be found at <http://www.eia.gov/forecasts/aeo/assumptions/index .cfm>.7-5

7.2.2 Inputs to National Energy Modeling System

To model potential impacts associated with the NSPS , we modified oil and gas production costs within the Oil and Gas Supply Modu le (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 pr oduction from onshore, offshore, Alaskan wells, as well as having a smaller-scale tr eatment of Canadian oil and gas production (U.S. EIA, 2010). The treatment of oil and gas res ources is detailed in that oil, shale oil, conventional gas, shale gas, tight sands gas, and c oalbed methane (CBM) are explicitly modeled. New exploration and development is pursued in the O GSM if the expected net present value of extracted resources exceeds expected costs, includi ng costs associated with capital, exploration, development, production, and taxes. Detailed techn ology and reservoir-level production economics govern finding and success rates and cost s.

The structure of the OGSM is amenable to analyzing potential impacts of the Oil and Natural Gas NSPS. We are able to target additional expenditures for environmental controls expected to be required by the NSPS on new explorat ory and developmental oil and gas production activities, as well as add additional co sts to existing projects. We model the impacts of additional environmental costs, as well as the i mpacts of additional product recovery. We explicitly model the additional natural gas recover ed when implementing the NSPS regulatory options. However, we are unable to explicitly mode l the additional production of condensates expected to be recovered by reduced emissions compl etions, although we incorporate expected revenues from the condensate recovery in the econom ic evaluation of new drilling projects.

While the oil production simulated by the OGSM is s ent to the refining module (the Petroleum Market Module), simulated natural gas pro duction is sent to a transmission and distribution network captured in the NGTDM. The NG TDM balances gas supplies and prices and “negotiates” supply and consumption to determin e a regional equilibrium between supply, demand and prices, including imports and exports vi a pipeline or LNG. Natural gas transmitted through a simplified arc-node representation of pip eline infrastructure based upon pipeline
economics.7-6

7.2.2.1 Compliance Costs for Oil and Gas Exploration and Pr oduction

As the NSPS affects new emissions sources, we chose to estimate impacts on new exploration and development projects by adding cost s of environmental regulation to the algorithm that evaluates the profitability of new p rojects. Additional NSPS costs associated with reduced emission completions and future recompletio ns 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 r epeated periodically, as in the case of recompletions. Costs required for reduced emission s recompletions on existing wells are added to stimulation expenses for existing wells exclusiv ely. Other costs are operations and maintenance-type costs and are added to fixed opera tion and maintenance (O&M) expenses associated with new projects. The one-shot and con tinuing O&M expenses are estimated and entered on a per well basis, depending on whether t he costs would apply to oil wells, natural gas wells, both oil and natural gas wells, or a subset of either. We base the per well cost estimates on the engineering costs including revenues from addit ional product recovery. This approach is appropriate given the structure of the NEMS algorit hm that estimates the net present value of drilling projects.

One concern in basing the regulatory costs inputs i nto NEMS on the net cost of the compliance activity (estimated annualized cost of c ompliance minus estimated revenue from product recovery) is that potential barriers to obt aining capital may not be adequately incorporated in the model. However, in general, po tential barriers to obtaining additional capital
should be reflected in the annualized cost via thes e barriers increasing the cost of capital. With this in mind, assuming the estimates of capital cos ts and product recovery are valid, the NEMS results will reflect barriers to obtaining the reti red capital. A caveat to this is that the estimate d unit-level capital costs of controls which are newl y required at a national-level as a result of the proposed regulation—RECs, for example—may not incor porate potential additional transitional costs as the supply of control equipment adjusts to new demand.

Table 7-1 shows the incremental O&M expenses that accrue to new drilling projects as a result of producers having to comply with the relev ant NSPS option. We estimate those costs as a function of new wells expected to be drilled in a representative year. To arrive at estimates of7-7

the per well costs, we first identify which emissio ns reductions will apply primarily to crude oil wells, to natural gas wells, or to both crude oil a nd natural gas wells. Based on the baseline projections of successful completions in 2015, we u sed 19,097 new natural gas wells and 12,193
new oil wells as the basis of these calculations. We then divide the estimated compliance costs for the given emissions point (from Table 3-3) by t he appropriate number of expected new wells in the year of analysis. The result yields an appr oximation of a per well compliance costs. We assume this approximation is representative of the incremental cost faced by a producer when evaluating a prospective drilling project.

Like the engineering analysis, we assume that hydra ulically fractured well completions and recompletions will be required of wells drilled into tight sand, shale gas, and coalbed methane formations. While costs for well recomplet ions reflect the cost of a single recompletion, the engineering cost analysis assumed that one in ten new wells drilled after the implementation of the promulgation and implementati on of the NSPS are completed using hydraulic fracturing will receive a recompletion in any given year using hydraulic fracturing. Meanwhile, within NEMS, wells are assumed to be sti mulated 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 ref lect the same assumptions as the engineering analysis. In entering compliance costs into NEMS, we also account for reduced emissions completions, completion combustion, and recompletio ns performed in absence of the regulation, using the same assumptions as the engineering costs analysis (Table 7-2).7-8

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

Emissions Sources/Points Emissions Control Per Well Costs (2008$) Wells Applied To in NEMS Option 1 Option 2

(Proposed) Option 3 Equipment Leaks Well Pads Subpart VV Not in Option Not in Option $3,552 Oil and Gas Gathering and Boosting Stations Subpart VV Not in Option Not in Option $806 Gas Processing Plants Subpart VVa Not in Option $56 $56 None Transmission Compressor Stations Subpart VV Not in Option Not in Option $320 Gas Reciprocating Compressors Well Pads Annual Monitoring/ Maintenance Not in Option Not in Option Not in Option None
Gathering/Boosting Stations AMM $17 $17 $17 Gas Processing Plants AMM $12 $12 $12 Gas Transmission Compressor Stations AMM $19 $19 $19 Gas Underground Storage Facilities AMM $1 $1 $1 Gas Centrifugal Compressors Processing Plants Dry Seals/Route to Process or Control -$113 -$113 -$113 Gas

Transmission Compressor Stations Dry Seals/Route to Process or Control -$62 -$62 -$62 Gas

Pneumatic Controllers - Oil and Gas Production Low Bleed/Route to Process -$698 -$698 -$698 Oil and Gas
Natural Gas Transmission and Storage Low Bleed/Route to Process $0.10 $0.10 $0.10 Gas
Storage Vessels High Throughput 95% control $143 $143 $143 Oil and Gas Low Throughput 95% control Not in Option Not in Option Not in Option None7-9

Table 7-2 Summary of Additional Per Completion/Reco mpletion Costs (2008$) for Environmental Controls Entered into NEMS

Emissions Sources/Points Emissions Control Per Completion/Recompletion Costs (2008$) Wells Applied To in NEMS Option 1 Option 2

(proposed) Option 3 Well Completions Hydraulically Fractured Gas Wells REC -$1,275 -$1,275 -$1,275 New Tight Sand/ Shale Gas/CBM Conventional Gas Wells Combustion Not in Option Not in Option Not in Option None Oil Wells Combustion Not in Option Not in Option Not in Option None Well Recompletions Hydraulically Fractured Gas Wells (post-NSPS wells) REC -$1,535 -$1,535 -$1,535 Existing Tight Sand/ Shale Gas /Coalbed Methane Hydraulically Fractured Gas Wells (existing wells) REC Not in Option -$1,535 -$1,535 Existing Tight Sand/ Shale Gas /Coalbed Methane Conventional Gas Wells Combustion Not in Option Not in Option Not in Option None Oil Wells Combustion Not in Option Not in Option Not in Option None

7.2.2.2 Adding Averted Methane Emissions into Natural Gas P roduction

A significant benefit of controlling VOC emissions from oil and natural gas production is
that methane that would otherwise be lost to the at mosphere can be directed into the natural gas production stream. We chose to model methane captu re in NEMS as an increase in natural gas industry productivity, ensuring that, within the mo del, natural gas reservoirs are not decremented by production gains from methane capture. We add e stimates 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 esti mates of commercially valuable averted emissions by region and well type in order to more accurately portray the economics of implementing the environmental technology. Adding the averted methane emissions in this manner has the effect of moving the natural gas sup ply curve to the right an increment consistent with the technically achievable emissions transferr ed into the production stream as a result of the proposed NSPS.

For all control options, with the exception of rec ompletions on existing wells, we enter the increased natural gas recovery into NEMS on a p er-well basis for new wells, following an7-10

estimation procedure similar to that of entering co mpliance costs into NEMS on a per well basis for new wells. Because each NSPS Option is compose d of a different suite of emissions controls, the per-well natural gas recovery value f or new wells is different across wells. For Option 1, we estimate that natural gas recovery is 5,739 Mcf per well. For Option 2 and Option 3, we estimate that natural gas recovery is 5,743 M cf per well. We make a simplifying assumption that natural gas recovery accruing to ne w wells accrues to new wells in shale gas, tight sands, and CBM fields. We make these assumpt ions because new wells in these fields are more likely to satisfy criteria such that RECs are required, which contributed that large majority of potential natural gas recovery. Note that these per well natural gas recovery is lower than the per well estimate when RECs are implemented. The e stimate is lower because we account for emissions that are combusted, RECs that are impleme nted absent Federal regulation, as well as the likelihood that natural gas is used during proc essing and transmission or reinjected.

We treat the potential natural gas recovery associ ated with recompletions of existing wells (in proposed Option 2 and Option 3) different ly in that we estimated the natural gas recovery by natural gas resource type and NSPS Opti on based on a combination of the engineering analysis and production patterns from t he 2011 Annual Energy Outlook. We estimate that additional natural gas product recove red by recompleting existing wells in proposed Option 2 and Option 3 to be 78.7 bcf, with 38.4 bcf accruing to shale gas, 31.4 bcf accruing to tight sands, and 8.9 bcf accruing to CBM, respectiv ely. This quantity is distributed within the NGTDM to reflect regional production by resource ty pe.

7.2.2.3 Fixing Canadian Drilling Costs to Baseline Path

Domestic drilling costs serve as a proxy for Canadi an drilling costs in the Canadian oil and natural gas sub-model within the NGTDM. This i mplies that, without additional modification, additional costs imposed by a U.S. re gulation will also impact drilling decisions in Canada. Changes in international oil and gas trad e are important in the analysis, as a large majority of natural gas imported into the U.S. orig inates in Canada. To avoid this problem, we fixed Canadian drilling costs using U.S. drilling c osts from the baseline scenario. This solution enables a more accurate analysis of U.S.-Canada ene rgy trade, as increased drilling costs in the U.S. as a result of environmental regulation serve to increase Canada’s comparative advantage.7-11

7.2.3 Energy System Impacts

As mentioned earlier, we estimate impacts to drilli ng activity, reserves, price and quantity changes in the production and consumption of crude oil and natural gas, and changes in international trade of crude oil and natural gas, a s well as whether and to what extent the NSPS might alter the mix of fuels consumed at a national level. In each of these estimates, we present estimates for the baseline year of 2015 and results for the three NSPS options. For context, we provide estimates of production activities in 2011.

7.2.3.1 Impacts on Drilling Activities

Because the potential costs of the NSPS options are concentrated in production activities, we first report estimates of impacts on crude oil a nd natural gas drilling activities and production and price changes at the wellhead. Table 7-3 prese nts estimates of successful wells drilled in the U.S. in 2015, the analysis year, for the three NSPS options and in the baseline.

Table 7-3 Successful Oil and Gas Wells Drilled, NSP S Options Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3

Successful Wells Drilled Natural Gas 16,373 19,097 19,191 18,935 18,872 Crude Oil 10,352 11,025 11,025 11,025 11,028 Total 26,725 30,122 30,216 29,960 29,900

% Change in Successful Wells Drilled from Baseline Natural Gas 0.49% -0.85% -1.18% Crude Oil 0.00% 0.00% 0.03% Total 0.31% -0.54% -0.74%

We estimate that the number of successful natural g as wells drilled increases slightly for Option 1, while the number of successful crude oil wells d rilled does not change. In Options 2, where costs of the natural gas processing plants equipmen t leaks standard and REC requirements for existing wells apply, natural gas wells drilling is forecast to decrease less than 1 percent, while crude oil drilling does not change. For Option 3, where the addition of an additional equipment7-12

leak standards add to the incremental costs, natura l gas well drilling is estimated to decrease
about 1.2%. The number of successful crude oil wel ls drilled under Option 3 increases very slightly. While it may seem counter-intuitive that the number of successful crude wells increased as costs increase, it is important to not e that crude oil and natural gas drilling compete with each other for factors of production, such as labor and material. The environmental compliance costs of the NSPS options predominantly affect natural gas drilling. As natural gas drilling declines, for example, as a result of incr eased compliance costs, crude oil drilling may increase because of the increased availability of l abor and material, as well as the likelihood that crude oil can substitute for natural gas to some ex tent.

Table 7-4 presents the forecast of successful well s by well type, for onshore drilling in
the lower 48 states. The results show that convent ional well drilling is unaffected by the regulatory options, as reduced emission completion and completion combustion requirements are
directed not toward wells in conventional reserves but toward wells that are hydraulically fractured, the wells in so-called unconventional re serves. The impacts on drilling tight sands, shale gas, and coalbed methane vary by option.

Table 7-4 Successful Wells Drilled by Well Type (On shore, Lower 48 States), NSPS Options Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3

Successful Wells Drilled Conventional Gas Wells 7,267 7,607 7,607 7,607 7,6 07 Tight Sands 2,441 2,772 2,791 2,816 2,780 Shale Gas 5,007 7,022 7,074 6,763 6,771 Coalbed Methane 1,593 1,609 1,632 1,662 1,627 Total 16,308 19,010 19,104 18,849 18,785

% Change in Successful Wells Drilled from Baseline Conventional Gas Wells 0.00% 0.00% 0.00% Tight Sands 0.70% 1.60% 0.29% Shale Gas 0.74% -3.68% -3.57% Coalbed Methane 1.44% 3.28% 1.09% Total 0.50% -0.85% -1.18%7-13

Well drilling in tight sands is estimated to increa se slightly from the baseline under all three options, 0.70 percent, 1.60 percent, and 0.29% for Options 1, 2, and 3, respectively. Wells in
CBM reserves are also estimated to increase from th e baseline under all three options, or 1.44 percent, 3.28 percent, and 1.09 percent for Options 1, 2, and 3, respectively. However, drilling in shale gas is forecast to decline from the baseli ne under Options 2 and 3, by 3.68 percent and 3.57 percent, respectively.

7.2.3.2 Impacts on Production, Prices, and Consumption
Table 7-5 shows estimates of the changes in the dom estic production of natural gas and crude oil under the NSPS options, as of 2015. Dome stic crude oil production is not forecast to change under any of the three regulatory options, a gain because impacts on crude oil drilling of the NSPS are expected to be negligible.

Table 7-5 Annual Domestic Natural Gas and Crude Oil Production, NSPS Options Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3 Domestic Production Natural Gas (trillion cubic feet) 21.05 22.43 22.4 7 22.45 22.44 Crude Oil (million barrels/day) 5.46 5.81 5.81 5.8 1 5.81

% Change in Domestic Production from Baseline Natural Gas 0.18% 0.09% 0.04% Crude Oil 0.00% 0.00% 0.00%

Natural gas production, on the other hand, increase s under all three regulatory options for the
NSPS from the baseline. A main driver for these in creases is the additional natural gas recovery engendered by the control requirements. Another dri ver for the increases under Option 1 is the increase in natural gas well drilling. While we sh owed earlier that natural gas drilling is estimated to decline under Options 2 and 3, the inc reased natural gas recovery is sufficient to offset the production loss from relatively fewer pr oducing wells.

For the proposed option, the NEMS analysis shown i n Table 7-5 estimates a 20 bcf increase in domestic natural gas production. This amount is less than the amount estimated in the engineering analysis to be captured by emission s controls implemented as a result of the7-14

proposed NSPS (approximately 180 bcf). This differ ence is because NEMS models the adjustment of energy markets to the now relatively more efficient natural gas production sector. At the new natural gas supply and demand equilibriu m in 2015, the modeling estimates 20 bcf more gas is produced at a relatively lower wellhead price (which will be presented momentarily). However, at the new equilibrium, producers implemen ting emissions controls still capture and sell approximately 180 bcf of natural gas. For exa mple, as shown in Table 7-4, about 11,200 new unconventional natural gas wells are completed under the proposed NSPS; using assumptions from the engineering cost analysis abou t RECs required under State regulations and exploratory wells exempted from REC requirements, a bout 9,000 NSPS-required RECs would be performed on new natural gas well completions, a ccording to the NEMS analysis. This recovered natural gas substitutes for natural gas t hat would be produced from the ground absent the rule. In effect, then, about 160 bcf of natura l gas that would have been extracted and emitted into the atmosphere is left in the formation for fu ture extraction.

As we showed for natural gas drilling, Table 7-6 sh ows natural gas production from onshore wells in the lower 48 states by type of wel l, predicted for 2015, the analysis year. Production from conventional natural gas wells and CBM wells are estimated to increase under all NSPS regulatory options. Production from shale gas reserves is estimated to decrease under Options 2 and 3, however, from the baseline project ion. Production from tight sands is forecast to decline slightly under Option 1.7-15

Table 7-6 Natural Gas Production by Well Type (Onsh ore, Lower 48 States), NSPS Options Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3 Natural Gas Production by Well Type (trillion cubic feet) Conventional Gas Wells 4.06 3.74 3.75 3.76 3.76 Tight Sands 5.96 5.89 5.87 6.00 6.00 Shale Gas 5.21 7.20 7.26 7.06 7.06 Coalbed Methane 1.72 1.67 1.69 1.72 1.71 Total 16.95 18.51 18.57 18.54 18.53

% Change in Natural Gas Production by Well Type fro m Baseline Conventional Gas Wells 0.32% 0.42% 0.48% Tight Sands -0.43% 1.82% 1.72% Shale Gas 0.73% -1.97% -1.93% Coalbed Methane 1.07% 2.86% 2.60% Total 0.31% 0.16% 0.13% Note: Totals may not sum due to independent roundin g. Overall, of the regulatory options, the proposed Op tion 2 is estimated to have the highest natural gas production from onshore wells in the lower 48 s tates, showing a 1.2% increase over the baseline projection.

Table 7-7 presents estimates of national average we llhead natural gas and crude oil prices for onshore production in the lower 48 states, esti mated for 2015, the year of analysis. All NSPS options show a decrease in wellhead natural gas and crude oil prices. The decrease in wellhead natural gas price form the baseline is attributable largely to the increased productivity of natural gas wells as a result of capturing a portion of com pletion emissions (in Options 1, 2, and 3) and in capturing recompletion emissions (in Options 2 a nd 3).7-16

Table 7-7 Lower 48 Average Natural Gas and Crude Oi l Wellhead Price, NSPS Options Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3 Lower 48 Average Wellhead Price Natural Gas (2008$ per Mcf) 4.07 4.22 4.18 4.18 4.19 Crude Oil (2008$ per barrel) 83.65 94.60 94.59 94.58 94.58

% Change in Lower 48 Average Wellhead Price from Ba seline Natural Gas -0.94% -0.94% -0.71% Crude Oil -0.01% -0.02% -0.02%

Table 7-8 presents estimates of the price of natura l gas to final consumers in 2008 dollars per million BTU. The production price decreases estima ted across NSPS are largely passed on to consumers but distributed unequally across consumin g sectors. Electric power sector consumers of natural gas are estimated to receive the largest price decrease while the transportation and
residential sectors are forecast to receive the sma llest price decreases.

Table 7-8 Delivered Natural Gas Prices by Sector (2 008$ per million BTU), 2015, NSPS Options Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3 Delivered Prices (2008$ per million BTU) Residential 10.52 10.35 10.32 10.32 10.33 Commercial 9.26 8.56 8.52 8.53 8.54 Industrial 4.97 5.08 5.05 5.05 5.06 Electric Power 4.81 4.77 4.73 4.74 4.75 Transportation 12.30 12.24 12.20 12.22 12.22 Average 6.76 6.59 6.55 6.57 6.57
% Change in Delivered Prices from Baseline Residential -0.29% -0.29% -0.19% Commercial -0.47% -0.35% -0.23% Industrial -0.59% -0.59% -0.39% Electric Power -0.84% -0.63% -0.42% Transportation -0.33% -0.16% -0.16% Average -0.60% -0.41% -0.30%7-17

Final consumption of natural gas is also estimated to increase in 2015 from the baseline under all NSPS options, as is shown on Table 7-9. Like delivered price, the consumption shifts are distributed differently across sectors.

Table 7-9 Natural Gas Consumption by Sector, NSPS O ptions Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3 Consumption (trillion cubic feet) Residential 4.76 4.81 4.81 4.81 4.81 Commercial 3.22 3.38 3.38 3.38 3.38 Industrial 6.95 8.05 8.06 8.06 8.06 Electric Power 7.00 6.98 7.00 6.98 6.97 Transportation 0.03 0.04 0.04 0.04 0.04 Pipeline Fuel 0.64 0.65 0.65 0.66 0.66 Lease and Plant Fuel 1.27 1.20 1.21 1.21 1.21 Total 23.86 25.11 25.15 25.14 25.13
% Change in Consumption from Baseline Residential 0.00% 0.00% 0.00% Commercial 0.00% 0.00% 0.00% Industrial 0.12% 0.12% 0.12% Electric Power 0.29% 0.00% -0.14% Transportation 0.00% 0.00% 0.00% Pipeline Fuel 0.00% 1.54% 1.54% Lease and Plant Fuel 0.83% 0.83% 0.83% Total 0.16% 0.12% 0.08% Note: Totals may not sum due to independent roundin g.
7.2.3.3 Impacts on Imports and National Fuel Mix
The NEMS modeling shows that impacts from all NSPS options are not sufficiently large to affect the trade balance of natural gas. As sho wn in Table 7-10, estimates of crude oil and natural gas imports do not vary from the baseline i n 2015 for each regulatory option.7-18

Table 7-10 Net Imports of Natural Gas and Crude Oil , NSPS Options Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3 Net Imports Natural Gas (trillion cubic feet) 2.75 2.69 2.69 2 .69 2.69 Crude Oil (million barrels/day) 9.13 8.70 8.70 8.7 0 8.70

% Change in Net Imports Natural Gas 0.00% 0.00% 0.00% Crude Oil 0.00% 0.00% 0.00%

Table 7-11 evaluates estimates of energy consumptio n by energy type at the national level for 2015, the year of analysis. All three NS PS options are estimated to have small effects at the national level. For Option 1, we estimate an i ncrease in 0.02 quadrillion BTU in 2015, a 0.02 percent increase. The percent contribution of natu ral gas and biomass is projected to increase, while the percent contribution of liquid fuels and coal is expected to decrease under Option 1. Meanwhile, under the proposed Options 2, total ener gy consumption is also forecast to rise 0.02 quadrillion BTU, with increase coming from natural gas primarily, with an additional small increase in coal consumption. Under Option 3, tota l energy consumption is forecast to rise 0.01 quadrillion BTU, or 0.01%, with a slight decrease i n liquid fuel consumption from the baseline, but increases in natural gas and coal consumption.7-19

Table 7-11 Total Energy Consumption by Energy Type (Quadrillion BTU), NSPS Options Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3 Consumption (quadrillion BTU) Liquid Fuels 37.41 39.10 39.09 39.10 39.09 Natural gas 24.49 25.77 25.82 25.79 25.79 Coal 20.42 19.73 19.71 19.74 19.74 Nuclear Power 8.40 8.77 8.77 8.77 8.77 Hydropower 2.58 2.92 2.92 2.92 2.92 Biomass 2.98 3.27 3.28 3.27 3.27 Other Renewable Energy 1.72 2.14 2.14 2.14 2.14 Other 0.30 0.31 0.31 0.31 0.31 Total 98.29 102.02 102.04 102.04 102.03
% Change in Consumption from Baseline Liquid Fuels -0.03% 0.00% -0.03% Natural Gas 0.19% 0.08% 0.08% Coal -0.10% 0.05% 0.05% Nuclear Power 0.00% 0.00% 0.00% Hydropower 0.00% 0.00% 0.00% Biomass 0.31% 0.00% 0.00% Other Renewable Energy 0.00% 0.00% 0.00% Other 0.00% 0.00% 0.00% Total 0.02% 0.02% 0.01% Note: Totals may not sum due to independent roundin g. With the national profile of energy consumption es timated to change slightly under the regulatory options in 2015, the year of analysis, i t is important to examine whether aggregate energy-related CO 2 -equivalent greenhouse gas (GHG) emissions also shi ft. A more detailed discussion of changes in CO 2 -equivalent GHG emissions from a baseline is presen ted within the benefits analysis in Section 4. Here, we present a single NEMS-based table showing estimated changes in energy-related “consumer-side” GHG emiss ions. We use the terms “consumer-side” emissions to distinguish emissions from the consump tion of fuel from emissions specifically associated with the extraction, processing, and tra nsportation of fuels in the oil and natural gas
sector under examination in this RIA. We term the emissions associated with extraction, processing, and transportation of fuels “producer-s ide” emissions.7-20

Table 7-12 Modeled Change in Energy-related "Consum er-Side" CO 2 -equivalent GHG Emissions Future NSPS Scenario, 2015
2011 Baseline Option 1 Option 2 (Proposed) Option 3 Energy-related CO 2 -equivalent GHG Emissions (million metric tons CO 2 -equivalent) Petroleum 2,359.59 2,433.60 2,433.12 2,433.49 2,43 3.45 Natural Gas 1,283.78 1,352.20 1,354.47 1,353.19 1, 352.87 Coal 1,946.02 1,882.08 1,879.84 1,883.24 1,883.30 Other 11.99 11.99 11.99 11.99 11.99 Total 5,601.39 5,679.87 5,679.42 5,681.91 5,681.61
% Change in Energy-related CO 2 -equivalent GHG Emissions from Baseline Petroleum -0.02% 0.00% -0.01% Natural Gas 0.17% 0.07% 0.05% Coal -0.12% 0.06% 0.06% Other 0.00% 0.00% 0.00% Total -0.01% 0.04% 0.03%

Note: Excludes “producer-side” emissions and emissi ons reductions estimated to result from NSPS altern atives. Totals may not sum due to independent rounding.

As is shown in Table 7-12, NSPS Option 1 is predict ed to slightly decrease aggregate consumer-side energy-related CO 2 -equivalent GHG emissions, by about 0.01 percent, w hile the mix of emissions shifts slightly away from coal and petroleum toward natural gas. Proposed Options 2 and 3 are estimated to increase consumer- side aggregate energy-related CO 2 - equivalent GHG emissions by about 0.04 and 0.03 per cent, respectively, mainly because consumer-side emissions from natural gas and coal c ombustion increase slightly.

7.3 Employment Impact Analysis

While a standalone analysis of employment impacts i s not included in a standard costbenefit analysis, such an analysis is of particular concern in the current economic climate of sustained high unemployment. Executive Order 13563, states, “Our regulatory system must protect public health, welfare, safety, and our env ironment 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 p roviding an estimate of the employment impacts of the proposed regulations using labor req uirements for the installation, operation, and7-21

maintenance of control requirements, as well as rep orting and recordkeeping requirements. Unlike several recent RIAs, however, we do not prov ide employment impacts estimates based on the study by Morgenstern et al. (2002); we discuss this decision after presenting estimates of the labor requirements associated with reporting and re cordkeeping and the installation, operation, and maintenance of control requirements.

7.3.1 Employment Impacts from Pollution Control Requireme nts

Regulations set in motion new orders for pollution control equipment and services. New categories of employment have been created in the p rocess 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 t o comply with the regulation when it becomes effective. Revenue and employment in the environme ntal technology industry have grown steadily between 2000 and 2008, reaching an industr y total of approximately $300 billion in revenues and 1.7 million employees in 2008. 52 While these revenues and employment figures represent gains for the environmental technologies industry, they are costs to the regulated industries required to install the equipment. More over, it is not clear the 1.7 million employees in 2008 represent new employment as opposed to work ers being shifted from the production of goods and services to environmental compliance acti vities.

Once the equipment is installed, regulated firms hi re workers to operate and maintain the pollution control equipment – much like they hire w orkers to produce more output. Morgenstern et al. (2002) examined how regulated industries res pond to regulation. The authors found that, on average for the industries they studied, employm ent increases in regulated firms. Of course, these firms may also reassign existing employees to perform these activities.

52 In 2008, the industry totaled approximately $315 b illion in revenues and 1.9 million employees includ ing indirect employment effects, pollution abatement equipment p roduction employed approximately 4.2 million worker s in 2008. These indirect employment effects are based o n a multiplier for indirect employment = 2.24 (1982 value from Nestor and Pasurka - approximate middle of ran ge of multipliers 1977-1991). Environmental Busines s International (EBI), Inc., San Diego, CA. Environm ental Business Journal, monthly (copyright). http://www.ebiusa.com/ EBI data taken from the De partment of Commerce International Trade Administra tion Environmental Industries Fact Sheet from April 2010 : http://web.ita.doc.gov/ete/eteinfo.nsf/068f3801d047 f26e85256883006ffa54/4878b7e2fc08ac6d85256883006c45 2c?OpenDocument7-22

Environmental regulations support employment in man y basic industries. In addition to the increase in employment in the environmental pro tection industry (via increased orders for pollution control equipment), environmental regulat ions also support employment in industries that provide intermediate goods to the environmenta l protection industry. The equipment manufacturers, in turn, order steel, tanks, vessels , blowers, pumps, and chemicals to manufacture and install the equipment. Bezdek et al. (2008) fo und that investments in environmental protection industries create jobs and displace jobs , but the net effect on employment is positive.

The focus of this part of the analysis is on labor requirements related to the compliance
actions of the affected entities within the affecte d sector. We do not estimate any potential changes in labor outside of the oil and natural gas sector. This analysis estimates the employment impacts due to the installation, operati on, and maintenance of control equipment, as well as employment associated with new reporting an d recordkeeping requirements.

It is important to highlight that unlike the typica l case where to reduce a bad output (i.e., emissions) a firm often has to reduce production of the good output, many of the emission controls required by the proposed NSPS will simulta neously increase production of the good output and reduce production of bad outputs. That i s, these controls jointly produce environmental improvements and increase output in t he 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 u ndesirable emissions.

No estimates of the labor used to manufacture or as semble pollution control equipment or to supply the materials for manufacture or assembly are included because U.S. EPA does not currently have this information. The employment an alysis uses a bottom-up engineering-based methodology to estimate employment impacts. The en gineering cost analysis summarized in this RIA includes estimates of the labor requirements as sociated with implementing the proposed regulations. Each of these labor changes may eithe r be required as part of an initial effort to comply with the new regulation or required as a con tinuous or annual effort to maintain compliance. We estimate up-front and continual, an nual labor requirements by estimating hours of labor required and converting this number to ful l-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks). We note that this type of FTE estimate7-23

cannot be used to make assumptions about the specif ic number of people involved or whether new jobs are created for new employees.

In other employment analyses U.S. EPA distinguishe d between employment changes within the regulated industry and those changes out side 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 d ifficult. The mix of in-house versus contracting services used by firms is very case-spe cific in the oil and natural gas industry. For example, sometimes the owner of the well, processin g plant, or transmission pipelines uses in– house employees extensively in daily operations, wh ile in other cases the owner relies on outside contractors for many of these services. For this r eason, we make no distinction in the quantitative estimates between labor changes within and outside of the regulated sector.

The results of this employment estimate are presen ted in Table 7-13 for the proposed NSPS and in Table 7-14 for the proposed NESHAP amen dments. The tables breaks down the installation, operation, and maintenance estimates by type of pollution control evaluated in the RIA and present both the estimated hours required a nd the conversion of this estimate to FTE. For both the proposed NSPS and NESHAP amendments, r eporting and recordkeeping requirements were estimated for the entire rules ra ther than by anticipated control requirements; the reporting and recordkeeping estimates are consi stent with estimates EPA submitted as part of its Information Collection Request (ICR).

The up-front labor requirement is estimated at 230 FTEs for the proposed NSPS and about 120 FTEs for the proposed NESHAP amendments. These up-front FTE labor requirements can be viewed as short-term labor requ irements required for affected entities to comply with the new regulation. Ongoing requiremen ts are estimated at about 2,400 FTEs for the proposed NSPS and about 102 FTEs for the propos ed NESHAP amendments. These ongoing FTE labor requirements can be viewed as sus tained labor requirements required for affected entities to continuously comply with the n ew regulation

Two main categories contain the majority of the lab or requirements for the proposed rules: implementing reduced emissions completions ( RECs) and reporting and recordkeeping7-24

requirements for the proposed NSPS. Also, note tha t 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 th at of the controllers that would be used absent the regulation. In this instance, we assume the in cremental labor requirements are zero.

Implementing RECs are estimated to require about 2, 230 FTE, over 90 percent of the total continuing labor requirements for the propose d NSPS. 53 We denote REC-related requirements as continuing, or annual, as the REC r equirements will in fact recur annually, albeit at different wells each year. The REC requirements are associated with certain new well completions or existing well recompletions, which w hile individual completions occur over a short period of time (days to a few weeks), new wel ls and other existing wells are completed or recompleted annually. Because of these reasons, we assume the REC-related labor requirements
are annual.

7.3.2 Employment Impacts Primarily on the Regulated Indus try

In previous RIAs, we transferred parameters from a study by Morgenstern et al. (2002) to estimate employment effects of new regulations. (S ee, for example, the Regulatory Impact Analysis for the recently finalized Industrial Boil ers and CISWI rulemakings, promulgated on February 21, 2011). The fundamental insight of Mor genstern, et al. is that environmental regulations can be understood as requiring regulate d firms to add a new output (environmental quality) to their product mixes. Although legally c ompelled to satisfy this new demand, regulated firms have to finance this additional production wi th the proceeds of sales of their other (market) products. Satisfying this new demand requires addit ional inputs, including labor, and may alter the relative proportions of labor and capital used by regulated firms in their production

processes.

Morgenstern et al. concluded that increased abateme nt expenditures in these industries generally do not cause a significant change in empl oyment. Using plant-level Census

53 As shown on earlier in this section, we project t hat the number of successful natural gas wells dril led in 2015 will decline slightly from the baseline projection. The refore, there may be small employment losses in dri llingrelated employment that partly offset gains in empl oyment from compliance-related activities.7-25

information between the years 1979 and 1991, Morgen stern et al. estimate the size of each effect for four polluting and regulated industries (petrol eum 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 ins ignificant) net increase of 1.55 (+/- 2.24) jobs. A s a result, the authors conclude that increases in po llution abatement expenditures do not necessarily cause economically significant employme nt changes.

For this version of RIA for the proposed NSPS and N ESHAP amendments, however, we chose not to quantitatively estimate employment imp acts using Morgenstern et al. because of reasons specific to the oil and natural gas industr y and proposed rules. We believe the transfer of parameter estimates from the Morgenstern et al. stu dy to the proposed NSPS and NESHAP amendments is beyond the range of the study for two reasons.7-26Table 7-13 Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating,andMaintaining Control Equipment Requirements, Proposed NSPS Option in 2015Source/Emissions Point Emissions ControlProjectedNo. ofAffectedUnitsPer UnitUp- FrontLaborEstimate(hours)Per UnitAnnualLaborEstimate(hours)TotalUp- FrontLaborEstimate(hours)TotalAnnualLaborEstimate(hours)Up-FrontFull-TimeEquivalentAnnualFull-TimeEquivalentWell CompletionsHydraulically Fractured Gas Wells Reduced EmissionsCompletion (REC) 9,313021802,025,8690.0974.0Hydraulically Fractured Gas Wells Combustion 44602209,6260.04.6Well RecompletionsHydraulically Fractured Gas Wells (preNSPS wells) REC 12,050021802,621,1260.01,260.2Equipment LeaksProcessing PlantsNSPS Subpart VVA2958788717,02325,7238.212.4Reciprocating CompressorsGathering/Boosting StationsAMM210112102100.10.1Processing Plants AMM375113753750.20.2Transmission Compressor Stations AMM199111991990.10.1Underground Storage Facilities AMM911990.00.0Centrifugal CompressorsProcessing Plants Dry Seals/Route to Process or Control 1635505,68002.70.0Transmission Compressor Stations Dry Seals/Route toProcess or Control 1435504,97002.40.0Pneumatic ControllersOil and Gas Production Low Bleed/Route to Process 13,63200000.00.0Natural Gas Trans. and Storage Low Bleed/Route to Process 6700000.00.0Storage VesselsHigh Throughput 95% control 30427119082,27957,58239.627.7Reporting and Recordkeeping for Complete NSPS---------360,443201,342173.396.8TOTAL---------471,1874,942,060226.52,376.0Note: Full-time equivalents (FTE) are estimated byfirst multiplying the projected number of affectedunits by the per unit laborrequirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum dueto independent rounding.7-27Table 7-14 Labor-based Employment Estimates for Reporting and Recordkeeping and Installing, Operating,andMaintaining Control Equipment Requirements, Proposed NESHAP Amendments in 2015Source/Emissions Point Emissions ControlProjectedNo. ofAffectedUnitsPer UnitOne-timeLaborEstimate(hours)Per UnitAnnualLaborEstimate(hours)Total OneTime LaborEstimate(hours)TotalAnnualLaborEstimate(hours)One-timeFull-TimeEquivalentAnnualFull-TimeEquivalentSmall Glycol DehydratorsProductionCombustion devices, recovery devices,process modifications 115272853,10832,8211.515.8TransmissionCombustion devices, recovery devices,process modifications 19272855135,4230.22.6Storage VesselsProduction Combustion devices, recovery devices 674311198209,753133,231100.864.1Reporting and Recordkeeping for Complete NESHAP Amendments---------36,46239,92317.519.2TOTAL--------249,836211,398120.1101.6Note: Full-time equivalents (FTE) are estimated byfirst multiplying the projected number of affectedunits by the per unit laborrequirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding.7-28

First, the possibility that the revenues producers are estimated to receive from additional natural gas recovery as a result of the proposed NSPS might offset the costs of complying with the rule presents challenges to estimating employment effect s (see Section 3.2.2.1 of the RIA for a detailed discussion of the natural gas recovery). The Morgenstern et al. paper, for example, is intended to analyze the impact of environmental com pliance expenditures on industry employment levels, and it may not be appropriate to draw on their demand and net effects when compliance costs are expected to be negative.

Second, the proposed regulations primarily affect t he natural gas production, processing, and transmission segments of the industry. While t he natural gas processing segment of the oil and natural gas industry is similar to petroleum re fining, which is examined in Morgenstern et al., the production side of the oil and natural gas (drilling and extraction, primarily) and natural gas pipeline transmission are not similar to petrol eum refining. Because of the likelihood of negative compliance costs for the proposed NSPS and the segments of the oil and natural gas industry affected by the proposals are not examined by Morgenstern et al., we decided not to use the parameters estimated by Morgenstern et al. to e stimate within-industry employment effects for the proposed oil and natural gas NESHAP amendme nts and NSPS.

That said, the likelihood of additional natural gas recovery is an important component of the market response to the rule, as it is expected that this additional natural gas recovery will reduce the price of natural gas. Because of the es timated fall in prices in the natural gas sector due to the proposed NSPS, prices in other sectors t hat consume natural gas are likely drop slightly due to the decrease in energy prices. Thi s small production increase and price decrease may have a slight stimulative effect on employment in industries that consume natural gas.

7.4 Small Business Impacts Analysis

The Regulatory Flexibility Act as amended by the Sm all Business Regulatory Enforcement Fairness Act (SBREFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemakin g requirements under the Administrative Procedure Act or any other statute, unless the agen cy certifies that the rule will not have a7-29

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

After considering the economic impact of the propos ed rules on small entities for both the NESHAP and NSPS, the screening analysis indicates t hat these proposed rules will not have a significant economic impact on a substantial number of small entities (or “SISNOSE”). The supporting analyses for these determinations are pr esented in this section of the RIA.

As discussed in previous sections of the economic i mpact analysis, under the proposed NSPS, some affected producers are likely to be able to recover natural gas that would otherwise be vented to the atmosphere, as well as recover sal eable 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 im plemented as a result of the Proposed NSPS. Because the total costs of the rule are likely to b e more than offset by the revenues producers gain from increased natural gas recovery, we expect there will be no SISNOSE arising from the proposed NSPS. However, not all components of the proposed NSPS are estimated to have cost savings. Therefore, we analyze potential impacts t o better understand the potential distribution of impacts across industry segments and firms. We feel taking this approach strengthens the
determination that there will be no SISNOSE. Unlik e the controls for the proposed NSPS, the controls evaluated under the proposed NESHAP amendm ents do not recover significant quantities of natural gas products.

7.4.1 Small Business National Overview
The industry sectors covered by the final rule were identified during the development of the engineering cost analysis. The U.S. Census Bur eau’s Statistics of U.S. Businesses (SUSB) provides national information on the distribution o f economic variables by industry and enterprise size. The Census Bureau and the Office o f Advocacy of the Small Business Administration (SBA) supported and developed these files for use in a broad range of economic analyses. 54 Statistics include the total number of establishmen ts, and receipts for all entities in an industry; however, many of these entities may not n ecessarily be covered by the final rule. SUSB also provides statistics by enterprise employment a nd receipt size (Table 7-15 and Table 7-16).

54 See http://www.census.gov/csd/susb/ and http://www. sba.gov/advocacy/ for additional details.7-30

The Census Bureau’s definitions used in the SUSB ar e as follows:

 Establishmen t: A single physical location where business is con ducted or where services or industrial operations are performed.

 Firm: A firm is a business organization consisting of on e or more domestic establishments in the same state and industry that were specified under common ownership or control. The firm and the establishmen t are the same for singleestablishment firms. For each multi-establishment f irm, establishments in the same industry within a state will be counted as one firm - the firm employment and annual payroll are summed from the associated establishmen ts.

 Receipts : Receipts (net of taxes) are defined as the revenu e for goods produced, distributed, or services provided, including revenu e earned from premiums, commissions and fees, rents, interest, dividends, a nd royalties. Receipts exclude all revenue collected for local, state, and federal tax es.

 Enterprise : An enterprise is a business organization consisti ng of one or more domestic establishments that were specified under c ommon ownership or control. The enterprise and the establishment are the same for s ingle-establishment firms. Each multi-establishment company forms one enterprise—th e enterprise employment and annual payroll are summed from the associated estab lishments. Enterprise size designations are determined by the sum of employmen t of all associated establishments.

Because the SBA’s business size definitions (SBA, 2 008) apply to an establishment’s “ultimate parent company,” we assumed in this analysis that t he “firm” definition above is consistent with the concept of ultimate parent company that is typi cally used for SBREFA screening analyses, and the terms are used interchangeably.7-31Table 7-15 Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007Owned by Firms with:NAICS NAICS DescriptionSBA SizeStandard(effectiveNov. 5,2010)< 20Employees20-99Employees100-499EmployeesTotal <500Employees> 500Employees Total FirmsNumber of Firms by Firm Size211111 Crude Petroleum and Natural Gas Extraction 500 5,759 455 115 6,329 95 6,424211112 Natural Gas Liquid Extraction 500 77 9 12 9841 139213111 Drilling Oil and Gas Wells 500 1,580 333 972,010 49 2,059486210 Pipeline Transportation of Natural Gas $7.0million 63 12 9 84 42 126Total Employment by Firm Size211111 Crude Petroleum and Natural Gas Extraction 500 21,170 16,583 17,869 55,622 77,664 133,286211112 Natural Gas Liquid Extraction 500 372 305 1,198 1,875 6,648 8,523213111 Drilling Oil and Gas Wells 500 5,972 13,78716,893 36,652 69,774 106,426486210 Pipeline Transportation of Natural Gas $7.0million 241 382 1,479 2,102 22,581 24,683Estimated Receipts by Firm Size ($1000)211111 Crude Petroleum and Natural Gas Extraction 500 12,488,688 15,025,443 17,451,805 44,965,936 149,141,316 194,107,252211112 Natural Gas Liquid Extraction 500 209,640 217,982 1,736,706 2,164,328 37,813,413 39,977,741213111 Drilling Oil and Gas Wells 500 1,101,481 2,460,301 3,735,652 7,297,434 16,550,804 23,848,238486210 Pipeline Transportation of Natural Gas $7.0million 332,177 518,341 1,448,020 2,298,538 18,498,143 20,796,681Source: U.S. Census Bureau. 2010. “Number of Firms,Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterprise Receipt Size for theUnited States, All Industries: 2007.” <http://www.census.gov/econ/susb/>7-32

Table 7-16 Distribution of Small and Large Firms by Number of Firms, Total Employment, and Estimated Receipts by Firm Size and NAICS, 2007
Percent of Firms

NAICS NAICS Description Total Firms Small Businesses Large

Businesses Total Firms Number of Firms by Firm Size 211111 Crude Petroleum and Natural Gas Extraction 6 ,424 98.5% 1.5% 100.0% 211112 Natural Gas Liquid Extraction 139 70.5% 29.5% 100.0% 213111 Drilling Oil and Gas Wells 2,059 97.6% 2.4% 100.0% 486210 Pipeline Transportation of Natural Gas 126 48.4% 51.6% 100.0%

Total Employment by Firm Size 211111 Crude Petroleum and Natural Gas Extraction 1 33,286 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 24,68 3 N/A* N/A* N/A*
Estimated Receipts by Firm Size ($1000) 211111 Crude Petroleum and Natural Gas Extraction 1 94,107,252 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 20,79 6,681 N/A* N/A* N/A* Note: Employment and receipts could not be broken d own between small and large businesses because of n ondisclosure requirements. Source: SBA

While the SBA and Census Bureau statistics provide informative broad contextual information on the distribution of enterprises by r eceipts and number of employees, it is also useful to additionally contrast small and large ent erprises (where large enterprises are defined as those that are not small, according to SBA criteria ) in the oil and natural gas industry. The summary statistics presented in previous tables ind icate that there are a large number of relatively small firms and a small number of large firms. Given the majority of expected impacts of the proposed rules arises from well completion-r elated requirements, which impacts production activities, exclusively, some explanatio n of this particular market structure is warranted as it pertains to production and small en tities. An important question to answer is whether there are particular roles that small entit ies serve in the production segment of the oil and natural gas industry that may be disproportiona tely affected by the proposed rules.7-33

The first important broad distinction among firms i s whether they are independent or integrated. Independent firms concentrate on explo ration and production (E&P) activities, while integrated firms are vertically integrated and ofte n have operations in E&P, processing, refining, transportation, and retail. To our awareness, ther e are no small integrated firms. Independent firms may own and operate wells or provide E&P-rela ted services to the oil and gas industry. Since we are focused on evaluating potential impact s to small firms owning and operating new and existing hydraulically fractured wells, we shou ld narrow down on this sector.

In our understanding, there is no single industry n iche for small entities in the production segment of the industry since small operators have different business strategies and that small entities can own different types of wells. The org anization of firms in oil and natural gas industry also varies greatly from firm to firm. Ad ditionally, oil and natural gas resources vary widely geographically and can vary significantly wi thin a single field.

Among many important roles, independent small opera tors historically pioneered exploration in new areas, as well as developed new technologies. By taking on these relatively large risks, these small entrepreneurs (wildcatters ) have been critical sources of industrial innovation and opened up critical new energy suppli es for the U.S. (HIS Global Insight). In recent decades, as the oil and gas industry has con centrated via mergers, many of these smaller firms have been absorbed into large firms.

Another critical role, which provides an interestin g contrast to small firms pioneering new territory, is that smaller independents maintai n and operate a large proportion of the Nation’s low producing wells, which are also known as marginal or stripper wells (Duda et al. 2005). While marginal wells represent about 80 per cent of the population of producing wells, they produce about 15 percent of domestic productio n, according to EIA (Table 7-17).7-34

Table 7-17 Distribution of Crude Oil and Natural Ga s Wells by Productivity Level, 2009

Type of Wells Wells (no.) Wells (%) Production (MMbbl for oil and Bcf gas) Production (%) Crude Oil Stripper Wells (<15 boe per year) 310,552 85% 311 19% Other Wells (>=15 boe per year) 52,907 15% 1,331 81% Total Crude Oil Wells 363,459 100% 1,642 100% Natural Gas Natural Gas Stripper Wells (<15 boe per year) 338,0 56 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_tabl e.html> Accessed 7/10/11. Note: Natural gas production converted to barrels o il equivalent (boe) uses the conversion of 0.178 ba rrels of crude oil to 1000 cubic feet natural gas.

Many of these wells were likely drilled and initial ly operated by major firms (although the data are not available to quantify the percenta ge of wells initially drilled by small versus large producers). Well productivity levels typical ly follow a steep decline curve; high production in earlier years but sustained low produ ction for decades. Because of relatively low overhead of maintaining and operating few relativel y co-located wells, some small operators with a particular business strategy purchase low pr oducing wells from the majors, who concentrate on new opportunities. As small operat ors have provided important technical innovation in exploration, small operators have als o been sources of innovation in extending the productivity and lifespan of existing wells (Duda e t al. 2005).

7.4.2 Small Entity Economic Impact Measures

The proposed Oil and Natural Gas NSPS and NESHAP am endments 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 entiti es that will bear the financial impacts associated with these additional operating costs. The proposed rule has the potential to impact all firms owning affected facilities, both large and small.7-35

The analysis provides EPA with an estimate of the m agnitude of impacts the proposed NSPS and NESHAP amendments may have on the ultimate domestic parent companies that own facilities EPA expects might be impacted by the rul es. The analysis focuses on small firms because they may have more difficulty complying wit h a new regulation or affording the costs associated with meeting the new standard. This sect ion presents the data sources used in the screening analysis, the methodology we applied to d evelop estimates of impacts, the results of the analysis, and conclusions drawn from the result s.

The small business impacts analysis for the NSPS an d NESHAP amendments relies upon a series of firm-level sales tests (represented as cost-to-revenue ratios) for firms that are likely t o be associated with NAICS codes listed in Table 7-15 . For both the NSPS and NESHAP amendments, we obtained firm-level employment, reve nues, and production levels using various sources, including the American Business Directory, the Oil and Gas Journal , corporate websites, and publically-available financial report s. Using these data, we estimated firm-level compliance cost impacts and calculated cost-to-reve nue ratios to identify small firms that might be significantly impacts by the rules. The approac hes taken for the NSPS and NESHAP amendments differed; more detail on approaches for each set of proposed rules is presented in the following sections.

For the sales test, we divided the estimates of ann ualized establishment compliance costs by estimates of firm revenue. This is known as the cost-to-revenue ratio, or the “sales test.” The “sales test” is the impact methodology EPA employs in analyzing small entity impacts as opposed to a “profits test,” in which annualized co mpliance costs are calculated as a share of profits. The sales test is often used because reve nues or sales data are commonly available for entities impacted by EPA regulations, and profits d ata normally made available are often not the true profit earned by firms because of accounting a nd tax considerations. Revenues as typically published are correct figures and are more reliably reported when compared to profit data. The use of a “sales test” for estimating small business impacts for a rulemaking such as this one is consistent with guidance offered by EPA on complian ce with SBREFA 55 and is consistent with guidance published by the U.S. SBA’s Office of Advo cacy that suggests that cost as a percentage

55 The SBREFA compliance guidance to EPA rulewriters regarding the types of small business analysis that should be considered can be found at <http://www.epa.gov/s brefa/documents/rfaguidance11-00-06.pdf>7-36

of total revenues is a metric for evaluating cost i ncreases on small entities in relation to increases on large entities (U.S. SBA, 2010). 568

7.4.3 Small Entity Economic Impact Analysis, Proposed NSP S

7.4.3.1 Overview of Sample Data and Methods

The proposed NSPS covers emissions points within va rious stages of the oil and natural gas production process. We expect that firms withi n multiple NAICS codes will be affected, namely the NAICS categories presented in Table 7-15 . Because of the diversity of the firms potentially affected, we decided to analyze three d istinct groups of firms within the oil and natural gas industry, while accounting for overlap across the groups. We analyze firms that are involved in oil and natural gas extraction that are likely to drill and operate wells, while a subset are integrated firms involved in multiple segments of production, as well as retailing products. We also analyze firms that primarily operate natura l gas processing plants. A third set of firms we analyzed contains firms that primarily operate n atural gas compression and pipeline
transmission.

To identify firms involved in the drilling and prim ary production of oil and natural gas, we relied upon the annual Oil and Gas Journal 150 Survey (OGJ 150) as described in the Industry Profile in Section 2. While the OGJ 150 l ists public firms, we believe the list is reasonably representative of the larger population of public and private firms operating in this segment of the industry. While the proportion of s mall firm in the OGJ 150 is smaller than the proportion evaluated by the Census SUSB, the OGJ 15 0 provides detailed information on the production activities and financial returns of the firms within the list, which are critical ingredients to the small business impacts analysis. We drew upon the OGJ 150 lists published for the years 2008 and 2009 ( Oil and Gas Journal , September 21, 2009 and Oil and Gas Journal
, September 6, 2010). The year 2009 saw relatively l ow levels of drilling activities because of the economic recession, while 2008 saw a relatively hig h level of drilling activity because of high fuel prices. Combined, we believe these two years of data are representative.

56 U.S. SBA, Office of Advocacy. A Guide for Governmen t Agencies, How to Comply with the Regulatory Flexibility Act, Implementing the President’s Small Business Agenda and Executive Order 13272, June 20 10.7-37

To identify firms that process natural gas, the OGJ also releases a period report entitled “Worldwide Gas Processing Survey”, which provides a wide range of information on existing processing facilities. We used the most recent lis t of U.S. gas processing facilities 57 and other resources, such as the American Business Directory and company websites, to best identify the parent company of the facilities. To identify firm s that compress and transport natural gas via pipelines, we examined the periodic OGJ survey on t he economics of the U.S. pipeline industry. This report examines the economic status of all maj or and non-major natural gas pipeline companies. 58 For these firms, we also used the American Busine ss Directory and corporate websites to best identify the ultimate owner of the facilities or companies.

After combining the information for exploration and production firms, natural gas processing firms, and natural gas pipeline transmis sion firms in order to identify overlaps across the list, the approach yielded a sample of 274 firm s that would potentially be affected by the proposed NSPS in 2015 assuming their 2015 productio n activities were similar to those in 2008 and 2009. We estimate that 129 (47 percent) of the se firms are small according to SBA criteria. We estimate 121 firms (44 percent) are not small fi rms according to SBA criteria. We are unable to classify the remaining 24 firms (9 percent) beca use of a lack of required information on employee counts or revenue estimates.

Table 7-18 shows the estimated revenues for 250 fir ms for which we have sufficient data that would be potentially affected by the proposed NSPS based upon their activities in 2008 and 2009. We segmented the sample into four groups, pr oduction and integrated firms, processing firms, pipeline firms, and pipelines/processing fir ms. For the firms in the pipelines/processing group, we were unable to determine the firms’ prima ry line of business, so we opted to group together as a fourth group.

57 Oil and Gas Journal. “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Proce ssing Capacity Ahead in 2009.” June 7, 2010. 58 Oil and Gas Journal. “Natural Gas Pipelines Continu e Growth Despite Lower Earnings; Oil Profits Grow.” November 1, 2010.7-38

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

Number of Firms Estimated Revenues (millions, 2008 dollars) Firm Type/Size Total Average Median Minimum Maximum Production and Integrated Small 79 18,554.5 234.9 76.3 0.1 1,116.9 Large 49 1,347,463.0 27,499.2 1,788.3 12.9 310,586. 0 Subtotal 128 1,366,017.4 10,672.0 344.6 0.1 310,586 .0 Pipeline Small 11 694.5 63.1 4.6 0.5 367.0 Large 36 166,290.2 4,619.2 212.9 7.1 112,493.0 Subtotal 47 166,984.6 3,552.9 108.0 0.5 112,493.0 Processing Small 39 4,972.1 127.5 26.9 1.9 1,459.1 Large 23 177,632.1 8,881.6 2,349.4 10.4 90,000.0 Subtotal 62 182,604.2 3,095.0 41.3 1.9 90,000.0 Pipelines/Processing Small 0 N/A N/A N/A N/A N/A Large 13 175,128.5 13,471.4 6,649.4 858.6 71,852.0 Subtotal 13 175,128.5 13,471.4 6,649.4 858.6 71,852 .0 Total Small 129 24,221.1 187.8 34.9 0.1 1,459.1 Large 121 1,866,513.7 15,817.9 1,672.1 7.1 310,586. 0 Total 250 1,890,734.8 7,654.8 163.9 0.1 310,586.0 Sources: Oil and Gas Journal . “OGJ150.” September 21, 2009; Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. Oil and Gas Journal . “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Proces sing Capacity Ahead in 2009.” June 7, 2010, with ad ditional 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 w ithin the sample are concentrated on integrated firms and firms engaged in production ac tivities (the E&P firms mentioned earlier).7-39

The oil and natural gas industry is capital-intens ive. To provide more context on the potential impacts of new regulatory requirements, T able 7-19 presents descriptive statistics for small and large integrated and production firms fro m the sample of firms (121 of the 128 integrated and production firms listed in the Oil and Gas Journal ; capital and exploration expenditures for 7 firms were not reported in the Oil and Gas Journal ).

Table 7-19 Descriptive Statistics of Capital and Ex ploration 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 Maxim um Small 76 13,478.8 177.4 67.1 0.1 2,401.9 Large 45 126,749.3 2,816.7 918.1 10.3 22,518.7 Total 121 140,228.2 1,158.9 192.8 0.1 22,518.7

Sources: Oil and Gas Journal . “OGJ150.” September 21, 2009; Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. American Business Directory was used to determine number of employees.

The average 2008 and 2009 total capital and explora tion expenditures for the sample of 121 firms were $140 billion in 2008 dollars). About 10 percent of this total was spent by small firms. Average capital and explorations expenditures for s mall firms are about 6 percent of large firms; median expenditures of small firms are about 7 perc ent of large firms’ expenditures. For small firms, capital and exploration expenditures are hig h relative to revenue, which appears to hold true more generally for independent E&P firms compa red 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 rev enues and capital and exploration expenditures.

Table 7-20 breaks down the estimated number of nat ural gas and crude oil wells drilled by the 121 firms in the sample for which the Oil and Gas Journal information reported welldrilling estimates. Note the fractions on the mini mum and maximum statistics; the fractions reported are due to our assumptions to estimate oil and natural gas wells drilled from the total wells drilled reported by the Oil and Gas Journal . The OGJ150 lists new wells drilled by firm in 2008 and 2009, but the drilling counts are not spec ific to crude oil or natural gas wells. We7-40

apportion the wells drilled to natural gas and crud e 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 Well s Drilled, Small and Large Firms in Sample, 2008 and 2009 (million 2008 dollars) Estimated Average Wells Natural Gas and Crude Oil W ells Drilled (2008 and 2009) Well Type Firm Size Number of Firms Total Average Median Minimum Maximum Natural Gas

Small 76 2,288.3 30.1 6.0 0.2 259.3 Large 45 9,445.1 209.9 149.1 0.6 868.3 Subtotal 121 11,733.4 97.0 28.3 0.2 868.3 Crude Oil Small 76 1,317.1 17.3 3.5 0.1 149.2

Large 45 5,436.3 120.8 85.8 0.4 499.7 Subtotal 121 6,753.4 55.8 16.3 0.1 499.7 Total Small 76 3,605.4 47.4 9.5 0.0 408.5

Large 45 14,881.4 330.7 234.9 0.0 1,368.0 Total 121 18,486.8 152.8 44.6 0.0 1,368.0

Sources: Oil and Gas Journal . “OGJ150.” September 21, 2009; Oil and Gas Journal . “OGJ150 Financial Results Down in '09; Production, Reserves Up.” September 6, 2010. American Business Directory was used to determine number of employees.

This table highlights the fact that many firms dril l relatively few wells; the median for small firms is 6 natural gas wells compared to 149 for la rge firms. Later in this section, we examine whether this distribution has implications for the engineering costs estimates, as well as the estimates of expected natural product recovery from controls such as RECs.

Unlike the analysis that follows for the analysis o f impacts on small business from the NESHAP amendments, we have no specific data on pote ntially affected facilities under the NSPS. The NSPS will apply to new and modified sour ces, for which data are not fully available in advance, particularly in the case of new and mod ified sources such as well completions and recompletions which are spatially diffuse and poten tially large in number.

The engineering cost analysis estimated compliance costs in a top-down fashion, projecting the number of new sources at an annual l evel and multiplying these estimates by7-41

model unit-level costs to estimate national impacts . To estimate per-firm compliance costs in this analysis, we followed a procedure similar to t hat of entering estimate compliance costs in NEMS on a per well basis. We first use the OGJ150- based list to estimate engineering compliance costs for integrated and production comp anies that may operate facilities in more than one segment of the oil and natural gas industr y. We then estimate the compliance costs per crude oil and natural gas well by totaling all comp liance costs estimates in the engineering cost estimates for the proposed NSPS and dividing that c ost by the total number of crude oil and natural gas wells forecast as of 2015, the year of analysis. These compliance costs include the expected revenue from natural gas and condensate re covery that result from implementation of some proposed controls.

This estimation procedure yielded an estimate of cr ude well compliance costs of $162 per drilled well and natural gas well compliance costs of $38,719 without considering estimated revenues from product recovery and -$2,455 per dril led well with estimated revenues from product recovery included. Note that the divergenc e of estimated per well costs between crude oil and natural gas wells is because the proposed N SPS requirements are primary directed toward natural gas wells. Also note that the per well cos t savings estimate for natural gas wells is different than the estimated cost of implementing a REC; this difference is because this estimate is picking up savings from other control options. We then estimate a single-year, firm-level compliance cost for this subset of firms by multipl ying the per well cost estimates with the well
count estimates.

The OGJ reports plant processing capacity in terms of MMcf/day. In the energy system impacts analysis, the NEMS model estimates a 6.5 pe rcent increase (from 21.05 tcf in 2011 to 22.43 tcf in 2015) in domestic natural gas producti on from 2011 to 2015, the analysis year. On this, basis, we estimate that natural gas processin g capacity for all plants in the OGJ list will increase 1.3 percent per year. This annual increme nt is equivalent to an increase in national gas processing capacity of 350 bcf per year. We assume that the engineering compliance costs estimates associated with processing are distribute d according to the proportion of the increased national processing capacity contributed by each pr ocessing plant. These costs are estimated at $6.9 million without estimated revenues from produc t recovery and $2.3 million with estimated7-42

revenues from product recovery, respectively, in 20 08 dollars, or about $20/MMcf without revenues and $7/MMcf with revenues.

The OGJ report on pipeline companies has the advant age that it reports expenditures on plant additions. We assume that the firm-level pro posed compression and transmission-related NSPS compliance costs are proportional to the expen ditures on plant additions and that these additions reflect a representative year or this ana lysis. We estimate the annual compression and transmission-related NSPS compliance costs at $5.5 million without estimated revenues from product recovery and $3.7 million with estimated re venues from product recovery, respectively,
in 2008 dollars.

7.4.3.2 Small Entity Impact Analysis, Proposed NSPS, Result s Summing estimated annualized engineering compliance costs across industry segment and individual firms in our sample, we estimate fir ms in the OGJ-based sample will face about $480 million in 2008 dollars, about 65 percent of t he estimated annualized costs of the Proposed NSPS without including revenues from additional pro duct recovery ($740 million). When including revenues from additional product recovery , the estimated compliance costs for the firms in the sample is about -$23 million, compare d to engineering cost estimate of -$45 million.

Table 7-21 presents the distribution of estimated p roposed NSPS compliance costs across firm size for the firms within our sample. Evident from this table, about 98 percent of the estimated engineering compliance costs accrue to th e integrated and production segment of the industry, again explain by the fact that completion -related requirements contribute the bulk of the estimated engineering compliance costs (as well as estimated emissions reductions). About 17 percent of the total estimated engineering complian ce costs (and about 18 percent of the costs accruing the integrated and production segment) are focused on small firms.7-43

Table 7-21 Distribution of Estimated Proposed NSPS Compliance Costs Without Revenues from Additional Natural Gas Product Recove ry across Firm Size in Sample of Firms

Number of Firms Estimated Engineering Compliance Costs Without Esti mated Revenues from Natural Gas Product Recovery (2008 dollars) Firm Type/Size Total Mean Median Minimum Maximum Production and Integrated Small 79 82,293,903 1,041,695 221,467 3,210 10,054,401 Large 49 387,489,928 7,907,958 5,730,634 15,238 33,677,388 Subtotal 128 469,783,831 3,670,186 969,519 3,210 33,677,388 Pipeline Small 11 3,386 308 111 18 1,144 Large 36 1,486,929 41,304 3,821 37 900,696 Subtotal 47 1,490,314 31,709 2,263 18 900,696 Processing Small 39 476,165 12,209 1,882 188 276,343 Large 23 859,507 37,370 8,132 38 423,645 Subtotal 62 1,335,672 21,543 2,730 38 423,645 Pipelines/Processing Small 0 N/A N/A N/A N/A N/A Large 13 5,431,510 417,808 147,925 2,003 2,630,236 Subtotal 13 5,431,510 417,808 147,925 2,003 2,630,236 Total Small 129 82,773,454 641,655 49,386 18 10,054,401 Large 121 395,267,874 3,266,677 57,220 37 33,677,388 Total 250 478,041,328 1,912,165 55,888 18 33,677,388

These distributions are similar when the revenues f rom expected natural gas recovery are included (Table 7-22). About 21 percent of the tot al savings from the proposed NSPS is expected to accrue to small firms (about 19 percent of the savings to the integrated and production segment accrue to small firms). Note al so in Table 7-22 that the pipeline and processing segments (and the pipeline/processing fi rms) are not expected to experience net cost savings (negative costs) from the proposed NSPS.7-44

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

Number of Firms Estimated Engineering Compliance Costs With Estimat ed Revenues from Natural Gas Product Recovery (millions, 2008 dollar s) Firm Type/Size Total Mean Median Minimum Maximum Production and Integrated Small 79 -5,065,551 -64,121 -13,729 -620,880 8,699 Large 49 -22,197,126 -453,003 -318,551 -2,072,384 423,760 Subtotal 128 -27,262,676 -212,990 -43,479 -2,072,384 423,760 Pipeline Small 11 2,303 209 76 12 779 Large 36 1,011,572 28,099 2,599 25 612,753 Subtotal 47 1,013,876 21,572 1,539 12 612,753 Processing Small 39 160,248 4,109 634 63 93,000 Large 23 289,258 12,576 2,737 13 142,573 Subtotal 62 449,506 7,250 919 13 142,573 Pipelines/Processing Small 0

--- --- --- --- --- Large 13 3,060,373 235,413 86,301 716 1,746,730 Subtotal 13 3,060,373 235,413 86,301 716 1,746,730 Total Small 129 -4,902,999 -38,008 -2,520 -620,880 93,000 Large 121 -17,835,922 -147,404 634 -2,072,384 1,746,730 Total 250 -22,738,922 -90,956 22 -2,072,384 1,746,7307-45

Table 7-23 Summary of Sales Test Ratios, Without Re venues from Additional Natural Gas Product Recovery for Firms Affected by Proposed NSPS

Number of Firms Descriptive Statistics for Sales Test Ratio Without Estimated Revenues from Natural Gas Product Recovery (%) Firm Type/Size Mean Median Minimum Maximum Production and Integrated Small 79 2.18% 0.49% 0.01% 50.83% Large 49 0.41% 0.28% <0.01% 2.83% Subtotal 128 1.50% 0.39% <0.01% 50.83% Pipeline Small 11 <0.01% <0.01% <0.01% 0.01% Large 36 0.01% <0.01% <0.01% 0.06% Subtotal 47 0.01% <0.01% <0.01% 0.06% Processing Small 39 0.05% 0.01% <0.01% 0.33% Large 23 0.02% 0.01% <0.01% 0.15% Subtotal 62 0.04% 0.01% <0.01% 0.33% Pipelines/Processing Small 0 --- --- --- --- Large 13 <0.01% <0.01% <0.01% 0.01% Subtotal 13 <0.01% <0.01% <0.01% 0.01% Total Small 129 1.34% 0.15% <0.01% 50.83% Large 121 0.17% 0.01% <0.01% 2.83% Total 250 0.78% 0.03% <0.01% 50.83%

The mean cost-sales ratio for all businesses when estimated product recovery is excluded from the analysis of the sample data is 0.78 percen t, with a median ratio of 0.03 percent, a minimum of less than 0.01 percent, and a maximum of over 50 percent (Table 7-23). For small firms in the sample, the mean and median cost-sales ratios are 1.34 percent and 0.15 percent, respectively, with a minimum of less than 0.01 perc ent and a maximum of over 50 percent (Table 7-23). Each of these statistics indicates t hat, when considered in the aggregate, impacts are relatively higher on small firms than large fir ms when the estimated revenue from additional natural gas product recovery is excluded. However, as the next table shows, the reverse is true when these revenues are included.7-46

Table 7-24 Summary of Sales Test Ratios, With Reven ues from Additional Natural Gas Product Recovery for Firms Affected by Proposed NSP S

Number of Firms Descriptive Statistics for Sales Test Ratio With Es timated Revenues from Natural Gas Product Recovery (%) Firm Type/Size Mean Median Minimum Maximum Production and Integrated Small 79 -0.13% -0.03% -2.96% <0.00% Large 49 -0.02% -0.02% -0.17% 0.06% Subtotal 128 -0.09% -0.02% -2.96% 0.06% Pipeline Small 11 <0.00% <0.01% <0.01% 0.01% Large 36 0.01% <0.01% <0.01% 0.04% Subtotal 47 0.01% <0.01% <0.01% 0.04% Processing Small 39 0.01% <0.01% <0.01% 0.05% Large 23 <0.00% <0.01% <0.01% 0.05% Subtotal 62 0.01% <0.01% <0.01% 0.05% Pipelines/Processing Small 0 --- --- --- --- Large 13 <0.01% <0.01% <0.01% 0.01% Subtotal 13 <0.01% <0.01% <0.01% 0.01% Total Small 129 -0.08% -0.01% -2.96% 0.05% Large 121 -0.01% <0.01% -0.17% 0.06% Total 250 -0.04% <0.01% -2.96% 0.06%

The mean cost-sales ratio for all businesses when estimated product recovery is included is in the sample is -0.04 percent, with a median ra tio of less than 0.01 percent, a minimum of -2.96 percent, and a maximum of 0.06 percent (Table 7-24). For small firms in the sample, the mean and median cost-sales ratios are -0.08 percent and -0.01 percent, respectively, with a minimum of -2.96 percent and a maximum of 0.05 perc ent (Table 7-24). Each of these statistics indicates that, when considered in the aggregate, i mpacts are small on small business when the estimated revenue from additional natural gas produ ct recovery are included, the reverse of the conclusion found when these revenues are excluded.
Meanwhile, Table 7-25 presents the distribution of estimated cost-sales ratios for the small firms in our sample with and without includin g estimates of the expected natural gas product recover from implementing controls. When r evenues estimates are included, all 1297-47

firms (100 percent) have estimated cost-sales ratio s less than 1 percent. While less than 1 percent, the highest cost-sales ratios for small fi rms in the sample experiencing impacts are largely driven by costs accruing to processing and pipeline firms. That said, the incremental costs imposed on firms that process natural gas or transport natural gas via pipelines are not estimated to create significant impacts on a cost-s ales ratio basis at the firm-level.

Table 7-25 Impact Levels of Proposed NSPS on Small Firms as a Percent of Small Firms in Sample, With and Without Revenues from Additiona l Natural Gas Product Recovery Without Estimated Revenues from Natural

Gas Product Recovery With Estimated Revenues from Natural Gas Product Recovery

Impact Level Number of Small

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

Sample Estimated to be Affected Number of Small

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

Sample Estimated to be Affected C/S Ratio less than 1% 109 84.5% 129 100.00% C/S Ratio 1-3% 11 8.5% 0 0.00% CS Ratio greater than 3% 9 7.0% 0 0.00%

When the estimated revenues from product recovery a re not included in the analysis, 11 firms (about 9 percent) are estimated to have sales test ratios between 1 and 3 percent. Nine firms (about 7 percent) are estimated to have sales test ratios greater than 3 percent. These results noted, the exclusion of product recovery is somewha t artificial. While the mean engineering compliance costs and revenues estimates are valid, drawing on the means ignores the distribution around the mean estimates, which risks masking effe cts. Because of this risk, the following section offers a qualitative discussion of small en tities with regard to obtaining REC services, the validity of the cost and performance of RECs for sm all firms, as well as offers a discussion about whether older equipment, which may be disproportion ately owned and operated be smaller producers, would be affected by the proposed NSPS.7-48

7.4.3.3 Small Entity Impact Analysis, Proposed NSPS, Additi onal Qualitative Discussion

3.5.3.3.1 Small Entities and Reduced Emissions Com pletions Because REC requirements of the proposed NSPS are e xpected to contribute the large majority of engineering compliance costs, it is imp ortant to examine these requirements more closely in the context small entities. Important i ssues to resolve are the scale of REC costs within a drilling project, how the payment system f or recovered natural gas functions, whether small entities pursue particular “niche” strategies that may influence the costs or performance in a way that makes the estimates costs and revenues i nvalid.

According to the most recent natural gas well cost data from EIA, the average cost of drilling and completing a producing natural gas wel l in 2007 was about $4.8 million (adjusted to 2008 dollars). This average includes lower cost we lls that may be relatively shallow or are not hydraulically fractured. Hydraulically fractured w ells in deep formations may cost up to $10 million. RECs contracted from a service provider a re estimated to cost $33,200 (in 2008 dollars) or roughly 0.3%-0.7% of the typical cost of a drill ing and completing a natural gas well. As this range does not include revenues expected from natur al gas and hydrocarbon condensate recovery expected to offset REC implementation costs, REC co sts likely represent a small increment of the overall burden of a drilling project.

To implement an REC, a service provider, which may itself be a small entity, is typically contracted to bring a set of equipment to the well pad temporarily to capture the stream that would otherwise be vented to the atmosphere. Typic ally, service providers are engaged in a long term drilling program in a particular basin coverin g multiple wells on multiple well pads. For gas captured and sold to the gathering system, Leas e Automatic Custody Transfer (LACT) meters are normally read daily automatically, and s ales transactions are typically settled at the end of the month. Invoices from service providers are generally delivered in 30-day increments during the well development time period, as well as at the end of the working contract for that well pad. The conclusion from the information, bas ed on the available information, in most cases, the owner/operator incurs the REC cost withi n the same 30 day period that the owner/operator receives revenue as a result of the REC.7-49

We assume small firms are performing RECs in CO and WY, as in many instances RECs are required under state regulation. In addition t o State regulations, some companies are implementing RECs voluntarily such as through parti cipation in the EPA Natural Gas STAR Program and the focus of recent press reports.

As described in more detail below, many small indep endent E&P companies often do not conduct any of the actual field work. These firms will typically contract the drilling, completion, testing, well design, environmental assessment, and maintenance. Therefore, we believe it is likely that small independent E&P firms will contra ct for RECs from service providers if required to perform RECs. An important reminder is that performing a REC is a straightforward and inexpensive extension of drilling, completion, and testing activities.

To the extent that very small firms may specialize in operating relatively few lowproducing stripper wells, it is important to ask wh ether low-producing wells are likely candidates for re-fracturing/re-completion and, if so, whether the expected costs and revenues would be valid. These marginal gas wells are likely to be o lder and in conventional formations, and as such are unlikely to be good candidates for re-frac turing/completion. To the extent the marginal wells may be good candidates for re-fracturing/comp letion, 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 cont racted out to specialty service providers who charge daily rates for the REC equipment and worker s. The cost is not related to any well
characteristic.

Large operators may receive a discount for offering larger contracts which help a service provider guarantee that REC equipment will be utili zed. However, we should note that the existence of a potential discount for larger contra cts is based on a strong assumption; we do not have evidence to support this assumption. Since co ntracting REC equipment is analogous to contracting for drilling equipment, completion equi pment, etc., the premium would likely be in the same range as other equipment contracted by sma ll operators. Since the REC cost is a small portion of the overall well drilling and completion cost, the effect of any bulk discount disparity between large and small operators will be small, if in fact it does exist.7-50

Although small operators may own the majority of ma rginal and stripper wells, they will make decisions based on economics just as any sized company would. For developing a new well, any sized company will expect a return on the ir investment meaning the potential for sufficient gas, condensate, and/or oil production t o pay back their investment and generate a return that exceeds alternative investment opportun ities. Therefore, small or large operators that are performing hydraulic fracture completions will experience the same distribution of REC performance. For refracturing an existing well, th e well must be a good candidate to respond to the re-fracture/completion with a production increa se that merits the investment in the refracture/completion.

Plugging and abandoning wells is complex and costly , so sustaining the productivity of wells is important for maximizing the exploitation of proven domestic resources. However, many marginal gas wells are likely to be older and in conventional formations, and as such are unlikely to be good candidates for re-fracturing/co mpletion, which means they are likely unaffected by the proposed NSPS.

3.5.3.3.2 Age of Equipment and Proposed Regulation s
Given a large fraction of domestic oil and natural gas production is produced from older and generally low productivity wells, it is importa nt to examine whether the proposed requirements might present impediments to owners an d operators of older equipment. The NSPS is a standard that applies to new or modified sourc es. Because of this, NSPS requirements target new or modified affected facilities or equipment, s uch as processing plants and compressors. While the requirements may apply to modifications o f 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 cos t estimates, the non-completion NSPS requirements (related to equipment leaks at pr ocessing plants, reciprocating and centrifugal compressors, pneumatic controllers, and storage vessels) are estimated to require $27 million in annualized engineering costs. EPA also estimates that the annualized costs of these requirements will be mostly if not fully offset by revenues expected from natural gas recovery. EPA does not expect these requirements to dispropor tionately affect producers with older7-51

equipment. Meanwhile, the REC and emissions combus tion requirements in the proposed NSPS relate to well completion activities at new hydraul ically fractured natural gas wells and existing wells which are recompleted after being fractured o r re-fractured. These requirements constitute the bulk of the expected engineering compliance exp enditures (about $710 million in annualized costs) and expected revenues from natural gas produ ct recovery (about $760 million in revenues, annually).

While age of the well and equipment may be an impor tant factor for small and large producers in determining whether it is economical t o fracture or re-fracture an existing well, this equipment is unlikely to be subject to the NSPS. T o comply with completion-related requirements, producers are likely to rely heavily on portable and temporary completion equipment brought to the wellpad over a short perio d of time (a few days to a few weeks) to capture and combust emissions that are otherwise ve nted. 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 th e NSPS requirement.

7.4.3.4 Small Entity Impact Analysis, Proposed NSPS, Screen ing Analysis Conclusion
The number of significantly impacted small business es is unlikely to be sufficiently large to declare a SISNOSE. Our judgment in this determ ination is informed by the fact that many affected firms are expected to receive revenues fro m the additional natural gas and condensate recovery engendered by the implementation of the co ntrols evaluated in this RIA. As much of the additional natural gas recovery is estimated to arise from completion-related activities, we expect the impact on well-related compliance costs to be significantly mitigated. This conclusion
is enhanced because the returns to reduced emission s completion activities occur without a significant time lag between implementing the contr ol and obtaining the recovered product unlike many control options where the emissions red uctions accumulate over long periods of time; the reduced emission completions and recomple tions occur over a short span of time, during which the additional product recovery is als o accomplished.7-52

7.4.4 Small Entity Economic Impact Analysis, Proposed NES HAP Amendments
The proposed NESHAP amendments will affect faciliti es operating three types of equipment: glycol dehydrators at production facilit ies, glycol dehydrators at transmission and compression facilities, and storage vessels. We id entified likely affected facilities in the National Emissions Inventory (NEI) and estimated th e number of newly required controls of each type that would be required by the NESHAP amen dments for each facility. We then used available data sources to best identify the ultimat e owner of the equipment that would likely require new controls and linked facility-level comp liance cost estimates to firm-level employment and revenue data. These data were then used to calculate an estimated compliance costs to revenues ratio to identify small businesse s that might be significantly impacted by the
NESHAP.

While we were able to identify the owners all but 1 4 facilities likely to be affected, we could not obtain employment and revenue levels for all of these firms. Overall, we expect about 447 facilities to be affected, and these facilities are owned by an estimated 160 firms. We were unable to obtain financial information on 42 (26 pe rcent) of these firms due to inadequate data. In some instances, firms are private, and financial data is not available. In other instance, firms may no longer exist, since NEI data are not updated continuously. From the ownership information and compliance cost estimates from the engineering analysis, we estimated total compliance cost per firm.

Of the 118 firms for which we have financial inform ation, we identified 62 small firms and 56 large firms that would be affected by the NE SHAP amendments. Annual compliance costs for small firms are estimated at $3.0 million (18 percent of the total compliance costs), and annual compliance costs for large firms are estimat ed at $10.7 million (67 percent of the total compliance costs). The facilities for which we wer e unable to identify the ultimate owners, employment, and revenue levels would have an estima ted annual compliance cost of $2.3 million (15 percent of the total). All figures are in 2008 dollars.

The average estimated annualized compliance cost fo r the 62 small firms identified in the dataset is $48,000, while the mean annual revenue f igure for the same firms is over $120 million, or less than 1 percent for a average sales-test rat io for all 62 firms (Table 7-26). The median7-53

sale-test ratio for these firms is smaller at 0.14 percent. Large firms are likely to see an average of $190,000 in annual compliance costs, whereas ave rage revenue for these firms exceeds $30 billion since this set of firms includes many of th e very large, integrated energy firms. For large firms, the average sales-test ratio is about 0.01 p ercent, and the median sales-test ratio is less than 0.01 percent (Table 7-26).

Table 7-26 Summary of Sales Test Ratios for Firms A ffected by Proposed NESHAP Amendments

Firm Size No. of Known

Affected Firms % of Total Known

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

C/S Ratio Small 62 53% 0.62% 0.14% < 0.01% 6.2% Large 56 47% 0.01% < 0.01% < 0.01% 0.4% All 118 100% 0.34% 0.02% < 0.01% 6.2%

Among the small firms, 52 of the 62 (84 percent) ar e likely to have impacts of less than 1 percent in terms of the ratio of annualized complia nce costs to revenues. Meanwhile 10 firms (16 percent) are likely to have impacts greater tha n 1 percent (Table 7-27). Four of these 10 firms are likely to have impacts greater than 3 per cent (Table 7-27) While these 10 firms might receive significant impacts from the proposed NESHA P amendments, they represent a very small slice of the oil and gas industry in its enti rety, less than 0.2 percent of the estimated 6,427 small firms in NAICS 211 (Table 7-27).

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

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

Affected Nationwide Affected Firms

as a % of National Firms (6,427) C/S Ratio less than 1% 52 83.9% 0.81% C/S Ratio 1-3% 6 9.7% 0.09% CS Ratio greater than 3% 4 6.5% 0.06%

Screening Analysis Conclusion: While there are significant impacts on small busin ess, the analysis shows that a substantial number of small f irms are not impacted. Based upon the analysis in this section, we presume there is no SI SNOSE arising from the proposed NESHAP amendments.7-54

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