# Regulatory Impact Analysis of the Proposed Emission Standards for New and Modified Sources in the Oil and Natural Gas Sectorii [This page intentionally left blank]iii EPA-452/R-15-002, August 2015



### Regulatory Impact Analysis of the Proposed Emission Standards for New and

Modified Sources in the Oil and Natural Gas Sector

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

This document has been prepared by staff from the O ffice of Air and Radiation, U.S. Environmental Protection Agency. Questions related to this document should be addressed to Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air and Radiation, Research Triangle Park, North Carolina 27711 (email : macpherson.alex@epa.gov ).

ACKNOWLEDGEMENTS

In addition to U.S. EPA staff from the Office of Ai r and Radiation, personnel from the U.S. EPA Office of Policy, EC/R Incorporated, and ICF Intern ational contributed data and analysis to this document.v TABLE OF CONTENTS

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

.................................................. ................................................... ......................................... 1-1 1.2 M ARKET F AILURE

.................................................. ................................................... ................................... 1-3 1.3 R EGULATORY O PTIONS A NALYZED IN THIS RIA ............................................... ........................................... 1-3 1.4 S UMMARY OF R ESULTS

.................................................. ................................................... ........................... 1-5 1.5 O RGANIZATION OF THIS R EPORT

.................................................. ................................................... ........... 1-10 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 .......................................

................................................... .............................................. 2-3 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 ..............................

................................................... ................................... 2-20 2.4.4 International Trade ...............................

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

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

.................................................. ................................................... .................................. 2-30 2.5.1 Finding Costs .....................................

................................................... ........................................... 2-30 2.5.2 Lifting Costs .....................................

................................................... ............................................ 2-32 2.5.3 Operating and Equipment Costs .....................

................................................... .............................. 2-33 2.6 F IRM C HARACTERISTICS

.................................................. ................................................... ....................... 2-35 2.6.1 Ownership .........................................

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

................................................... ....................... 2-36 2.6.3 Trends in National Employment and Wages ...........

................................................... ..................... 2-37 2.6.4 Horizontal and Vertical Integration ...............

................................................... ............................... 2-39 2.6.5 Firm-level Information ............................

................................................... ..................................... 2-41 2.6.6 Financial Performance and Condition................

................................................... ........................... 2-45 2.7 R EFERENCES

.................................................. ................................................... ......................................... 2-49 3 E MISSIONS AND E NGINEERING C OSTS .................................................. .............................. 3-1
3.1 I NTRODUCTION

.................................................. ................................................... ....................................... 3-1 3.2 S ECTOR E MISSIONS O VERVIEW

.................................................. ................................................... ............... 3-1 3.3 E MISSIONS P OINTS AND P OLLUTION C ONTROLS ASSESSED IN THE RIA ............................................... ........ 3-2 3.4 E NGINEERING C OST A NALYSIS

.................................................. ................................................... ............... 3-5 3.4.1 Regulatory Options ................................

................................................... ......................................... 3-5vi

3.4.2 Projection of Incrementally Affected Facilities ...

................................................... ........................... 3-8 3.4.3 Emissions Reductions ..............................

................................................... ..................................... 3-11 3.4.4 Product Recovery ..................................

................................................... ........................................ 3-12 3.4.5 Engineering Compliance Costs ......................

................................................... ............................... 3-13 3.4.6 Cost-Effectiveness ................................

................................................... ........................................ 3-14 3.4.7 Comparison of Regulatory Alternatives .............

................................................... .......................... 3-18 3.4.8 Capital and Annualized Compliance Costs Compared to Industry-level Capital Expenditures and Revenues ..........................................

................................................... ................................................... ........ 3-20 3.5 C OMPLIANCE C OSTS E STIMATED USING 3 AND 7 P ERCENT D ISCOUNT R ATES ........................................... 3-24 3.6 D ETAILED I MPACTS T ABLES

.................................................. ................................................... ................. 3-24 4 B ENEFITS OF E MISSIONS R EDUCTIONS .................................................. ............................. 4-1
4.1 I NTRODUCTION

.................................................. ................................................... ....................................... 4-1 4.2 E MISSION R EDUCTIONS FROM THE P ROPOSED NSPS .............................................. ..................................... 4-4 4.3 M ETHANE

.................................................. ................................................... ............................................... 4-5 4.3.1 Methane climate effects and valuation .............

................................................... ............................... 4-5 4.4 VOC AS A PM 2.5 PRECURSOR

.................................................. ................................................... ................. 4-17 4.4.1 PM 2.5 health effects and valuation ......................

................................................... ........................... 4-18 4.4.2 Organic PM welfare effects ........................

................................................... .................................. 4-22 4.4.3 Visibility Effects ................................

................................................... ........................................... 4-23 4.5 VOC AS AN O ZONE P RECURSOR

.................................................. ................................................... ........... 4-23 4.5.1 Ozone health effects and valuation ................

................................................... ............................... 4-24 4.5.2 Ozone vegetation effects ..........................

................................................... ..................................... 4-25 4.5.3 Ozone climate effects .............................

................................................... ....................................... 4-25 4.6 H AZARDOUS A IR P OLLUTANT (HAP) B ENEFITS

.................................................. ...................................... 4-26 4.6.1 Benzene ...........................................

................................................... ............................................. 4-31 4.6.2 Toluene ...........................................

................................................... .............................................. 4-32 4.6.3 Carbonyl sulfide ..................................

................................................... .......................................... 4-33 4.6.4 Ethylbenzene.......................................

................................................... .......................................... 4-34 4.6.5 Mixed xylenes .....................................

................................................... .......................................... 4-35 4.6.6 n-Hexane ..........................................

................................................... ............................................. 4-35 4.6.7 Other Air Toxics ..................................

................................................... ......................................... 4-36 4.7 S ECONDARY A IR E MISSIONS I MPACTS

.................................................. ................................................... .. 4-36 4.8 R EFERENCES

.................................................. ................................................... ......................................... 4-39 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

.................................................. ................................................... ................ 5-1 5.3 R EGULATORY F LEXIBILITY A CT (RFA) .............................................

................................................... ....... 5-2 5.4 U NFUNDED M ANDATES R EFORM A CT

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

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

.................................................. ................................................... ................................................... ............. 5-6 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 (NTTAA) AND 1 C.F.R. PART 51 .............. 5-8 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 -9 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

.................................................. ................................................... ....................................... 7-1vii

7.2 E NERGY S YSTEM I MPACTS A NALYSIS

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

................................................... ......................... 7-3 7.2.2.1 Compliance Costs for Oil and Gas Exploration and Pr oduction .......................................... .... 7-4 7.2.2.2 Adding Averted Methane Emissions into Natural Gas P roduction ......................................... . 7-6 7.2.3 Energy System Impacts .............................

................................................... ..................................... 7-7 7.3 I NITIAL R EGULATORY F LEXIBILITY A NALYSIS

.................................................. ........................................ 7-10 7.3.1 Reasons why Action is Being Considered ............

................................................... ........................ 7-11 7.3.2 Statement of Objectives and Legal Basis for Propose d Rules ........................................... .............. 7-11 7.3.3 Description and Estimate of Affected Small Entities

.................................................. .................... 7-13 7.3.4 Compliance Cost Impact Estimates ..................

................................................... ............................ 7-17 7.3.4.1 Methodology for Estimating Impacts on Small Entitie s.................................................. ....... 7-17 7.3.4.2 Results ...........................................

................................................... ...................................... 7-19 7.3.5 Caveats and Limitations ...........................

................................................... ..................................... 7-21 7.3.6 Projected Reporting, Recordkeeping and Other Compli ance Requirements ................................. .. 7-21 7.3.7 Related Federal Rules .............................

................................................... ...................................... 7-22 7.3.8 Regulatory Flexibility Alternatives ...............

................................................... ................................ 7-23 7.3.8.1 Oil Well Exemptions ...............................

................................................... ............................ 7-23 7.3.8.2 Fugitives - Leak Detection Methods ................

................................................... ................... 7-28 7.3.8.3 Fugitives – Survey Frequency ......................

................................................... ....................... 7-29 7.3.8.4 Fugitive Emissions at Well Sites ..................

................................................... ....................... 7-30 7.3.8.5 Fugitive Emissions at Production and Processing Sit es, and Compressor Stations at Transmission and Storage Sites ....................

................................................... .......................................... 7-30 7.3.8.6 Well Site Compressors .............................

................................................... ........................... 7-31 7.3.8.7 Pneumatic Pumps ...................................

................................................... ............................. 7-31 7.3.8.8 Reciprocating Compressors .........................

................................................... ........................ 7-31 7.3.8.9 Centrifugal Compressors ...........................

................................................... .......................... 7-32 7.3.8.10 Pneumatic Controllers .............................

................................................... ............................ 7-32 7.3.8.11 Recordkeeping and Reporting for High Bleed Controll ers ............................................... ..... 7-33 7.3.8.12 Liquids Unloading .................................

................................................... .............................. 7-33 7.4 E MPLOYMENT I MPACT A NALYSIS

.................................................. ................................................... ......... 7-33 7.4.1 Employment Impacts of Environmental Regulation ....

................................................... ................. 7-34 7.4.2 Labor Estimates Associated with Proposed Requiremen ts ................................................ .............. 7-38 7.5 R EFERENCES

.................................................. ................................................... ......................................... 7-46viii LIST OF TABLES

Table 1-1 Emissions Sources and Controls Evaluated at Proposa l for the NSPS .................................... .......... 1-4 Table 1-2 Summary of the Monetized Benefits, Costs, and Net B enefits for Option 1 in 2020 and 2025 (2012$) .

................................................. ................................................... ................................................... .... 1-8 Table 1-3 Summary of the Monetized Benefits, Costs, and Net B enefits for Option 2 (Proposed Option) in 2020 and 2025 (2012$) ..................................

................................................... ................................................... ............... 1-9 Table 1-4 Summary of the Monetized Benefits, Costs, and Net B enefits for Option 3 in 2020 and 2025 (2012$) .

................................................. ................................................... ................................................... .. 1-10 Table 2-1 Technically Recoverable Crude Oil and Natural Gas R esource ........................................... ........... 2-10 Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Produ ction, Proved Reserves, and Proved Ultimate Recovery, 1977-2013 ...............................

................................................... ................................................... .......... 2-11 Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by St ate, 2013 ......................................... ........... 2-13 Table 2-4 Crude Oil Domestic Production, Wells, Well Producti vity, and.......................................... ............ 2-14 Table 2-5 Natural Gas Production and Well Productivity, 1990- 2013 .............................................. .............. 2-15 Table 2-6 Crude Oil and Natural Gas Exploratory and Developme nt Wells and Average Depth, 1990-2010 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, 2010-201 3 ................................................. ................. 2-20 Table 2-9 Crude Oil Consumption by Sector, 1990-2012 ........

................................................... ..................... 2-20 Table 2-10 Natural Gas Consumption by Sector, 1990-2012 ......

................................................... ................... 2-23 Table 2-11 Total Crude Oil and Petroleum Products Trade (Milli on Bbl), .......................................... .............. 2-25 Table 2-12 Natural Gas Imports and Exports, 1990-2013.........

................................................... ...................... 2-26 Table 2-13 Forecast of Total Successful Wells Drilled, Lower 4 8 States, 2010-2040 ............................... ........ 2-27 Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhea d Prices, 2011-2040 ............................... ..... 2-28 Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price ................................ ..... 2-30 Table 2-16 SBA Size Standards and Size Distribution of Oil and Natural Gas Firms ................................ ....... 2-37 Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1 990-2013 .......................................... ....... 2-38 Table 2-18 Oil and Natural Gas Industry Average Wages by NAICS , 1990-2013 (2012 dollars) .................... 2-3 9 Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Tota l Assets), 2012 ................................... ...... 2-43 Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throu ghput), 2009 ...................................... ....... 2-44 Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2012 ............................ 2-45 Table 2-22 Selected Financial Items from Income Statements (Bi llion 2008 Dollars) ............................... ....... 2-47 Table 2-23 Return on Investment for Lines of Business (all FRS ), for 1998, 2003, 2008, and 2009 (percent) . 2-48 Table 2-24 Income and Production Taxes, 1990-2009 (Million 200 8 Dollars) ........................................ ......... 2-49 Table 3-1 Emissions Sources and Controls Evaluated at Proposa l for the NSPS .................................... .......... 3-7 Table 3-2 Number of Incrementally Affected Sources for the NS PS ................................................ .............. 3-10 Table 3-3 Emissions Reductions for Proposed NSPS Option 2, 20 20 and 2025........................................ ...... 3-11 Table 3-4 Estimated Natural Gas Recovery (Mcf) for Proposed N SPS Option 2 in 2020 and 2025 ............... 3-13 Table 3-5 Engineering Compliance Cost Estimates for Proposed NSPS Option 2 in 2020 and 2025 (millions 2012$) ...........................................

................................................... ................................................... ........ 3-14 Table 3-6 Single Pollutant Approach to Engineering Compliance Cost-Effectiveness Estimates in 2020 and 2025 for Proposed NSPS Option 2 (High Impact Case f or Well Site Fugitive Emissions Requirements) ..... ......... 3-17 Table 3-7 Multipollutant Approach to Engineering Compliance C ost-Effectiveness Estimates for Proposed NSPS Option 2 in 2020 and 2025 (High Impact Case fo r Well Site Fugitive Emissions Requirements) ...... ......... 3-18 Table 3-8 Comparison of Regulatory Alternatives .............

................................................... .......................... 3-19 Table 3-9 NAICS-Based Capital Expenditure Data ..............

................................................... ........................ 3-20 Table 3-10 NAICS-Based Revenue Data ..........................

................................................... .............................. 3-21 Table 3-11 Comparison of Proposed NSPS Nationwide Cost by Affe cted Facility Cost to Industry-wide Capital Expenditures and Revenues .........................

................................................... ................................................... ...... 3-23 Table 3-12 Annualized Costs using 3 and 7 Percent Discount Rat es for Proposed NSPS Option 2 in 2020 and 2025 (millions 2012$) .............................

................................................... ................................................... .......... 3-24 Table 3-13 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020 ......................... .. 3-25 Table 3-14 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025 ......................... .. 3-26 Table 3-15 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact Case, 2020 .......................................

................................................... ................................................... ............ 3-27ix

Table 3-16 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact Case, 2025 .......................................

................................................... ................................................... ............ 3-28 Table 3-17 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact Case, 2020 .......................................

................................................... ................................................... ............ 3-29 Table 3-18 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact Case, 2025 .......................................

................................................... ................................................... ............ 3-30 Table 3-19 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020 ......................... .. 3-31 Table 3-20 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025 ......................... .. 3-32 Table 4-1 Climate and Human Health Effects of Emission Reduct ions from this Proposal ........................... ... 4-2 Table 4-2 Direct Emission Reductions across NSPS Regulatory O ptions in 2020 and 2025 ........................... . 4-5 Table 4-3 Social Cost of Methane (SC-CH 4 ), 2012 – 2050 a [in 2012$ per metric ton] (Source: Marten et al.
, 2014 b ) ................................................

................................................... ................................................... ... 4-14 Table 4-4 Estimated Global Benefits of Methane Reductions* (i n millions, 2012$) ................................ ....... 4-16 Table 4-5 Monetized Benefits-per-Ton Estimates for VOC based on Previous Modeling in 2015 (2012$) .... 4-21 Table 4-6 Secondary Air Pollutant Impacts (short tons per yea r) ................................................ .................... 4-37 Table 4-7 Summary of Emissions Changes (short tons per year, except where noted) ............................... ..... 4-38 Table 6-1 Summary of the Monetized Benefits, Costs, and Net B enefits for Option 1 in 2020 and 2025 (2012$) .

................................................. ................................................... ................................................... .... 6-1 Table 6-2 Summary of the Monetized Benefits, Costs, and Net B enefits for Option 2 (Proposed Option) in 2020 and 2025 (2012$) ..................................

................................................... ................................................... ............... 6-2 Table 6-3 Summary of the Monetized Benefits, Costs, and Net B enefits for Option 3 in 2020 and 2025 (2012$) .

................................................. ................................................... ................................................... .... 6-3 Table 6-4 Summary of Emissions Changes across Options for the NSPS in 2020 and 2025 (short tons per year, unless otherwise noted) ...........................

................................................... ................................................... ............ 6-4 Table 7-1 Per Well Costs for Environmental Controls Entered i nto NEMS (2012$) .................................. ...... 7-6 Table 7-2 Successful Oil and Gas Wells Drilled (Onshore, Lowe r 48 States) ...................................... ............. 7-8 Table 7-3 Annual Domestic Natural Gas and Crude Oil Productio n (Onshore, Lower 48 States) .................... 7 -8 Table 7-4 Average Natural Gas and Crude Oil Wellhead Price (O nshore, Lower 48 States, 2012$) ................ 7- 9 Table 7-5 Net Imports of Natural Gas and Crude Oil ..........

................................................... ......................... 7-10 Table 7-6 SBA Size Standards by NAICS Code ..................

................................................... ......................... 7-13 Table 7-7 Distribution of Estimated Compliance Costs across S ources ............................................ .............. 7-15 Table 7-8 No. of Completions in 2012 by Preliminary Firm Size

................................................... ................. 7-16 Table 7-9 No. of Completions in 2012 by Firm Size ...........

................................................... ......................... 7-16 Table 7-10 No. of Incrementally Affected Sources in 2020 and 2 025 by Firm Size, Low Impact Fugitive Emissions Case ....................................

................................................... ................................................... .............. 7-17 Table 7-11 No. of Incrementally Affected Sources in 2020 and 2 025 by Firm Size, High Impact Fugitive Emissions Case ....................................

................................................... ................................................... .............. 7-18 Table 7-12 Distribution of Estimated Compliance Costs 1 across Firm Size Classes ......................... ................ 7-18 Table 7-13 Compliance Costs-to-Sales 1 Ratios (Fugitive Emissions Requirements Low Impact Case) across Firm Size Classes for Primary Scenario and Low Oil Price Scenario 2

.................................................. ........................... 7-20 Table 7-14 Compliance Costs-to-Sales 1 Ratios (Fugitive Emissions Requirements Low Impact Case) across Firm Size Classes for Primary Scenario and Low Oil Price Scenario 2

.................................................. ........................... 7-20 Table 7-15 Estimates of Labor Required to Comply with Proposed NSPS for Hydraulically Fractured Oil Well Completions, 2020 and 2025 ........................

................................................... ................................................... ..... 7-41 Table 7-16 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, Low Impact Case, 2020 and 2025 ...............................

................................................... ................................................... ........... 7-42 Table 7-17 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, High Impact Case, 2020 and 2025 ...............................

................................................... ................................................... ........... 7-43 Table 7-18 Estimates of Labor Required to Comply with Proposed NSPS for Reciprocating and Centrifugal Compressors, 2020 and 2025 ........................

................................................... ................................................... ..... 7-44 Table 7-19 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic Controllers and Pumps, 2020 and 2025 ....................................

................................................... ................................................... ............... 7-45 Table 7-20 Estimates of Labor Required to Comply with Proposed NSPS, 2020 and 2025 .............................. 7-46x LIST OF FIGURES
Figure 2-1 A) Domestic Crude Oil Proved Reserves and Cumulativ e Production, 1990-2013. B) Domestic Natural Gas Proved Reserves and Cumulative Producti on, 1990-2013...................................... ............................. 2-12 Figure 2-2 A) Total Producing Crude Oil Wells and Average Well Productivity, 1990-2011. B) Total Producing Natural Gas Wells and Average Well Productivity, 19 90-2013. .......................................... ................................... 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), 1990-2011 ............................ 2-21 Figure 2-5 Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-2012 ......................... 2-24 Figure 2-6 Forecast of Domestic Crude Oil Production and Net I mports, 2010-2040 ................................. ..... 2-29 Figure 2-7 Costs of Crude Oil and Natural Gas Wells Drilled, 1 981-2008 .......................................... ............. 2-31 Figure 2-8 Finding Costs for FRS Companies, 1981-2009 ........

................................................... .................... 2-32 Figure 2-9 Direct Oil and Natural Gas Lifting Costs for FRS Co mpanies, 1981-2009 (3-year Running Average) ..

................................................. ................................................... ................................................... .. 2-33 Figure 2-10 Crude Oil Operating Costs and Equipment Costs Indic es (1976=100) and Crude Oil Price (in 1976 dollars), 1976-2009 ...............................

................................................... ................................................... ............. 2-34 Figure 2-11 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas Price, 1976-2009

................................................. ................................................... ................................................... .. 2-35 Figure 4-1 Path from GHG Emissions to Monetized Damages ......

................................................... ................ 4-10 Figure 4-2 2005 NATA Model Estimated Census Tract Carcinogenic Risk from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics I nventory........................................... ................................... 4-28 Figure 4-3 2005 NATA Model Estimated Census Tract Noncancer (R espiratory) Risk from HAP Exposure from All Outdoor Sources based on the 2005 National Toxi cs Inventory ...................................... ................................. 4-291-1 1 EXECUTIVE SUMMARY

1.1 Background

The action analyzed in this regulatory impact analy sis (RIA) proposes to amend the new source performance standards (NSPS) for the oil and natural gas source category by setting standards for both methane and volatile organic com pounds (VOC) for certain equipment, processes and activities across this source categor y.
The Environmental Protection Agency (EPA) is includ ing requirements for methane emissions in this proposal because methane is a gre enhouse gas (GHG), and the oil and natural gas category is currently one of the country's larg est emitters of methane. In 2009, the EPA found that by causing or contributing to climate ch ange, GHGs endanger both the public health and the public welfare of current and future genera tions.

The EPA is proposing to amend the NSPS to include s tandards for reducing methane as well as VOC emissions across the oil and natural ga s source category. Specifically, we are proposing both methane and VOC standards for severa l emission sources not currently covered by the NSPS (i.e., hydraulically fractured oil well completions, fugitive emissions from well sites and compressor stations, pneumatic pumps). In addit ion, we are proposing methane standards for certain emission sources that are currently regulat ed for VOC (i.e., hydraulically fractured gas well completions, equipment leaks at natural gas pr ocessing plants). However, we do not expect any incremental benefits or costs as a result from regulating methane for currently regulated
VOC sources.

With respect to certain equipment that are used acr oss the source category, the current NSPS regulates only a subset of these equipment (pn eumatic controllers, centrifugal compressors, reciprocating compressors). The propos ed amendents would establish methane standards for these equipment across the source cat egory and extend the current VOC standards to the remaining unregulated equipment. Lastly, ame ndments to the current NSPS are being proposed that improve several aspects of the curren t standards related to implementation. These improvements result from reconsideration of certain issues raised in petitions for reconsideration that were received by the Administrator on the Augu st 16, 2012, final NSPS for the oil and1-2

natural gas sector and related amendments. Except f or these implementation improvements and the setting of standards for methane, these amendme nts do not change the requirements for operations already covered by the current standards

. As part of the regulatory process, the EPA is requi red to develop a regulatory impact analysis (RIA) for rules that have costs or benefit s that exceed $100 million annually. The EPA estimates the proposed NSPS will have costs that ex ceed $100 million, so the Agency has prepared an RIA. This RIA includes an economic impa ct analysis and an analysis of the climate, health, and welfare impacts anticipated from the pr oposed NSPS. 1 We also estimate potential impacts of the proposed rule on the national energy economy using the U.S. Energy Information Administration’s National Energy Modeling System (N EMS). The engineering compliance costs are annualized using 3 and 7 percent discount rates

. This analysis estimates regulatory impacts for the analysis years of 2020 and 2025, which spans a period of six years. The analysis of 2020 i s assumed to represent the first year the full suite of proposed standards is in effect and thus r epresents a single year of potential impacts. We estimate impacts in 2025 to illustrate how new and modified sources accumulate over time under the proposed NSPS. The regulatory impact estimates for 2025 include sources newly affected in
2025 as well as the accumulation of affected source s from 2020 to 2024 that are also assumed to be in continued operation in 2025, thus incurring c ompliance costs and emissions reductions in
2025.

Several emission controls for the NSPS, such as red uced emissions completions (RECs) of hydraulically-fractured oil wells, capture metha ne and VOC emissions that otherwise would be vented to the atmosphere. The averted methane em issions can be directed into natural gas production streams and sold. The revenues derived f rom natural gas recovery are expected to offset a portion of the engineering costs of implem enting the NSPS. In this RIA, we present results that include the additional product recover y and the revenues we expect producers to gain from the additional product recovery.

1 The analysis in this draft RIA constitutes the eco nomic assessment required by CAA section 317. In th e EPA’s judgment, the assessment is as extensive as practic able taking into account the EPA’s time, resources, and other duties and authorities.1-3

The baseline used for the impacts analysis of our N SPS takes into account emissions reductions conducted pursuant to state regulations covering the relevant operations. More
detailed discussion on the derivation of the baseli ne is presented in Section 3 of this RIA.

1.2 Market Failure

Many regulations are promulgated to correct market failures, which lead to a suboptimal
allocation of resources within the free market. Air quality and pollution control regulations address “negative externalities” whereby the market does not internalize the full opportunity cost of production borne by society as public goods such as air quality are unpriced.

Greenhouse Gas (GHG) and VOC emissions impose costs on society, such as negative climate, health, and welfare impacts that are not r eflected in the market price of the goods produced through the polluting process. For this re gulatory action the goods produced, processed, transported, or stored are crude oil, na tural gas, and other hydrocarbon products. These social costs associated with the climate, hea lth, and welfare impacts are referred to as negative externalities. If an oil and natural gas f irm pollutes the atmosphere while extracting, processing, transporting, or storing the commoditie s, this cost will be borne not by the polluting firm but by society as a whole. The market price of the products will fail to incorporate the full opportunity cost to society of producing the produc ts. All else equal, given this externality, the quantity of oil and natural gas produced in a free market will not be at the socially optimal level. More oil and natural gas will be produced than woul d occur if the power producers had to account for the full opportunity cost of production including the negative externality. Consequently, absent a regulation on emissions, the marginal social cost of the last units of oil and natural gas produced will exceed its marginal s ocial benefit.

1.3 Regulatory Options Analyzed in this RIA

In this RIA, we examine three broad regulatory opti ons. 2 Table 1-1 shows the emissions

2 See Chapter 3 for a detailed discussion of the com parative impacts of the regulatory options. The EPA also analyzed a variant of proposed Option 2 where only emissions combustion is required for hydraulically fractured and re-fracture oil well completions, rather than r equire reduced emissions completions (RECs) in comb ination with combustion. This variation of the proposed Opt ion 2 would achieve direct emission reduction that are equivalent to requiring RECs and combustion, but at an approximately $70 million per year lower cost.1-4

sources, points, and controls for the three NSPS re gulatory options analyzed in this RIA, which we term Option 1, Option 2, and Option 3. Option 2 was selected for proposal. Option 1 was selected for co-proposal.

Table 1-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS

Emissions Point Emissions Control Option 1 Option 2 (proposed) Option 3
Well Completions and Recompletions Hydraulically Fractured Development Oil Wells REC / Combustion X X X

Hydraulically Fractured Wildcat and Delineation Oil Wells Combustion X X X

Fugitive Emissions Well Pads Monitoring and Maintenance Annual Semiannual Quarterly Gathering and Boosting Stations Monitoring and Maintenance Semiannual Semiannual Quarterly Transmission Compressor Stations Monitoring and Maintenance Semiannual Semiannual Quarterly Pneumatic Pumps Well Pads Route to control X X X Gathering and Boosting Stations Route to control X X X Transmission and Storage Compressor Stations Route to control X X X
Pneumatic Controllers - Natural Gas Transmission and Storage Stations Emissions limit X X X
Reciprocating Compressors Natural Gas Transmission and Storage Stations Annual Monitoring and Maintenance X X X Centrifugal Compressors Natural Gas Transmission and Storage Stations Route to control X X X

The proposed Option 2 contains reduced emission com pletion (REC) and completion combustion requirements for a subset of newly compl eted oil wells that are hydraulically fractured or refractured. Option 2 also requires fu gitive emissions survey and repair programs be

However, as explained in Section VIII.F of the prea mble to the proposed NSPS, the EPA determined RECs and combustion to be the best system of emissions reduc tion. Section 4 of the Technical Support Document f or the proposal presents the detailed technical analysis o f the regulatory options for hydraulically fracture d and refractured oil well completions.1-5

performed semiannually (twice per year) at newly dr illed or refractured oil and natural gas well sites, new or modified gathering and boosting stati ons, and new or modified transmission and storage compressor stations. However, low productio n well sites are exempt from the well site fugitive requirements. A low production site is def ined by the average combined oil and natural gas production for the wells at the site being less than 15 barrels of oil equivalent (boe) per day. 3 Option 2 also requires reductions from centrifugal compressors, reciprocating compressors, pneumatic controllers, and pneumatic pumps througho ut the oil and natural gas source category.

While the EPA is proposing an exclusion from fugiti ve emission requirements for low production well sites, there is uncertainty in how many well sites this exclusion might affect in the future. As a result, the analyses in this RIA p resents a “low” impact case and “high” impact case for fugitive emissions requirements at well si tes. The low impact case excludes from analysis an estimate low production sites, assuming that the fraction of wells meeting the low production criteria in the future will be the same as in 2012 (based on the first month of production data from wells newly completed or modif ied in 2012).The high impact case includes all forecasted well sites providing a bounding case where no newly completed or modified wells meet the low production criteria. Summary results f or option 2, then, are presented as ranges.

Options 1 and 3 differ from the Option 2 with respe ct to the requirements for fugitive emissions. Meanwhile, the co-proposed Option 1 requ ires annual monitoring for well sites, including low production sites, while maintaining s emiannual requirements for others sites. The more stringent Option 3 requires quarterly monitori ng for all sites under the fugitive emissions program, including low production sites. More frequ ent surveys result in higher costs, higher emissions reductions, and increased natural gas rec overy over the co-proposed Option 2.

1.4 Summary of Results
For the proposed NSPS, the key results of the RIA f ollow and are summarized in Table 1-2 through Table 1-4. Note all dollar estimates ar e in 2012 dollars:

• Emissions Analysis: The proposed NSPS is anticipated to prevent signif icant new emissions, including 170,000 to 180,000 tons of met hane, 120,000 tons of VOCs and 310

3 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels o f crude oil equals 1000 cubic feet natural gas.1-6

to 400 tons of hazardous air pollutants (HAP) in 20 20, increasing to 340,000 to 400,000 tons of methane, 170,000 to 180,000 tons of VOCs, a nd 1,900 to 2,500 tons of HAP prevented in 2025. 4 The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 3.8 to 4.0 million metric tons in 2020 and 7.7 to 9.0 m illion metric tons in 2025.

• Benefits Analysis: The monetized benefits in this RIA include those fr om reducing methane emissions, which are valued using the socia l cost of methane (SC-CH 4 ). 5 The EPA estimates that, in 2020, the proposal will yiel d monetized climate benefits of $88 million to approximately $550 million; the mean SC- CH 4 at the 3% discount rate results in an estimate of about $200 to $210 million in 202 0. In 2025, the EPA estimates monetized climate benefits of $220 million to appro ximately $1.4 billion; the mean SCCH 4 at the 3% discount rate results in an estimate of about $460 to $550 million in 2025. 6 While we expect that the avoided emissions will res ult in improvements in ambient air quality and reductions in health effects associated with exposure to HAP, ozone, and particulate matter (PM), we have determined that qu antification of those benefits cannot be accomplished for this rule. 7 This is not to imply that there are no health bene fits anticipated from the proposed rule; 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 h ealth improvements, there will be improvements in visibility effects, ecosystem effec ts, as well as additional natural gas recovery. The specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.

• Engineering Cost Analysis: The EPA estimates the total capital cost of the pro posed NSPS to be $170 to $180 million in 2020 and $280 to $330 million in 2025. The estimate of total annualized engineering costs of the propos ed NSPS is $180 to $200 million in 2020 and $370 to $500 million in 2025 when using a 7 percent discount rate. When estimated revenues from additional natural gas are included, the annualized engineering costs of the proposed NSPS are estimated to be $150 to $170 million in 2020 and $320 to $420 million in 2025, assuming a wellhead natural g as price of $4/thousand cubic feet (Mcf). The estimated engineering compliance costs t hat include the product recovery are sensitive to the assumption about the price of the recovered product. There is also geographic variability in wellhead prices, which ca n also influence estimated engineering costs. For example, $1/Mcf change in the wellhead p rice causes a change in estimated

4 Estimates are presented in short tons. 5 The social cost of methane (SC-CH 4 ) is the monetary value of impacts associated with a marginal change in methane emissions in a given year. 6 The range of estimates reflects four SC-CH 4 estimates are associated with different discount r ates (model average at 2.5, 3 and 5 percent; 95 th percentile at 3 percent). See Section 4.3 for a co mplete discussion.
7 Previous studies have estimated the monetized bene fits-per-ton of reducing VOC emissions associated w ith the effect that those emissions have on ambient PM 2.5 levels and the health effects associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009). While these ran ges of benefit-per-ton estimates provide useful con text, the geographic distribution of VOC emissions from the o il 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 redu ctions in that study are derived from total VOC emissions acr oss all sectors. Coupled with the larger uncertaint ies about the relationship between VOC emissions and PM 2.5 and the highly localized nature of air quality res ponses associated with VOC reductions, these factors lead us to conclude that the available VOC benefit-per-t on estimates are not appropriate to calculate monetize d benefits of these rules, even as a bounding exerc ise.1-7

engineering compliance costs of about $8 million in 2020 and $16 to $19 million in 2025, given the EPA estimates that about 8 million Mcf in 2020 and 16 to 19 million Mcf of natural gas will be recovered by implementing the N SPS. When using a 3 percent discount rate, the estimate of total annualized eng ineering costs of the proposed NSPS is $200 million in 2020 and $490 million in 2025, or $ 150 to $170 million in 2020 and $310 to $420 million in 2025, when estimated revenues fr om additional natural gas are included. 8

• Energy System Impacts Analysis: The EPA used the National Energy Modeling System (NEMS) to estimate the impacts of the proposed rule on the United States energy system. 9 We estimate that natural gas and crude oil product ion levels remains essentially unchanged in 2020, while slight declines are estima ted for 2025 for both natural gas (about 4 billion cubic feet (bcf) or about 0.01 per cent) and crude oil production (about 2,000 barrels per day or 0.03 percent). Wellhead na tural gas prices for onshore lower 48 production are not estimated to change in 2020, but are estimated to increase about $0.007 per Mcf or 0.14 percent in 2025. Meanwhile, well crude oil prices for onshore lower 48 production are not estimated to change, de spite the incidence of new compliance costs from the proposed NSPS. Meanwhile, net imports of natural gas are estimated to decline slightly in 2020 (by about 1 b cf or 0.05 percent) and in 2025 (by about 3 bcf or 0.09 percent). Crude oil imports are estimated to not change in 2020 and increase by about 1,000 barrels per day (or 0.02 pe rcent) in 2025.

• Small Entity Analyses: To understand the potential impact of the proposed rule of small entities the EPA conducted a screening analysis of the potential impacts by estimating the ratio of potential compliance costs to firm sales ( i.e. a cost-to-sales test). Based on the results of this screening analysis, the EPA conclud ed it is not able to certify that the proposed rule will not have a Significant Impact on a Substantial Number of Small Entities (SISNOSE). As a result, the EPA initiated a Small Business Advisory Review panel and completed an Initial Regulatory Flexibili ty Analysis.

• Employment Impacts Analysis: The EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipment and control activities, as well as the labor associated with new reporting and recordkeeping requirements. We estimated one-time and continual, annual labor requ irements 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 one-time labor requirement to comply with the proposed NSPS is est imated at about 50 to 70 FTEs in 2020 and in 2025. The annual labor requirement to c omply with proposed NSPS is estimated at about 470 to 530 FTEs in 2020 and 1,10 0 to 1,400 FTEs in 2025. We note that this type of FTE estimate cannot be used to id entify the specific number of people

8 The choice of discount rate has a small effect on nationwide annualized costs. The compliance costs r elated to oil well completions and fugitive emissions surveys occ ur in each year, so the interest rate has little im pact on annualized costs for these sources. The annualized costs for pneumatic pumps, compressors, and pneumat ic controllers are sensitive to interest rate, but the se constitute a relatively small part of the total compliance cost estimates for the proposal. 9 The EPA only modeled the high impact case of the p roposed NSPS with respect the low production exempt ion from the well site fugitive emissions requirements. As such the NEMS-based estimates of energy system impacts are likely high end estimates.1-8

involved or whether new jobs are created for new em ployees, versus displacing jobs from other sectors of the economy.
Table 1-2 presents the summary results for co-propo sed Option 1, Table 1-3 presents summary results for the co-proposed Option 2, and T able 1-4 presents summary results for Option 3. The summary results for Option 2 reflects the range from the low impacts to high impacts case with respect the well site fugitive em issions requirements.

Table 1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 2020 and 2025 (2012$)
2020 2025
Total Monetized Benefits 1 $200 million $470 million
Total Costs 2 $150 million $310 million
Net Benefits 3 $43 million $160 million

Non-monetized Benefits Non-monetized climate benefits Non-monetized climat e benefits
Health effects of PM 2.5 and ozone exposure from 120,000 tons of VOC

reduced Health effects of PM 2.5 and ozone exposure from 170,000 tons of VOC

reduced Health effects of HAP exposure from 310 tons of HAP reduced Health effects of HAP exposure from 1,900 tons of HAP reduced Health effects of ozone exposure from 170,000 tons of methane Health effects of ozone exposure from 340,000 tons of methane Visibility impairment Visibility impairment Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four di fferent estimates of the social cost of methane (SC -CH 4 ) (model average at 2.5 percent discount rate, 3 perc ent, and 5 percent; 95 th percentile at 3 percent). For purposes of this table, we show the benefits associated with th e model average a 3 percent discount rate. However, we emphasize the importance and value of considering t he benefits calculated using all four SC-CH 4 estimates; the additional benefit estimates range from $89 million to $530 million in 2020 and $220 million to $1,200 million in 2025 for the proposed option, as shown in Section 4 .3. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4. 7 for details.
2 The engineering compliance costs are annualized usi ng a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 p ercent discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate. 3 Estimates may not sum due to independent rounding.1-9

Table 1-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 (Proposed Option) in 2020 and 2025 (2012$)
2020 2025
Total Monetized Benefits 1 $200 to $210 million $460 to $550 million
Total Costs 2 $150 to $170 million $320 to $420 million Net Benefits 3 $35 to $42 million $120 to $150 million

Non-monetized Benefits Non-monetized climate benefits
Health effects of PM 2.5 and ozone exposure from 120,000 tons of VOC

reduced Non-monetized climate benefits
Health effects of PM 2.5 and ozone exposure from 170,000 to 180,000 tons of VOC reduced Health effects of HAP exposure from 310 to 400 tons of HAP reduced Health effects of ozone exposure from 170,000 to 180,000 tons of methane Health effects of HAP exposure from 1,900 to 2,500 tons of HAP reduced Health effects of ozone exposure from 340,000 to 400,000 tons of methane Visibility impairment Visibility impairment Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four di fferent estimates of the social cost of methane (SC -CH 4 ) (model average at 2.5 percent discount rate, 3 perc ent, and 5 percent; 95 th percentile at 3 percent). For purposes of this table, we show the benefits associated with th e model average a 3 percent discount rate. However, we emphasize the importance and value of considering t he benefits calculated using all four SC-CH 4 estimates; the additional benefit estimates range from $88 million to $550 million in 2020 and $250 million to $1,400 million in 2025 for the proposed option, as shown in Section 4 .3. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 3.8 to 4.0 million metric tons in 20 20 and 7.7 to 9.0 million metric tons in 2025. Also , the specific control technologies for the proposed NSPS are anti cipated to have minor secondary disbenefits. See Se ction 4.7 for details. 2 The engineering compliance costs are annualized usi ng a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 p ercent discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate. 3 Estimates may not sum due to independent rounding.1-10

Table 1-4 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in 2020 and 2025 (2012$)
2020 2025 Total Monetized Benefits 1 $220 million $640 million Total Costs 2 $210 million $680 million Net Benefits 3 $7.6 million -$35 million

Non-monetized Benefits Non-monetized climate benefits Non-monetized climat e benefits Health effects of PM 2.5 and ozone exposure from 130,000 tons of VOC

reduced Health effects of PM 2.5 and ozone exposure from 200,000 tons of VOC

reduced Health effects of HAP exposure from 510 tons of HAP reduced Health effects of HAP exposure from 3,200 tons of HAP reduced Health effects of ozone exposure from 190,000 tons of methane Health effects of ozone exposure from 470,000 tons of methane Visibility impairment Visibility impairment Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four di fferent estimates of the social cost of methane (SC -CH 4 ) (model average at 2.5 percent discount rate, 3 perc ent, and 5 percent; 95th percentile at 3 percent). For purposes of this table, we show the benefits associated with the model average at a 3 percent discount rate. Ho wever we emphasize the importance and value of considering t he benefits calculated using all four SC-CH 4 estimates; the additional benefit estimates range from $99 million to $590 million in 2020 and $300 million to $1,700 million in 2025 for this more stringent option, as shown in Se ction 4.3. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 4.2 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.
2 The engineering compliance costs are annualized usi ng a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 p ercent discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate. 3 Estimates may not sum due to independent rounding.

1.5 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 natura l gas industry. Section 3 describes the emissions and engineering cost analysis. Section 4 presents t he benefits analysis. Section 5 presents statutory and executive order analyses. Section 6 p resents a comparison of benefits and costs. Section 7 presents energy system impact, employment impact, and small entity 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 require controls for the oil and natural gas produc ts and processes of the drilling and extraction of crude oil and natural gas, natural gas processin g, 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 wells 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 (2 21210—Natural Gas Distribution, 486110—Pipeline Transportation of Crude Oil, and 54 1360—Geophysical Surveying and Mapping Services) are often included in the oil and natural gas sector, these are not discussed in detail in the Industry Profile because they are not directly affected by the proposed NSPS.

The outputs of the oil and natural gas industry are inputs for larger production processes of gas, energy, and petroleum products. As of 2013, the Energy Information Administration (EIA) estimates that about 490,000 producing natura l gas wells operated in the U.S. The latest
available information from EIA indicates there were about 360,000 producing oil wells in the U.S. as of 2009. Domestic dry natural gas productio n was 24.3 trillion cubic feet (tcf) in 2013, the highest annual production level in U.S. history . The leading five natural gas producing states are Texas, Pennsylvania, Louisiana, Oklahoma, and W yoming. Domestic crude oil production in 2013 was 2,716 million barrels (bbl), the highest a nnual level in the U.S. since 1991. The leading five crude oil producing states are Texas, North Da kota, California, Alaska, and Oklahoma.

The Industry Profile provides a brief introduction to the components of the oil and natural gas industry that are relevant to the proposed NSPS . The purpose is to give the reader a general understanding of the geophysical, engineering, and economic aspects of the industry that are addressed in subsequent economic analysis in this R IA. The Industry Profile relies heavily on background material from the EPA’s “Economic Analys is of Air Pollution Regulations: Oil and
Natural Gas Production” (1996), the EPA’s “Sector Notebook Project: Profile of the Oil and Gas2-2

Extraction Industry” (2000), and the EPA’s “Regulat ory Impact Analysis: Final New Source
Performance Standards and Amendments to the Nationa l Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry” (2 012).

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 used 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 generall y 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 may be referred to as live crudes. Live crudes contain entrained or dissolved gases which m ay be released during processing or storage. Dead crudes are those that have gone through variou s separation and storage phases and contain little, if any, entrained or dissolved gases.2-3

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 natural underground reservoirs. Natural gas may contain con taminants, 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. So ur gas contains a H 2 S concentration of greater than 0.25 grain per 100 standard cubic feet , along with the presence of CO 2
. Concentrations of H 2 S and CO 2 , along with organic sulfur compounds, vary widely among sour gases. A majority of total onshore natural gas prod uction and nearly all 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 hydr ocarbon 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 mix ed 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 t he well bore gets deeper sections of drill pipe are added. A mix of fluids called drilling mud is relea sed 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 ce mented 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, 2013). Hydraulic fracturing involves pum ping 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 r eservoir. Where oil and gas are associated, a gas cap forms above the oil. Natural gas is extract ed from a well either because it is associated with oil in an oil well or from a pure natural gas reservoir. Once a well has been drilled to reach the reservoir, the oil and gas can be extracted in different ways depending on the well pressure (Hyne, 2001).

Frequently, oil and natural gas are produced from 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 occurs 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 and 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. Typical ly, about 30 to 35 percent of the resource in the reservoir is extracted this way (Hyne, 2001). T he 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 13). Therefore, the resource does not move
into a reservoir as in the case with a conventional source. Mining, induced pressure, or heat is required to release the resource. The specific type of extraction method needed depends on the type of formation where the resource is located. Un conventional oil and natural gas resource types relevant for this rule include:

• Shale Oil and Natural Gas: Shale natural gas comes from sediments of clay mix ed with organic matter. These sediments form low permeabili ty shale rock formations that do not allow the gas to move. To release the gas, the rock must be fragmented, making the extraction process more complex than it is for conv entional gas extraction. Shale gas can be extracted by drilling either vertically or horiz ontally, and breaking the rock using hydraulic fracturing (U.S. DOE, 2013).

• Tight Sands Natural Gas: Reservoirs are composed of low-porosity sandstones and carbonate into which natural gas has migrated from other sources. Extraction of the natural gas from tight gas reservoirs is often perf ormed using horizontal wells. Hydraulic fracturing is often used in tight sands (U.S. DOE, 2013).

• Coalbed Methane: Natural gas is present in a coal bed due to the ac tivity 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 fr om 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 hi gh 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 vapo r 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. Thre e 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 rege nerated simply by heating them above the boiling point of water. Finally, particularly for g as extracted from deep, hot wells, simply cooling the gas to a temperature below the condensation poi nt of water can remove enough water to transport the gas. Of the three approaches mentione d 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 stations 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 as prim e movers to provide the necessary horsepower to maintain system pressure. Underground 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 l ocated 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 dry natural gas prove d reserves, unproved reserves, and total technically recoverable resources as of 2009. According to EIA 10 , 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.

• Unproved resources: additional volumes estimated to be technically reco verable without consideration of economics or operating con ditions, based on the application of current technology.

• Total technically recoverable resources: resources that are producible using current technology without reference to the economic viabil ity of production.

According to EIA, dry natural gas is consumer-grade natural gas. The dry natural gas volumes reported in Table 2-1 reflect the amount of gas rem aining after liquefiable portion has been removed from the natural gas, as well as any non-hy drocarbon gases that render the natural gas unmarketable have been removed. The sum of proved r eserves and unproved reserves equal the total technically recoverable resources. As seen in Table 2-1, as of 2009, proved domestic crude oil reserves accounted for about 10 percent of the totally technically recoverable crude oil

resources.

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

Table 2-1 Technically Recoverable Crude Oil and Nat ural Gas Resource Estimates, 2009

Region Proved Reserves Unproved Resources Total Technically

Recoverable Resources Crude Oil and Lease Condensate (billion barrels) 48 States Onshore 14.2 112.6 126.7 48 States Offshore 4.6 50.3 54.8 Alaska 3.6 35.0 38.6 Total U.S. 22.3 197.9 220.2

Dry Natural Gas (trillion cubic feet) Conventionally Reservoired Fields 105.5 904.0 1, 009.5 48 States Onshore 1 81.4 369.7 451.1 48 States Offshore 15.0 262.6 277.6 Alaska 9.1 271.7 280.8
Tight Gas, Shale Gas and Coalbed Methane 167.1 1,02 6.7 1,193.8 Total U.S. 272.5 1,930.7 2,203.3

Source: U.S. Energy Information Administration, Annual Energy Review 2012. Totals may not sum due to independent rounding. 1 Includes associated-dissolved natural gas that occ urs in crude oil reservoirs either as free gas (ass ociated) or as gas in solution with crude oil (dissolved gas).

Proved natural gas reserves accounted for about 12 percent of the total technically recoverable natural gas resources. Significant proportions of t hese reserves exist in Alaska and offshore areas. While the dry natural gas proved reserves in 2009 were estimated at 272.5 tcf, wet natural gas reserves were estimated at 283.9 tcf. Of the 28 3.9 tcf, 250.5 tcf (about 88 percent) is considered to be wet non-associated natural gas, wh ile 33.3 tcf (about 12 percent) is considered to be wet associated-dissolved natural gas. Associa ted-dissolved natural gas, according to EIA, is natural gas which occurs in crude oil reservoirs as free natural gas or in solution with crude oil.

Table 2-2 and Figure 2-1 show trends in crude oil a nd natural gas production and reserves from 1990 to 2013. In Table 2-2, proved ultimate re covery equals the sum of cumulative production and proved reserves. While crude oil and natural gas are nonrenewable resources, the table shows that proved ultimate recovery rises ove r time as new discoveries become2-11

economically accessible. Reserves growth and declin e 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.

Table 2-2 Crude Oil and Natural Gas Cumulative Dome stic Production, Proved Reserves, and Proved Ultimate Recovery, 1977-2013
Crude Oil and Lease Condensa te

(million barrels) Dry Natural Gas (Billion Cubic Feet or bcf) Cumulative Production Proved

Reserves Proved Ult.

Recovery Cumulative

Production Proved

Reserves Proved Ult.

Recovery 1990 158,175 26,254 184,429 744,546 169,346 913,892 1991 160,882 24,682 185,564 762,244 167,062 929,306 1992 163,507 23,745 187,252 780,084 165,015 945,099 1993 166,006 22,957 188,963 798,179 162,415 960,594 1994 168,437 22,457 190,894 817,000 163,837 980,837 1995 170,831 22,351 193,182 835,599 165,146 1,000,7 45 1996 173,197 22,017 195,214 854,453 166,474 1,020,9 27 1997 175,552 22,546 198,098 873,355 167,223 1,040,5 78 1998 177,834 21,034 198,868 892,379 164,041 1,056,4 20 1999 179,981 21,765 201,746 911,211 167,406 1,078,6 17 2000 182,112 22,045 204,157 930,393 177,427 1,107,8 20 2001 184,229 22,446 206,675 950,009 183,460 1,133,4 69 2002 186,326 22,677 209,003 968,937 186,946 1,155,8 83 2003 188,388 21,891 210,279 988,036 189,044 1,177,0 80 2004 190,379 21,371 211,750 1,006,627 192,513 1,199 ,140 2005 192,270 21,757 214,027 1,024,677 204,385 1,229 ,062 2006 194,127 20,972 215,099 1,043,181 211,085 1,254 ,266 2007 195,981 21,317 217,298 1,062,447 237,726 1,300 ,173 2008 197,811 19,121 216,932 1,082,605 244,656 1,327 ,261 2009 199,763 20,682 220,445 1,103,229 272,509 1,375 ,738 2010 201,764 23,267 225,031 1,124,545 304,625 1,429 ,170 2011 203,825 26,544 230,369 1,147,447 334,067 1,481 ,514 2012 206,202 30,529 236,731 1,171,480 308,036 1,479 ,516 2013 208,918 33,371 242,289 1,195,814 338,264 1,534 ,078 Source: U.S. Energy Information Administration However, annual production as a percentage of prove d reserves has declined over time for both crude oil and natural gas, from above 11 percent in the early 1990s to 8 to 10 percent over the2-12

period from 2006 to 2013 for crude oil and from abo ve 11 percent during the 1990s to between 7 and 9 percent from 2006 to 2013 for natural gas.

Figure 2-1 A) Domestic Crude Oil Proved Reserves an d Cumulative Production, 1990- 2013. B) Domestic Natural Gas Proved Reserves and C umulative Production, 1990-2013
Table 2-3 presents the U.S. proved reserves of crud e oil and natural gas by state or producing area as of 2013. Five areas currently acc ount for 81 percent of the U.S. total proved reserves of crude oil, led by Texas and followed by North Dakota, U.S. Federal Offshore, Alaska, and California. The top five states (Texas, Pennsylvania, Wyoming, Oklahoma, and West Virginia) account for about 65 percent of the U.S. total proved reserves of natural gas.

0 50,000 100,000 150,000 200,000 250,000 300,000Crude Oil (million bbl) A). Crude Oil

0 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600,000 1,800,000Natural Gas (bcf) B). Natural Gas

Cumulative Production Proved Reserves2-13

Table 2-3 Crude Oil and Dry Natural Gas Proved Rese rves by State, 2013

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

(% of total) Dry Natural Gas

(% of total) Alabama 44 1,597 0.1 0.5 Alaska 2,898 7,316 8.7 2.2 Arkansas 40 13,518 0.1 4.0 California 2,876 1,887 8.6 0.6 Colorado 896 22,381 2.7 6.6 Florida 38 15 0.1 0.0 Kansas 372 3,592 1.1 1.1 Kentucky 17 1,663 0.1 0.5 Louisiana 503 20,164 1.5 6.0 Michigan 64 1,807 0.2 0.5 Miscellaneous States 105 2,552 0.3 0.8 Mississippi 223 595 0.7 0.2 Montana 413 575 1.2 0.2 New Mexico 1,171 13,576 3.5 4.0 New York * 144 * 0.0 North Dakota 5,677 5,420 17.0 1.6 Ohio 42 3,161 0.1 0.9 Oklahoma 1,019 26,873 3.1 7.9 Pennsylvania 15 49,674 0.0 14.7 Texas 10,468 90,349 31.4 26.7 U.S. Federal Offshore 5,137 8,193 15.4 2.4 Utah 613 6,829 1.8 2.0 West Virginia 17 22,765 0.1 6.7 Wyoming 723 33,618 2.2 9.9

Total Proved Reserves 33,371 338,264 100.0 100.0 Source: U.S. Energy Information Administration. Tot al may not sum due to independent rounding. * New York crude oil reserves are included in misce llaneous states.

2.4.2 Domestic Production
Domestic oil production was in a state of decline t hat began in 1970 and continued to a low point in 2008. Since 2008, domestic oil product ion has recovered to the highest levels since 1991. Table 2-4 shows U.S. production in 2013 at 2, 716 million bbl per year.2-14

Table 2-4 Crude Oil Domestic Production, Wells, Wel l Productivity, and U.S. Average First Purchase Price, 1990-2013

Total Production (million barrels) Producing Wells (1000s) Avg. Well

Productivity (bbl/well) US Average

First Purchase Price/Barrel (nominal dollars) US Average

First Purchase Price/Barrel (2012 dollars) 1990 2,685 602 4,460 20.03 31.55 1991 2,707 614 4,409 16.54 25.21 1992 2,625 594 4,419 15.99 23.83 1993 2,499 584 4,279 14.25 20.74 1994 2,431 582 4,178 13.19 18.80 1995 2,394 574 4,171 14.62 20.41 1996 2,366 574 4,122 18.46 25.31 1997 2,355 573 4,110 17.23 23.23 1998 2,282 562 4,060 10.87 14.50 1999 2,147 546 3,932 15.56 20.44 2000 2,131 534 3,990 26.72 34.32 2001 2,118 530 3,995 21.84 27.42 2002 2,097 529 3,963 22.51 27.84 2003 2,062 513 4,019 27.56 33.42 2004 1,991 510 3,905 36.77 43.39 2005 1,891 498 3,798 50.28 57.49 2006 1,857 497 3,737 59.69 66.21 2007 1,853 500 3,706 66.52 71.87 2008 1,830 526 3,479 94.04 99.64 2009 1,953 526 3,712 56.35 59.26 2010 2,001 520 3,848 74.71 77.62 2011 2,060 536 3,844 95.73 97.45 2012 2,378 N/A N/A 94.52 94.52 2013 2,716 N/A N/A 95.99 94.58 Source: U.S. Energy Information Administration First purchase price represents the average price a t the lease or wellhead at which domestic crude is purchased. Prices adjusted using GDP Implicit Price Deflator.

Average well productivity has also generally decrea sed 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.

Annual production of natural gas from natural gas w ells has increased more than 8000 bcf from the 1990 to 2013 (Table 2-5). The number o f wells producing natural gas has nearly doubled between 1990 and 2011 (Figure 2-2). While t he number of producing wells has increased overall, average well productivity has de clined, despite improvements in exploration and gas well stimulation technologies.2-15

Table 2-5 Natural Gas Production and Well Productiv ity, 1990-2013
Natural Gas Gross Withdrawals (Billion Cubic Feet) Natural Gas Well Productivity

Total Dry Gas Production 1 Producing

Wells Avg. Well

Productivity Million Cubic Feet/Year) 1990 21,523 17,810 269,790 66.0 1991 21,750 17,698 276,987 63.9 1992 22,132 17,840 276,014 64.6 1993 22,726 18,095 282,152 64.1 1994 23,581 18,821 291,773 64.5 1995 23,744 18,599 298,541 62.3 1996 24,114 18,854 301,811 62.5 1997 24,213 18,902 310,971 60.8 1998 24,108 19,024 316,929 60.0 1999 23,823 18,832 302,421 62.3 2000 24,174 19,182 341,678 56.1 2001 24,501 19,616 373,304 52.5 2002 23,941 18,928 387,772 48.8 2003 24,119 19,099 393,327 48.6 2004 23,970 18,591 406,147 45.8 2005 23,457 18,051 425,887 42.4 2006 23,535 18,504 440,516 42.0 2007 24,664 19,266 452,945 42.5 2008 25,636 20,159 476,652 42.3 2009 26,057 20,624 493,100 41.8 2010 26,816 21,316 487,627 43.7 2011 28,479 22,902 514,637 44.5 2012 29,542 24,033 482,822 49.8 2013 30,005 24,334 487,286 49.92-16

Figure 2-2 A) Total Producing Crude Oil Wells and A verage Well Productivity, 1990- 2011. B) Total Producing Natural Gas Wells and Ave rage Well Productivity, 1990-2013.
Domestic exploration and development for oil has co ntinued during the last two decades. From 2002 to 2010, crude oil well drilling showed s ignificant increases, although the 1992-2004 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 depart ure from this trend, likely due to the recession experienced in the U.S.

Meanwhile, natural gas drilling has increased signi ficantly during the 1990-2010 period. Like crude oil drilling, 2009 and 2010 saw a relati vely low level of natural gas drillings. The success rate of wells (producing wells versus dry w ells) has also increased gradually over time from 75 percent in 1990, to 86 percent in 2000, to a peak of 90 percent in 2009 (Table 2-6). The increasing success rate reflects improvements in ex ploration technology, as well as technological 0 1,000 2,000 3,000 4,000 5,000

0 100 200 300 400 500 600 700Crude Oil (bbl)/WellProducing Wells A). Crude Oil Wells

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

0 100,000 200,000 300,000 400,000 500,000 600,000

0 10 20 30 40 50 60 70Natural Gas(MMcf)/WellProducing Wells B). Natural Gas Wells

Avg. Well Productivity (MMcf/year) Producing Wells2-17

improvements in well drilling and completion. Simil arly, well average depth has also increased by during this period (Table 2-6).
Table 2-6 Crude Oil and Natural Gas Exploratory and Development Wells and Average Depth, 1990-2010

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

Depth (ft) 1990 12,445 11,126 8,496 32,067 75 4,881 1991 12,035 9,611 7,882 29,528 75 4,920 1992 9,019 8,305 6,284 23,608 75 5,202 1993 8,764 10,174 6,513 25,451 75 5,442 1994 7,001 9,739 5,515 22,255 77 5,795 1995 7,827 8,454 5,319 21,600 77 5,636 1996 8,760 9,539 5,587 23,886 79 5,617 1997 10,445 11,186 5,955 27,586 79 5,691 1998 6,979 11,127 4,805 22,911 80 5,755 1999 4,314 11,121 3,504 18,939 83 5,090 2000 8,090 17,051 4,146 29,287 86 4,961 2001 8,888 22,072 4,598 35,558 87 5,087 2002 6,775 17,342 3,754 27,871 87 5,232 2003 8,129 20,722 3,982 32,833 88 5,426 2004 8,789 24,186 4,082 37,057 89 5,547 2005 10,779 28,590 4,653 44,022 89 5,508 2006 13,385 32,838 5,206 51,429 90 5,613 2007 13,371 32,719 4,981 51,071 90 6,064 2008 16,633 32,246 5,423 54,302 90 5,964 2009* 11,190 18,088 3,525 32,803 90 6,202 2010* 15,753 16,696 4,162 36,611 89 6,108 Source: U.S. Energy Information Administration * Average Depth values for 2009-2010 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 e stimates 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 0.61 Tribal Lands 9,513 297 149,261 62,379 2.39 Federal Total 476,693 3,084 736,614 1,025,645 0.72 U.S. Total 1,750,452 24,374 20,995,174 6,089,024 3 .45 Source: Argonne National Laboratory and Department of Energy (2009). Natural gas production converted to barrels oil equivalent to facilitate comparison usi ng the conversion of 0.178 barrels of crude oil equ als 1000 cubic feet natural gas. Totals may not sum due to i ndependent rounding.2-19

As can be seen in Table 2-7, the amount of water p roduced 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 as 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 th e 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 1990-2011 period (Table 2-8), appearing to follow the downward supply trend shown in Table 2-4 . While exhibiting some variation, pipeline mileage transporting refined products remained rela tively 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 , 2010-2013 Natural Gas Pipelines (miles) Distribution mains Distribution

Service Transmission

pipelines Gathering

lines Total 2010 1,229,501 872,377 304,775 19,640 2,426,293 2011 1,238,683 881,886 305,036 19,364 2,444,969 2012 1,247,115 892,209 303,333 16,524 2,459,181 2013 1,254,686 894,605 302,827 17,435 2,469,553 Source: U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Off ice of Pipeline Safety, Annual Report Mileage Summary Statistics , available at http://phmsa.dot.gov/pipeline/library/data-stats as of December 29, 2014.

Table 2-8 splits natural gas pipelines into four ty pes: distribution mains, distribution service, transmission pipelines, and gathering line s. Gathering lines are low-volume pipelines that gather natural gas from production sites to de liver directly to gas processing plants or compression stations that connect numerous gatherin g lines to transport gas primarily to processing plants. Transmission pipelines move larg e volumes of gas to or from processing plants to distribution points. From these distribut ion points, the gas enters a distribution system that delivers the gas to final consumers.

2.4.3 Domestic Consumption
Historical crude oil sector-level consumption trend s for 1990 through 2012 are shown in

Table 2-9 and Figure 2-4. Total consumption rose gr adually until 2008 when consumption dropped as a result of the economic rec ession. The share of residential, commercial, industrial, and electric power on a percentage basi s declined during this period, while the share of total consumption by the transportation sector r ose from 64 percent in 1990 to 71 percent in
2012.

Table 2-9 Crude Oil Consumption by Sector, 1990-201 2 Percent of Total
Total (million barrels) Residential and

Commercial Industrial Transportation

Sector Electric

Power 1990 6,178 7.3 25.1 64.3 3.3 1991 6,068 7.3 24.9 64.7 3.2 1992 6,209 7.1 26.1 64.3 2.6 1993 6,277 6.9 25.3 65.0 2.9 1994 6,439 6.6 26.0 64.8 2.62-21 1995 6,402 6.4 25.7 66.0 1.9 1996 6,627 6.7 26.1 65.2 2.0 1997 6,726 6.3 26.4 65.1 2.2 1998 6,837 5.7 25.4 65.8 3.1 1999 7,053 6.1 25.6 65.5 2.8 2000 6,984 4.6 25.1 67.6 2.6 2001 6,963 4.6 25.1 67.4 2.9 2002 6,990 4.2 25.2 68.3 2.2 2003 7,091 4.6 24.8 67.9 2.7 2004 7,399 4.4 25.3 67.7 2.6 2005 7,530 5.8 24.2 67.3 2.6 2006 7,506 5.0 24.8 68.9 1.4 2007 7,517 5.1 24.1 69.5 1.4 2008 7,095 5.5 23.0 70.4 1.1 2009 6,849 5.5 22.2 71.4 1.0 2010 6,994 5.2 22.8 71.0 0.9 2011 7,013 5.0 23.2 71.1 0.7 2012 6,902 5.0 23.4 71.1 0.5 Source: U.S. Energy Information Administration.

Figure 2-4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990- 2011 0% 10% 20% 30% 40% 50% 60% 70% 80%Consumption (% of total)

Residential and Commercial Industrial

Transportation Sector Electric Power2-22

Natural gas consumption has increased over the last twenty years. From 1990 to 2012, 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 consu mption 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.2-23

Table 2-10 Natural Gas Consumption by Sector, 1990- 2012
Percent of Total
Total (tcf) Residential Commercial Industrial Electric Power Transportation 1990 19.93 22.0 13.1 45.3 16.2 3.3 1991 19.56 23.2 13.9 42.8 17.0 3.1 1992 20.23 23.1 13.8 43.1 17.0 2.9 1993 20.80 23.8 13.8 42.7 16.7 3.0 1994 21.27 22.8 13.6 42.0 18.3 3.2 1995 22.25 21.8 13.6 42.4 19.0 3.2 1996 22.67 23.1 14.0 42.9 16.8 3.2 1997 22.88 21.8 14.1 43.0 17.8 3.3 1998 22.32 20.3 13.4 42.9 20.6 2.9 1999 22.43 21.1 13.6 40.9 21.5 2.9 2000 23.31 21.3 13.6 39.9 22.3 2.8 2001 22.21 21.4 13.6 37.9 24.1 2.9 2002 23.02 21.2 13.7 37.5 24.7 3.0 2003 22.03 23.0 14.4 37.5 22.2 2.8 2004 21.99 22.1 14.2 37.9 23.0 2.7 2005 21.62 22.3 13.9 35.7 25.3 2.9 2006 21.37 20.4 13.2 35.9 27.6 2.9 2007 22.78 20.7 13.2 34.6 28.6 2.9 2008 22.95 21.3 13.7 34.4 27.6 3.0 2009 22.89 20.9 13.6 32.5 29.9 3.1 2010 24.06 19.9 12.9 33.7 30.6 3.0 2011 24.38 19.3 12.9 33.7 31.0 3.0 2012 25.64 16.3 11.3 33.4 36.1 3.0 Source: U.S. Energy Information Administration.2-24

Figure 2-5 Natural Gas Consumption by Sector (Perce nt of Total Consumption), 1990- 2012

2.4.4 International Trade Until 2006, net trade of crude oil and refined petr oleum products increased, showing increased substitution of imports for domestic prod uction, as well as imports satisfying growing consumer demand in the U.S. (Table 2-11). Since the n, however, imports have been declining while exports have been rising, leading to signific ant declines in net trade or crude oil and petroleum products. 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50%Consumption (% of total)

Residential Commercial Industrial

Electric Power Transportation2-25

Table 2-11 Total Crude Oil and Petroleum Products T rade (Million Bbl), 1990-2013 Imports Exports Net Imports

Crude Oil Petroleum Products Total Crude Oil Petroleum Products Total Crude Oil Petroleum Products Total 1990 2,151 775 2,926 40 273 313 2,112 502 2,614 1991 2,111 673 2,784 42 323 365 2,068 350 2,418 1992 2,226 661 2,887 32 315 348 2,194 345 2,539 1993 2,477 669 3,146 36 330 366 2,441 339 2,780 1994 2,578 706 3,284 36 308 344 2,542 398 2,940 1995 2,639 586 3,225 35 312 346 2,604 274 2,878 1996 2,748 721 3,469 40 319 359 2,708 403 3,110 1997 3,002 707 3,709 39 327 366 2,963 380 3,343 1998 3,178 731 3,908 40 305 345 3,137 426 3,564 1999 3,187 774 3,961 43 300 343 3,144 474 3,618 2000 3,320 874 4,194 18 362 381 3,301 512 3,813 2001 3,405 928 4,333 7 347 354 3,398 581 3,979 2002 3,336 872 4,209 3 356 359 3,333 517 3,849 2003 3,528 949 4,477 5 370 375 3,523 579 4,102 2004 3,692 1119 4,811 10 374 384 3,682 745 4,427 2005 3,696 1310 5,006 12 414 425 3,684 896 4,580 2006 3,693 1310 5,003 9 472 481 3,684 838 4,523 2007 3,661 1255 4,916 10 513 523 3,651 742 4,393 2008 3,581 1146 4,727 10 649 659 3,570 497 4,068 2009 3,290 977 4,267 16 723 739 3,274 255 3,528 2010 3,363 942 4,305 15 843 859 3,348 98 3,446 2011 3,261 913 4,174 17 1073 1,090 3,244 -160 3,084 2012 3,121 758 3,879 25 1148 1,173 3,096 -390 2,706 2013 2,821 777 3,598 49 1273 1,322 2,773 -496 2,277 Source: U.S. Energy Information Administration.

Natural gas imports also increased steadily from 19 90 to 2007 in volume and percentage terms (Table 2-12). The years 2007 through 2012 saw imported natural gas constituting a lower percentage of domestic natural gas consumption. Unt il recent years, industry analysts forecast that LNG imports would continue to grow as a percen tage of U.S. consumption. However, it is possible that increasingly accessible domestic unco nventional gas resources, such as shale gas and coalbed methane, might reduce the need for the U.S. to import natural gas, either via pipeline or shipped LNG.2-26

Table 2-12 Natural Gas Imports and Exports, 1990-20 13

Total Imports (bcf) Total Exports

(bcf) Net Imports

(bcf) Percent of U.S.

Consumption 1990 1,532 86 1,447 7.3 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 12.4 1998 3,152 159 2,993 13.4 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 14.8 2004 4,259 854 3,404 15.5 2005 4,341 729 3,612 16.7 2006 4,186 724 3,462 16.2 2007 4,608 822 3,785 16.6 2008 3,984 963 3,021 13.2 2009 3,751 1,072 2,679 11.7 2010 3,741 1,137 2,604 10.8 2011 3,468 1,506 1,962 8.0 2012 3,138 1,619 1,519 5.9 2013 2,883 1,572 1,311 N/A Source: U.S. Energy Information Administration.

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 forec asts are from the 2014 Annual Energy Outlook produced by EIA, the most current forecast information available from EIA. As will be discussed in detail in Section 7, 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 2014 Annual Energy Outlook.

Table 2-13 present forecasts of successful wells d rilled in the U.S. from 2010 to 2040.
Crude oil well forecasts for the lower 48 states sh ow a rise up to the year 2025 then a gradual
decline until 2040.2-27

Table 2-13 Forecast of Total Successful Wells Drill ed, Lower 48 States, 2010-2040
Totals Year Crude Oil Natural Gas 2010 19,316 19,056 2011 23,048 14,355 2012 26,749 11,011 2013 25,248 11,507 2014 22,274 14,099 2015 22,706 14,076 2016 22,552 15,004 2017 22,355 15,773 2018 22,421 18,340 2019 22,525 20,188 2020 24,765 20,396 2021 25,017 23,427 2022 25,400 24,945 2023 25,981 24,999 2024 26,917 24,745 2025 27,763 24,831 2026 26,258 25,445 2027 25,830 26,895 2028 25,270 28,341 2029 24,801 29,019 2030 24,310 28,799 2031 23,972 29,681 2032 23,607 31,406 2033 23,283 31,749 2034 23,057 32,882 2035 22,740 33,278 2036 22,494 33,456 2037 22,343 33,536 2038 22,075 33,944 2039 21,911 34,001 2040 21,750 33,656 Source: U.S. Energy Information Administration, Annual Energy Outlook 2014.
Meanwhile, show increases for natural gas drilling in the lower 48 states from the present to 2040, more than doubling during this 25-year period

.
Table 2-14 presents forecasts of domestic crude oil production, reserves, imports and 6 depicts these trends graphically.2-28

Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2011-2040 Domestic Production (million bbls)

Total Domestic Lower

48 Onshore Lower

48 Offshore Alaska Other Crude Supply Net

Imports Total

Crude Supply Lower

48 End of Year Reserves (million bbls) Lower 48

Average Wellhead Price (2012 dollars per barrel) 2011 2,065 1,336 520 209 97 3,244 7,472 9,161 98. 12 2012 2,370 1,679 498 193 32 3,078 7,850 9,018 94. 94 2013 2,819 2,132 500 186 85 2,687 8,409 9,360 97. 54 2014 3,113 2,396 544 173 59 2,355 8,640 10,054 98 .50 2015 3,299 2,534 595 169 0 2,250 8,848 10,224 93. 15 2016 3,483 2,581 733 169 0 2,105 9,071 10,957 89. 76 2017 3,488 2,598 719 172 0 2,122 9,099 11,073 88. 23 2018 3,495 2,607 716 172 0 2,120 9,110 11,228 88. 87 2019 3,507 2,620 721 166 0 2,102 9,116 11,410 90. 82 2020 3,487 2,632 695 160 0 2,112 9,086 11,599 92. 93 2021 3,437 2,632 654 151 0 2,149 9,024 11,652 95. 30 2022 3,390 2,624 625 142 0 2,169 8,950 11,721 97. 81 2023 3,355 2,610 611 134 0 2,181 8,890 11,830 100 .25 2024 3,312 2,594 591 126 0 2,203 8,826 11,898 102 .65 2025 3,287 2,570 598 119 0 2,209 8,782 12,050 104 .90 2026 3,224 2,517 595 112 0 2,259 8,707 12,192 106 .89 2027 3,164 2,474 586 105 0 2,312 8,640 12,237 109 .28 2028 3,108 2,429 581 99 0 2,356 8,573 12,299 111. 00 2029 3,059 2,381 585 93 0 2,397 8,515 12,367 113. 00 2030 3,031 2,330 614 88 0 2,422 8,484 12,564 114. 69 2031 2,978 2,284 611 83 0 2,475 8,431 12,585 116. 70 2032 2,947 2,237 610 100 0 2,505 8,398 12,612 118 .92 2033 2,936 2,195 617 124 0 2,518 8,390 12,650 121 .24 2034 2,914 2,155 618 142 0 2,554 8,383 12,642 123 .50 2035 2,873 2,114 622 138 0 2,610 8,356 12,622 125 .59 2036 2,830 2,068 628 135 0 2,666 8,327 12,618 127 .47 2037 2,810 2,028 651 131 0 2,703 8,324 12,687 129 .33 2038 2,759 1,987 654 117 0 2,781 8,299 12,656 131 .59 2039 2,749 1,949 694 105 0 2,797 8,294 12,859 134 .45 2040 2,730 1,909 726 95 0 2,826 8,287 12,938 13 7.63 Source: U.S. Energy Information Administration, Annual Energy Outlook, 2014

Table 2-14 also shows forecasts of proved reserves in the lower 48 states. The reserves forecast shows steady growth from 2010 to 2040, an increase of 25 percent overall. This increment is larger than the forecast increase in production fro m the lower 48 states during this period, 122-29

percent, showing reserves are forecast to grow more rapidly than production. Table 2-14 also shows average wellhead prices increasing more than 100 percent from 2010 to 2040, from $76.78 per barrel to $160.38 per barrel in 2011 dol lar terms.

Figure 2-6 Forecast of Domestic Crude Oil Productio n and Net Imports, 2010-2040

Table 2-15 shows domestic natural gas production is forecast to increase until 2040. Meanwhile, imports of natural gas via pipeline are expected to be eliminated during the forecast period, from 1.68 tcf in 2011 to -2.43 in 2040 tcf. Imports of LNG are also eliminated during the forecast period, from 0.28 tcf in 2011 to -3.37 tcf in 2040. Total supply, then, increases about 33 percent, from 22.55 tcf in 2011 to 37.54 tcf in 204 0.

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000Crude Oil (Million bbl)

Total Domestic Net Imports Lower 48 Onshore Lower 48 Offshore Alaska2-30

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

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 per well has increased by an annual average of Dry Gas Productio

n Supplemen tal Natural Gas Net Imports (Pipeline) Net

Imports (LNG) Total

Supply Lower 48 End

of Year Dry Reserves (tcf) Average Henry Hub

Spot Price (2012 dollars per million Btu) 2011 22.55 0.06 1.68 0.28 24.57 324.6 4.07 2012 24.06 0.06 1.37 0.15 25.64 320.1 2.75 2013 24.19 0.06 1.22 0.12 25.59 329.1 3.60 2014 24.28 0.07 1.21 0.14 25.69 332.5 3.74 2015 24.63 0.06 1.05 0.04 25.78 337.0 3.74 2016 25.68 0.06 0.92 -0.16 26.50 341.8 4.14 2017 26.38 0.06 0.64 -0.61 26.47 344.5 4.40 2018 27.20 0.06 0.45 -1.11 26.61 346.1 4.80 2019 28.19 0.06 0.22 -1.62 26.85 348.6 4.66 2020 29.09 0.06 0.00 -1.93 27.23 352.5 4.38 2021 29.70 0.06 -0.13 -2.17 27.47 354.6 4.67 2022 30.19 0.06 -0.32 -2.17 27.77 358.0 4.82 2023 30.92 0.06 -0.51 -2.37 28.11 362.2 4.96 2024 31.44 0.06 -0.62 -2.57 28.31 365.1 5.12 2025 31.86 0.06 -0.84 -2.57 28.52 368.5 5.23 2026 32.47 0.06 -0.97 -2.77 28.79 372.4 5.36 2027 33.07 0.06 -1.14 -2.97 29.02 375.4 5.49 2028 33.65 0.06 -1.28 -3.17 29.27 378.4 5.59 2029 34.09 0.06 -1.42 -3.35 29.39 380.6 5.78 2030 34.43 0.06 -1.57 -3.37 29.56 382.6 6.03 2031 34.66 0.06 -1.67 -3.37 29.69 385.2 6.17 2032 35.04 0.06 -1.87 -3.37 29.86 387.5 6.36 2033 35.39 0.06 -1.97 -3.37 30.12 389.6 6.59 2034 35.73 0.06 -2.04 -3.37 30.38 391.9 6.74 2035 36.09 0.06 -2.16 -3.37 30.63 393.6 6.92 2036 36.36 0.06 -2.25 -3.37 30.80 394.7 7.18 2037 36.68 0.06 -2.31 -3.37 31.06 397.5 7.23 2038 37.04 0.06 -2.39 -3.37 31.34 399.6 7.26 2039 37.36 0.06 -2.48 -3.37 31.57 401.6 7.42 2040 37.54 0.06 -2.43 -3.37 31.81 402.6 7.65 Domestic Production (tcf) Net Imports (tcf)

Source: U.S. Energy Information Administration, Ann ual Energy Outlook, 20142-31

about 15 percent, and cost per foot has increased o n average of about 13 percent per year (Figure 2-7).

Figure 2-7 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. These 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 2-8 shows average domestic onshore and offshore and foreign finding costs for the samp le of U.S. firms in EIA’s Financial Reporting System (FRS) database from 1981 to 2009. The costs are reported in 2009 dollars on a barrel of oil equivalent basis for crude oil and natural gas combined. The average domestic finding costs dropped from 1981 until the mid-1990s. Interestingl y, in the mid-1990s, domestic onshore and offshore and foreign finding costs converged for a few years. After this period, offshore finding costs rose faster than domestic onshore and foreign costs.

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

1981 1984 1987 1990 1993 1996 1999 2002 2005 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)2-32

Figure 2-8 Finding Costs for FRS Companies, 1981-20 09

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 2-7 and finding costs in Figure 2-8 prese nt 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 cos ts includes costs of operating and maintaining wells and associated production equipment. Direct l ifting 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 2009 dollars on a barrel of oil equivalent basis. Total lifting costs are the sum of direct lifting costs and produ ction taxes. Figure 2-9 depicts direct lifting cost trends from 1981 to 2009 for domestic and foreign p roduction.

0 10 20 30 40 50 60 70 80$2008/boe

U.S. Onshore U.S. Offshore Foreign2-33

Figure 2-9 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2009 (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 2009, domestic lifting costs increased sharply, just over $8 per barrel of oil equivalent. Foreign lifting 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 2009.

2.5.3 Operating and Equipment Costs
The EIA report, “Oil and Gas Lease Equipment and Op erating Costs 1994 through
2009” 11 , 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 six regions (California, Mid-Continent, South Louisiana , South Texas, West Texas, and Rocky

11 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 ren t/coststudy.html > Accessed February 2, 2011.

0 2 4 6 8 10 12 14$2008/boe

Domestic Foreign2-34

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 2-10 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 this ti me period, while operating costs have risen more quickly than equipment costs. Operating and eq uipment costs and oil prices rose steeply in the late 1970s, but generally decreased from about 1980 until the late 1990s.

Figure 2-10 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976 dollars), 1976-2009 12
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 equipment costs are 154 and 107, respectively.

12 The last release date for EIA’s Oil and Gas Lease Equipment and Operating Costs analysis was September 2010. Updates have been discontinued. 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)2-35

Figure 2-11 Natural Operating Costs and Equipment C osts Indices (1976=100) and Natural Gas Price, 1976-2009
Figure 2-11 depicts natural gas operating and equip ment costs indices, as well as natural gas prices. Similar to the cost trends for crude oil, n atural gas operating and equipment costs track the price of natural gas over this time period, 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. 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)2-36

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 prod ucers include large oil and gas companies that are involved in each of the five industry segm ents: drilling and exploration, production, transportation, refining, and marketing. Independen t 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 re ports 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, transpo rters are comprised of the pipeline companies, while distributors are comprised of the local distribution companies.

2.6.2 Size Distribution of Firms in Affected NAICS

As of 2014, there were 6,659 firms within the 21111 1 and 211112 NAICS codes, of which 6,535 (98 percent) were considered small enti ties (Table 2-16). Within NAICS 211111 and 211112, large firms compose about 2 percent of the firms, but account for about 60 percent of employment listed under these NAICS.2-37

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

NAICS NAICS Description SBA Size Standard (Employees or Annual Receipts) Small

Firms Large

Firms Total

Firms Number of Firms by Firm Size
211111 Crude Petroleum and Natural Gas Extraction 5 00 6,436 87 6,523 211112 Natural Gas Liquid Extraction 500 99 37 136 213111 Drilling Oil and Gas Wells 500 1,993 48 2,04 1 213112 Support Activities for Oil and Gas Operation s $38.5 million N/A N/A 8,119 486210 Pipeline Transportation of Natural Gas $27.5 million N/A N/A 107

Total Employment by Firm Size
211111 Crude Petroleum and Natural Gas Extraction 5 00 45,641 63,313 108,954 211112 Natural Gas Liquid Extraction 500 1,733 8,27 2 10,005 213111 Drilling Oil and Gas Wells 500 36,663 57,843 94,506 213112 Support Activities for Oil and Gas Operation s $38.5 million N/A N/A 219,827 486210 Pipeline Transportation of Natural Gas $27.5 million N/A N/A 27,151 Source: U.S. Small Business Administration Office o f Advocacy. 2014. Firm Size Data. <Available at https://www.sba.gov/a dvocacy/firm-size-data> Accessed January 5, 2015. Note: "N/A" indicates where national counts of smal l and large firms could not be performed.

The small and large firms within NAICS 21311 are si milarly distributed, with large firms accounting for about 2 percent of firms, but 61 per cent of employment. Because there are relatively few firms within NAICS 486210, the Censu s Bureau cannot release breakdowns of firms by size in sufficient detail to perform simil ar calculation.

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. Ta ble 2-17 shows employment in oil and natural gas-related NAICS codes from 1990 to 2013. The overall trend shows a decline in total industry employment throughout the 1990s, hitting a low of 314,000 in 1999, but rebounding to a 2013 peak of 620,000. Crude Petroleum and Natural G as Extraction (NAICS 211111) and Support Activities for Oil and Gas Operations (NAIC S 213112) employ the majority of workers in the industry.2-38

Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-2013

Crude Petroleum and Natural Gas Extraction (NAICS 211111) Natural

Gas Liquid Extraction (NAICS 211112) Drilling of

Oil and Natural Gas Wells (NAICS 213111) Support

Activities for Oil and Gas Ops. (NAICS 213112) Pipeline

Trans. of Crude Oil (NAICS 486110) Pipeline

Trans. of Natural Gas (NAICS 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 33,620 350, 469 2002 116,559 4,565 48,596 120,536 7,447 31,556 329, 259 2003 115,636 4,691 51,526 120,992 7,278 29,684 329, 807 2004 117,060 4,285 57,332 128,185 7,073 27,340 341, 275 2005 121,535 4,283 66,691 145,725 6,945 27,341 372, 520 2006 130,188 4,670 79,818 171,127 7,202 27,685 420, 690 2007 141,239 4,842 84,525 197,100 7,975 27,431 463, 112 2008 154,898 5,183 92,640 223,635 8,369 27,080 511, 805 2009 155,150 5,538 67,756 193,589 8,753 26,753 457, 539 2010 153,490 4,833 74,491 201,685 8,893 26,708 470, 100 2011 164,900 5,835 87,272 241,490 8,959 27,320 535, 776 2012 181,473 6,529 92,340 282,447 9,348 27,595 599, 732 2013 189,804 6,928 93,261 296,891 10,059 26,981 623 ,924 Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2013 , <http://www.bls.gov/cew/>

From 1990 to 2013, average wages for the oil and na tural gas industry have increased. Table 2-18 shows real wages (in 2012 dollars) from 1990 to 2013 for the NAICS codes associated with the oil and natural gas industry.2-39

Table 2-18 Oil and Natural Gas Industry Average Wag es by NAICS, 1990-2013 (2012 dollars) Crude

Petroleum and Natural Gas Extraction (211111) Natural

Gas Liquid Extraction (211112) Drilling of

Oil and Natural Gas Wells (213111) Support

Activities for Oil and Gas Ops. (213112) Pipeline

Trans. of Crude Oil (486110) Pipeline

Trans. of Natural Gas (486210) Total 1990 74,475 69,877 44,193 48,010 71,231 64,452 62,2 45 1991 75,980 69,993 45,593 49,578 72,277 68,228 63,8 86 1992 80,222 72,285 45,683 51,355 77,941 70,472 67,4 35 1993 81,214 72,237 47,486 52,649 76,445 70,777 67,7 34 1994 82,976 74,277 46,717 52,565 79,790 71,804 68,0 58 1995 85,341 70,873 48,462 53,294 82,717 75,418 69,6 34 1996 88,319 72,256 51,256 55,400 80,589 80,103 71,7 27 1997 94,309 83,369 54,754 58,343 82,305 86,858 75,3 55 1998 97,870 94,427 55,692 60,445 83,028 88,367 77,3 93 1999 103,235 93,852 57,216 62,756 86,626 99,119 82, 969 2000 115,018 117,477 63,787 63,505 84,994 136,907 9 0,990 2001 116,417 116,513 64,792 64,298 87,363 128,243 8 9,416 2002 115,314 108,703 65,226 62,847 91,763 96,010 86 ,240 2003 116,161 118,322 64,095 64,368 91,788 96,109 86 ,714 2004 127,324 124,374 66,251 65,672 98,381 98,485 90 ,960 2005 133,920 134,419 74,486 70,753 96,906 95,017 95 ,030 2006 145,658 140,685 78,047 74,085 96,693 104,055 1 00,084 2007 143,266 140,329 86,705 76,099 101,516 111,476 101,724 2008 153,155 132,582 86,845 78,432 107,836 105,127 105,011 2009 141,752 131,508 85,854 74,579 106,188 106,598 102,193 2010 152,074 131,980 86,297 77,774 108,855 112,857 106,522 2011 156,035 120,939 91,885 81,441 114,710 116,266 108,863 2012 155,735 136,352 92,266 80,222 120,292 139,127 108,872 2013 153,095 122,787 92,737 80,516 116,215 116,621 107,028 Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2013, annual wages per employee <http://www.bls.gov/cew/>

Employees in the NAICS 211 codes earn the highest a verage wages in the oil and natural gas industry, while employees in the NAICS 213 code s have relatively lower wages. Average wages in natural gas pipeline transportation show t he highest variation.

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 a spects of a firm’s size reflect the extent to which goods and services that can be bought from outside are produced in house, while the horizontal2-40

aspect of a firm’s size refers to the scale of prod uction in a single-product firm or its scope in a multiproduct one. Vertical integration is a potenti ally important dimension in analyzing firmlevel impacts because the regulation could affect a vertically integrated firm on more than one level. The regulation may affect companies for whom oil and natural gas production is only one of several processes in which the firm is involved. For example, a company that owns oil and natural gas production facilities may ultimately pr oduce final petroleum products, such as motor gasoline, jet fuel, or kerosene. This firm would be considered vertically integrated because it is involved in more than one level of requiring crude oil and natural gas and finished petroleum products. A regulation that increases the cost of o il and natural gas production will ultimately affect the cost of producing final petroleum produc ts.

Horizontal integration is also a potentially import ant dimension in firm-level analyses for any of the following reasons. A horizontally integr ated firm may own many facilities of which only some are directly affected by the regulation. Additionally, a horizontally integrated firm may own facilities in unaffected industries. This t ype of diversification would help mitigate the financial impacts of the regulation. A horizontally integrated firm could also be indirectly as well as directly affected by the regulation.

In addition to the vertical and horizontal 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 distribution of natural gas usually occur at individual firms, although processing is increasing performed by the integrated major companies. Several natural gas firms operate multiple facilities. However, nat ural gas wells are not exclusive to natural gas firms only. Typically wells produce both oil and ga s 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 the2-41

wellhead from the sale of oil and natural gas or th e provision of oil and gas production-related engineering or financial services. Overall, indepen dent 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 public oil and natural gas co mpanies with domestic reserves and headquarters in the U.S. In the past, the survey re ported information on the top 300 companies, now the top 150. In 2012, 134 public companies are listed; in 2011there were 145 firms. 13 The 2012 list contains four companies that were not on the list in the previous year. Also, 10 other companies listed in 2011do not appear on the 2012 l ist as a result of mergers, bankruptcies, or
other reasons. Table 2-19 lists selected statistics for the top 20 companies in 2012. The results presented in the table reflect a decline in U.S. na tural gas and natural gas liquids prices, weak energy demand growth, and increased capital and ope rating costs in 2012.

Net income for the top 134 companies fell between 2 011 and 2012 from $114.5 billion to $91.1 billion. Revenues for these companies fell 1. 4 percent from 2011 to 2012. Even though earnings decreased in 2012, strong earnings from 20 11 boosted available financial resources and the companies continued to invest. Capital and expl oratory spending for the companies in 2012 totaled $206.5 billion, up 17.1 from 2011.

The total worldwide liquids production for the 134 firms increased 6.85 percent to 2.879 billion bbl, while total worldwide gas production i ncreased 2.4 percent to a total of 17.4 tcf ( Oil
and Gas Journal , September 2, 2013). Meanwhile, the 134 firms on t he OGJ list increased both oil and natural gas production and reserves from 20 11 to 2012. Domestic production of liquids increased about 19.8 percent from 2011 to 1.437 bil lion bbl, and natural gas production was up about 6.3 percent. For context, the OGJ150 domestic crude production represents about 49 percent of total domestic production (2.06 billion bbl, according to EIA). The OGJ150 natural gas production represents about 69 percent of total domestic production (28.5 tcf, according to

13 Oil and Gas Journal. “OGJ150 Earnings Down as US P roduction Climbs.” September 2, 2013.2-42

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 57 9 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 579 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.2-43Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012WorldwideProductionUSProductionRank byTotalAssets Company EmployeesTotalAssets($Million)TotalRevenue($Million)NetIncome($Million)Liquids(Millionbbl)NaturalGas(Bcf)Liquids(Millionbbl)NaturalGas(Bcf)NetWellsDrilled1ExxonMobil Corp.76,900 333,795 482,295 47,681 625 2,992 166 1,5181,4112Chevron Corp.17,418 232,982 241,909 26,336 536 1,737 151 1,1291,2723ConocoPhillips16,900 117,144 62,004 8,498 271 1,539 120 916 1,1634Occidental Petroleum Corp.12,300 64,210 24,253 4,598201 1129 100 752 1,0165Apache Corp.5,976 60,737 17,078 2,001 145 938 84 685 9586 Anadarko Petroleum Corp. 5,200 52,589 13,411 2,445 115 916 75 565 9517 Hess Corp. 14,775 43,441 38,373 2,063 110 839 61440 8268 Devon Energy Corp. 5,700 43,326 9,502 -206 103 565 57 407 7699 Chesapeake Energy Corp. 12,000 41,611 12,316 -59493 557 49 380 75110 Marathon Oil Corp. 3,367 35,306 16,221 1582 78 470 45 380 69911 EOG Resources Inc. 2,650 27,337 11,683 570 49 416 39 313 51312 Noble Energy Inc. 2,190 17,554 4,223 1027 42 38034 300 49213 Murphy Oil Corp. 9,185 17,523 28,626 971 41 32226 259 46814 Plains Exploration andProduction Co 906 17,298 2,565 343 34 284 25 253 43915Pioneer Natural Resources Co.3,667 13,069 3,228 243 26 259 24 249 36716 Linn Energy LLC 1,136 11,451 1,774 -387 25 253 24 249 33417 Denbury Resources Inc. 1,432 11,139 2,456 525 24249 24 183 31518 Sandridge Energy Inc. 2,510 9,791 2,731 247 24 249 20 161 29719 WPX Energy Inc. 1,200 9,456 3,189 -211 22 244 18160 27120 Continental Resources Inc. 753 9,140 2,573 416 20 183 18 156 263Source: Oil and Gas Journal. “OGJ150 Earnings Downas US Production Climbs.” September 2, 2013. The annualOil and Gas Journal(OGJ) survey, theOGJ150, reports financial and operating results forpublic oil and natural gas companies with domesticreserves and headquarters in the U.S.Notes: The source for employment figures is Hoovers, a D&B Company.2-44

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 162 companies in 2011 ( Oil and Gas Journal , September 2, 2013). 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 2012. 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 61 percent of t he total pipeline mileage and transport about 56 percent of the volume of the ind ustry (Table 2-21). Operating revenues of the2-45

top 20 companies equaled $12.1 billion, representin g 59 percent of the total operating revenues for major and non-major companies. The top 20 compa nies also account for 59 percent of the net income of the industry.

Table 2-21 Performance of Top 20 Gas Pipeline Compa nies (Based on Net Income), 2012

Rank Company Transmission (miles) Vol. trans

for others (MMcf) Operating

Revenue ($000s) Net

Income ($000s)

1 Dominion Transmission Inc. 3,687 653,272 903,4 04 256,010 2 Texas Eastern Transmission LP 9,563 1,747,856 9 56,536 242,277 3 Florida Gas Transmission Co. LLC 5,336 979,857 77 5,375 204,968 4 Transcontinental Gas Pipe Line Co. LLC 9,378 3,27 4,209 1,254,154 194,573 5 Tennessee Gas Pipeline Co. 13,780 2,626,030 1,0 15,928 190,970 6 Columbia Gas Transmission LLC 9,708 1,305,728 813 ,185 186,594 7 Natural Gas Pipeline Co of America 8,911 1,511,84 4 687,366 176,447 8 Southern Natural Gas Co. 7,079 1,005,151 584,82 8 162,275 9 ETC Tiger Pipeline LLC 196 546,137 279,572 134,93 4 10 Northern Natural Gas Co. 14,949 928,977 587,768 134,715 11 Panhandle Eastern Pipe Line Co., LP 6,406 581,92 6 338,787 123,392 12 Texas Gas Transmission LLC 5,880 1,052,070 417 ,809 106,994 13 Kern River Gas Transmission Co. 1,718 928,206 38 3,393 105,447 14 Rockies Express Pipeline LLC 1,698 822,587 786,2 25 103,427 15 CenterPoint Energy Gas Transmission Co., LLC 5,954 1,143,552 437,836 103,290 16 Colorado Interstate Gas Co. 4,253 788,905 397,29 2 100,902 17 Dominion Cove Point LNG, LP 136 82989 281,517 97 ,192 18 Gulf South Pipeline Co., LP 6,484 1,115,618 470, 149 93,816 19 Northern Border Pipeline Co. 1,408 1,008,857 310 ,869 89,767 20 Northwest Pipeline GP 3,906 658,161 437,835 87,1 19 TOTAL FOR TOP 20 120,430 22,761,932 12,119,828 2,8 95,109 TOTAL FOR ALL COMPANIES 198,279 40,759,824 20,545 ,763 4,888,125 Source: Oil and Gas Journal. “US Pipeline Operators Sink Revenue Growth into Expansion.” September 2, 2013.

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 and reports summary information in the publication “The Performance Profiles of Major Energy
Producers”. 14 This information is used in annual report to Congr ess, as well as is released to the

14 The “Performance Profiles of Major Energy Producer s 2009” released on February 25, 2011 is the most r ecent release of this report.2-46

public in aggregate form. While the companies that report information to FRS each year changes,
EIA makes an effort to retain sufficient consistenc y such that trends can be evaluated. For 2009, there are 30 companies in the FRS 15 that accounted for 43 percent of total U.S. crude oil and NGL production, 43 percent of natural gas productio n, 78 percent of U.S. refining capacity, and 0.3 percent of U.S. electricity net generation (U.S . EIA, 2011). Table 2-22 shows a series of financial trends in 2008 dollars selected and aggre gated from FRS firms’ financial statements. The table shows operating revenues and expenses ris ing significantly from 1990 to 2008, with operating income (the difference between operating revenues and expenses) rising until dropping off significantly in 2009. Interest expenses remain ed relatively flat during this period. Meanwhile, recent years have shown that other incom e and income taxes have played a more significant role for the industry. Net income has r isen as well, although 2008 and 2009 saw a decline from previous periods, as oil and natural g as prices declined significantly during the
latter half of 2008.

15 Alenco, Alon USA, Anadarko Petroleum Corporation, Apache Corporation, BP America, Inc., Chalmette, Chesapeake Energy Corporation, Chevron Corporation, CITGO Petroleum Corporation, ConocoPhillips, Devon Energy Corporation, El Paso Corporation, EOG Resour ces, Inc., Equitable Resources, Inc., Exxon Mobil Corporation, Hess Corporation, Hovensa, Lyondell Ch emical Corporation, Marathon Oil Corporation, Motiv a Enterprises, L.L.C., Occidental Petroleum Corporati on, Shell Oil Company, Sunoco, Inc., Tesoro Petrole um Corporation, The Williams Companies, Inc., Total Ho ldings USA, Inc., Valero Energy Corp., Western Refining, WRB Refining LLC, and XTO Energy, Inc.2-47

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 2009 1,136.8 1,085.9 50.8 10.8 18.7 29.5 29.3 Source: Energy Information Administration, Form EIA -28 (Financial Reporting System). * Other Income includes other revenue and expense (excluding inter est expense), discontinued operations, extraordinar y items, and accounting changes. Totals may not sum due to i ndependent rounding.

Table 2-23 shows in percentage terms the estimated return on investments for a variety of business lines, in 1998, 2003, 2008, and 2009 for F RS companies. For U.S. petroleum-related business activities, oil and natural gas production was the most profitable line of business relative to refining/marketing and pipelines, susta ining a return on investment greater than 10 percent in 1998, 2003, and 2008, with a significant decrease in 2009. Returns to foreign oil and natural gas production rose above domestic producti on in 2008 and 2009. Electric power generation and sales emerged in 2008 as a highly pr ofitable line of business for the FRS companies and declined significantly in 2009.2-48

Table 2-23 Return on Investment for Lines of Business (all FRS ), for 1998, 2003, 2008, and 2009 (percent)

Line of Business 1998 2003 2008 2009
Petroleum 10.8 13.4 12.0 4.5 U.S. Petroleum 10 13.7 8.2 0.4 Oil and Natural Gas Production 12.5 16.5 10. 7 3.5 Refining/Marketing 6.6 9.3 2.6 -6.6 Pipelines 6.7 11.5 2.4 4.7 Foreign Petroleum 11.9 13.0 17.8 10.3 Oil and Natural Gas Production 12.5 14.2 16. 3 11 Refining/Marketing 10.6 8.0 26.3 5.8 Downstream Natural Gas* - 8.8 5.1 9.6 Electric Power - 5.2 181.4 -32 Other Energy 7.1 2.8 -2.1 5.1 Non-energy 10.9 2.4 -5.3 2.8 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 sign ificant tax revenues for local, state,
and federal authorities. Table 2-24 shows income an d production tax trends from 1990 to 2009 for FRS companies. The column with U.S. federal, st ate, and local taxes paid or accrued includes
deductions for the U.S. Federal Investment Tax Cred it ($198 million in 2008) 16 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 13 , about 13 percent of the total paid to U.S. author ities.

16 Data was withheld in 2009 to avoid disclosure.2-49

Table 2-24 Income and Production Taxes, 1990-2009 ( Million 2008 Dollars)

Year US Federal, State,

and Local Taxes Paid or Accrued Total Current Total Deferred Total Income

Tax Expense Other

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 2009* -1,655 35,478 -5,988 29,490 -173 Source: Energy Information Administration, Form EIA -28 (Financial Reporting System). *In 2009, data on the U.S. Federal Investment Tax C redit and U.S. State and Local Income Taxes were wi thheld to avoid disclosure.

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-inc ome production taxes paid, which have risen almost three-fold between 1990 and 2008, include wi ndfall profit and severance taxes, as well as other production-related taxes.

2.7 References

Andrews, et al. 2009. Unconventional Gas Shales: Development, Tech nology, and Policy Issues. Congressional Research Service. R40894.
Argonne National Laboratory. 2009. Produced Water V olumes 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.2-50

Independent Petroleum Association of America. 2009. Profile of Independent Producers.<http://www.ipaa.org/wpcontent/uploads/downloads/2011/12/2009ProfileOfInde pendentProducers.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 . “US Pipeline Operators Sink Revenue Growth into E xpansion.” September 2, 2013.

Oil and Gas Journal . “OGJ150 Earnings Down as US Production Climbs.” S eptember 2, 2013.

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. 2013. Modern Shale Gas D evelopment in the United States: An Update. < http://www.netl.doe.gov/File20Library/Res earch/Oil-Gas/shale-gas-primerupdate-2013.pdf> Accessed December 19, 2014.

U.S. Energy Information Administration (U.S. EIA). 2012. Annual Energy Review 2011 (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 3 0, 2011. U.S. Energy Information Administration (U.S. EIA). 2013. Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves 2011. <http://www.eia.doe.gov/oil_gas/natural_gas/data_pu blications/crude_oil_natural_gas_re serves/cr.html> Accessed September 15, 2013.

U.S. Energy Information Administration (U.S. EIA). 2011. Performance Profiles of Major Energy Producers 2009. <http://www.eia.gov/finance/ performanceprofiles> Accessed September 15, 2013.
U.S. Energy Information Administration (U.S. EIA). 2014. Annual Energy Outlook 2014. <http://www.eia.gov/forecasts/aeo/> Accessed March 17, 2014.2-51

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/Oil20and20 NG20Production20and20NG20Tra nsmission_IP.pdf> Accessed December 19, 2014.

U.S. Environmental Protection Agency (U.S. EPA). 20 00. EPA Office of Compliance Sector Notebook Project: Profile of the Oil and Gas Extrac tion Industry. EPA/310-R-99-006. <http://www.epa.gov/compliance/resources/publicatio ns/assistance/sectors/notebooks/oil gas.pdf> Accessed December 19, 2014.

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 (U.S. EPA). 20 12. Regulatory Impact Analysis: Final New Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry. <http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natur al_gas_final_neshap_nsps_ria.pdf> Accessed December 19, 2014.3-1 3 EMISSIONS AND ENGINEERING COSTS

3.1 Introduction

This chapter describes the emissions and engineerin g cost analysis for the proposed NSPS. The first section discusses the emissions poi nts and control options. The following section describes each step in the emissions and engineerin g cost analysis and presents overview results. Detailed tables describing the impacts for each sou rce and option can be found at the end of the chapter. We provide reference to the more-detailed Technical Support Document (TSD) prepared by the EPA for the reader interested in a greater l evel of detail. 17

3.2 Sector Emissions Overview

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 gas industry to provide context for estimated reductions as a result of the proposed ru le. Crude oil and natural gas production sector VOC emissions are approximately 2.8 million tons, a ccording to the 2011 EPA National Emissions Inventory (NEI). The Inventory of U.S. Gr eenhouse Gas Emissions and Sinks: 1990- 2013 (published April 2015) estimates 2013 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries and pet roleum transportation) to be 182 MMt CO 2 Eq. In 2013, total methane emissions from the oil a nd gas industry represented nearly 29 percent
of the total methane emissions from all sources and account for about 3 percent of all CO 2 Eq. emissions in the U.S., with the combined petroleum and natural gas systems being the largest contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2015).

It is important to note that the 2013 GHG emission s estimates do not include methane emissions from hydraulically fractured and re-fract ured oil well completions due to lack of available data when the 2013 GHG Inventory estimate was developed. The estimate in this proposed rule includes an adjustment for hydraulica lly fractured oil wells, and such an adjustment is also being considered as a planned im provement in the 2014 Inventory (to be published April 2016). This adjustment would increa se the 2013 Inventory methane estimate by

17 U.S. EPA. 2015. Oil and Natural Gas Sector: Standa rds of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution. Backgrou nd Technical Support Document for the Proposed Amendments to the New Source Performance Standards.3-2

about 3 MMt CO 2 Eq. The total methane emissions from Petroleum and Natural Gas Systems based on the 2013 GHG Inventory, adjusted for hydra ulically fractured and re-fractured oil well completions, is approximately 185 MMt CO 2 Eq.

3.3 Emissions Points and Pollution Controls assessed in the RIA

A series of emissions controls were evaluated as pa rt of the NSPS review. This section provides a basic description of 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 TSD.

Completions of Hydraulically Fractured and Re-fract ured Oil Wells : Well completion activities include multiple steps after the well bo re hole has reached the target depth. The highest emissions are from venting of natural gas to the at mosphere 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. The TSD separately considers developmental wells and exploratory wells . Developmental wells are wells drilled within known boundaries of a proven oil or gas fiel d, while exploratory or “wildcat” wells are wells drilled in areas of new or unknown potential.

The EPA considered the same two techniques that hav e been proven to reduce emissions from well completions: reduced emissions completion s (RECs) and completion combustion. The use of a REC not only reduces emissions but deliver s natural gas product that would typically be vented to the sales meter. Completion combustion de stroys the organic compounds. Three main technical barriers limit the feasibility of RECs at some wells: proximity of pipelines, pressure of produced gas, and inert gas concentration.

Fugitive Emissions: There are several potential sources of fugitive em issions throughout the oil and natural gas sector. Fugitive emissions occur wh en connection points are not fitted properly or when seals and gaskets start to deteriorate. Cha nges in pressure and pressure or mechanical stresses can also cause components or equipment to leak. Potential sources of fugitive emissions include agitator seals, connectors, pump diaphragms , flanges, instruments, meters, open-ended3-3

lines, pressure relief devices, pump seals, valves or improperly controlled liquid storage tanks. These fugitive emissions do not include devices tha t vent as part of normal operations, such as gas driven pneumatic controllers or gas driven pneu matic pumps.

The TSD considers fugitive emissions from productio n well sites, gathering line and boosting stations, and natural gas transmission/sto rage compressor stations. There are two options for reducing methane and VOC emissions from leaking components: a leak monitoring program based on individual component monitoring us ing EPA Method 21 for leak detection combined with a leak correction, and a leak monitor ing program based on the use of OGI leak
detection combined with leak correction. In additio n, alternative frequencies for fugitive emissions surveys were considered: annual, semiannu al, and quarterly.

Pneumatic controllers : Pneumatic controllers are automated instruments u sed for maintaining a process condition such as liquid level, pressure, p ressure differential, and temperature. In many situations across all segments of the oil and natur al gas industry, pneumatic controllers make use of the available high-pressure natural gas to opera te or control a valve. In these “gas-driven” pneumatic controllers, natural gas may be released with every valve movement and/or continuously from the valve control pilot. Not all pneumatic controllers are gas driven. These “non-gas driven” pneumatic controllers use sources of power other than pressurized natural gas. Examples include solar, electric, and instrument ai r. At oil and gas locations with electrical service, non-gas-driven controllers are typically u sed. Continuous bled pneumatic controllers can be classified into two types based on their emissio ns rates: (1) high-bleed controllers and (2)
low-bleed controllers. A controller is considered t o be high-bleed when the continuous bleed emissions are in excess of 6 standard cubic feet pe r hour (scfh), while low-bleed devices bleed at a rate less than or equal to 6 scfh. The EPA evalua ted the impact of replacing high-bleed
controllers with low-bleed controllers.

Pneumatic pumps : Pneumatic pumps are devices that use gas pressure to drive a fluid by raising or reducing the pressure of the fluid by means of a positive displacement, a piston or set of rotating impellers. Gas powered pneumatic pumps are generally used at oil and natural gas production sites where electricity is not readily a vailable (GRI/EPA, 1996) and can be a significant source of methane and VOC emissions. Pn eumatic chemical and methanol injection3-4

pumps are generally used to pump fairly small volum es of chemicals or methanol into wellbores, surface equipment, and pipelines. Typically, these pumps include plunger pumps with a diaphragm or large piston on the gas end and a smal ler piston on the liquid end to enable a high discharge pressure with a varied but much lower pne umatic supply gas pressure. They are typically used semi-continuously with some seasonal variation. Pneumatic diaphragm pumps are another type used widely in the onshore oil and gas sector to move larger volumes of liquids per unit of time at lower discharge pressures than chem ical and methanol injection pumps. The usage of these pumps is episodic including transferring b ulk liquids such as motor oil, pumping out sumps, and circulation of heat trace medium at well sites in cold climates during winter months.

For both of these types of pumps, emissions occur w hen the gas used in the pump stroke is exhausted to enable liquid filling of the liquid chamber side of the diaphragm. Emissions are a function of the amount of fluid pumped, the pressur e of the pneumatic supply gas, the number of pressure ratio’s between the pneumatic supply gas p ressure and the fluid discharge pressure, and the mechanical inefficiency of the pump. As discuss ed in the white papers, we identified several options for reducing methane and VOC emissions: rep lace natural gas-assisted pump with instrument air pump, replace natural gas-assisted p ump with solar-charged direct current pump (solar pumps), replace natural gas-assisted pump wi th electric pump, and route pneumatic pump
emissions to a control device. The EPA evaluated th e impact of routing pump emissions to a preexisting on-site control device.

Centrifugal and Reciprocating Compressors: Compressors are mechanical devices that increase the pressure of natural gas and allow the natural gas to be transported from the production site, through the supply chain, and to t he consumer. The types of compressors that are used by the oil and gas industry as prime movers ar e reciprocating and centrifugal compressors. Centrifugal compressors use either wet or dry seals

.
Emissions from compressors occur when natural gas l eaks around moving parts in the compressor. In a reciprocating compressor, emission s occur when natural gas leaks around the piston rod when pressurized natural gas is in the c ylinder. Over time, during operation of the compressor, the rod packing system becomes worn and will need to be replaced to prevent excessive leaking from the compression cylinder. Th e potential control options reviewed for3-5

reducing emissions from reciprocating compressors i nclude control techniques that limit the leaking of natural gas past the piston rod packing. This includes replacement of the compressor rod packing, replacement of the piston rod, and the refitting or realignment of the piston rod.

Emissions from centrifugal compressors depend on th e type of seal used: either “wet”, which use oil circulated at high pressure, or “dry” , which use a thin gap of high pressure gas. The use of dry gas seals substantially reduces emission s. In addition, they significantly reduce operating costs and enhance compressor efficiency. Limiting or reducing the emission from the rotating shaft of a centrifugal compressor using a mechanical dry seal system was evaluated. For centrifugal compressors equipped with wet seals, a flare was evaluated as an option for reducing emissions from centrifugal compressors.

3.4 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 to comply with the proposed NSPS. A detailed discussion of the methodology used to esti mate cost impacts is presented in the TSD, which is published in the Docket.

The following sections describe each step in the en gineering cost analysis. First, representative facilities are established for each source category, including baseline emissions and control options. The regulatory alternatives in clude different variations of regulatory requirements considered for inclusion in the propos ed standards. Then, projections are made of the number of incrementally affected facilities for each type of equipment or facility. National
emissions reductions and cost estimates result from multiplying representative factors by the number of affected facilities in each projection ye ar. In addition to emissions reductions, some control options result in natural gas recovery, whi ch can then be combusted for useful processes
or sold. The national cost estimates include estima ted revenue from product recovery where applicable. Finally, national-level cost-effectiven ess is calculated.

3.4.1 Regulatory Options

For each emissions source, point, and control optio n, the TSD develops a representative facility. The characteristics of this facility incl ude typical equipment, operating characteristics,3-6

and representative factors including baseline emiss ions and the costs, emissions reductions, and product recovery resulting from each control option . In this RIA, we examine three broad regulatory options. 18 Table 3-1 shows the emissions sources, points, and controls for the three NSPS regulatory options analyzed in this RIA, which we term Option 1, Option 2, and Option 3. Options 1 and 2 were selected for co-proposal.

18 The EPA also analyzed a variant of proposed Option 2 where only emissions combustion is required for hydraulically fractured and re-fracture oil well co mpletions, rather than require reduced emissions co mpletions (RECs) in combination with combustion. This variati on of the proposed Option 2 would achieve direct em ission reduction that are equivalent to requiring RECs and combustion, but at an approximately $70 million pe r year lower cost. However, as explained in Section VIII.F of the preamble to the proposed NSPS, the EPA dete rmined RECs and combustion to be the best system of emissi ons reduction. Section 4 of the Technical Support Document for the proposal presents the detailed tec hnical analysis of the regulatory options for hydra ulically fractured and re-fractured oil well completions.3-7

Table 3-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS

Emissions Point Emissions Control Option 1 Option 2 (proposed) Option 3
Well Completions and Recompletions Hydraulically Fractured Development Oil Wells REC / Combustion X X X

Hydraulically Fractured Wildcat and Delineation Oil Wells Combustion X X X

Fugitive Emissions Well Pads Monitoring and Maintenance Annual Semiannual Quarterly Gathering and Boosting Stations Monitoring and Maintenance Semiannual Semiannual Quarterly Transmission Compressor Stations Monitoring and Maintenance Semiannual Semiannual Quarterly Pneumatic Pumps Well Pads Route to control X X X Gathering and Boosting Stations Route to control X X X Transmission and Storage Compressor Stations Route to control X X X
Pneumatic Controllers - Natural Gas Transmission and Storage Stations Emissions limit X X X
Reciprocating Compressors Natural Gas Transmission and Storage Stations Annual Monitoring and Maintenance X X X Centrifugal Compressors Natural Gas Transmission and Storage Stations Route to control X X X

The co-proposed Option 2 contains reduced emission completion (REC) and completion combustion requirements for a subset of newly compl eted oil wells that are hydraulically fractured or refractured. Option 2 also requires fu gitive emissions survey and repair programs be performed semiannually (twice per year) at newly dr illed or refractured oil and natural gas well sites, new or modified gathering and boosting stati ons, and new or modified transmission and storage compressor stations. However, low productio n well sites are exempt from the well site fugitive requirements. A low production site is def ined by the average combined oil and natural3-8

gas production for the wells at the site being less than 15 barrels of oil equivalent (boe) per day. 19 Option 2 also requires reductions from centrifugal compressors, reciprocating compressors, pneumatic controllers, and pneumatic pumps througho ut the oil and natural gas source category.

While the EPA is proposing an exclusion from fugiti ve emission requirements for low production well sites, there is uncertainty in how many well sites this exclusion might affect in the future. As a result, the analyses in this RIA p resents a “low” impact case and “high” impact case for fugitive emissions requirements at well si tes. The low impact case excludes from analysis an estimate low production sites, assuming that the fraction of wells meeting the low production criteria in the future will be the same as in 2012 (based on the first month of production data from wells newly completed or modif ied in 2012).The high impact case includes all forecast well sites providing a bounding case w here no newly completed or modified wells meet the low production criteria. Summary results f or option 2, then, are presented as ranges.

Options 1 and 3 differ from the Option 2 with respe ct to the requirements for fugitive emissions. Meanwhile, the co-proposed Option 1 requ ires annual monitoring for well sites, including low production sites, while maintaining s emiannual requirements for others sites. The more stringent Option 3 requires quarterly monitori ng for all sites under the fugitive emissions program, including low production sites. More frequ ent surveys result in higher costs, higher emissions reductions, and increased natural gas rec overy over the co-proposed Option 2.

3.4.2 Projection of Incrementally Affected Facilities

The second step in estimating national costs and em issions impacts of the proposed rule is projecting the number of incrementally affected facilities. Incrementally affected facilities are facilities that would be expected to change their e missions control activities as a result of the proposal. Facilities in states with similar state-l evel requirements are not included within incrementally affected facilities.

The years of analysis are 2020, to represent the fi rst full year of compliance for the proposal, and 2025, to represent impacts of the pro posal over a longer period of time. Affected

19 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels o f crude oil equals 1000 cubic feet natural gas.3-9

facilities are facilities which are new or modified since the effective year of the proposal. In 2020 affected facilities are those which are newly estab lished or modified in 2020. Over time more facilities are newly established or modified in eac h year, and to the extent the facilities remain in operation in future years, the total number of faci lities subject to the NSPS accumulates. In 2025, affected facilities include facilities newly establ ished or modified in 2025, but also facilities which were newly established or modified from 2020 through 2024 and are still operating in
2025.

The EPA has projected affected facilities using a c ombination of historical data from the U.S. GHG Inventory, and projected activity levels, taken from the Energy Information Administration (EIA’s) Annual Energy Outlook (AEO). The EPA derived typical counts for new compressors, pneumatic controllers, and pneumatic p umps by averaging the year-to-year increases over the past ten years in the Inventory. New and modified hydraulically fractured oil well completions and well sites are based on projec tions and growth rates consistent with the drilling activity in the 2014 Annual Energy Outlook

.
The 2014 Annual Energy Outlook was the most recent projection available at the time that the analysis underlying this RIA was being pre pared. However, since then the 2015 Annual Energy Outlook has been released by the U.S. Energy Information Administration. The 2015 AEO reflects that growth in U.S. crude oil producti on over the last two years, along with the late2014 drop in global crude oil prices, have altered the economics of the oil market. In comparison to 2014 AEO reference case, the 2015 AEO reference case shows higher crude oil production (in 2025, 18 percent higher in 2015 AEO), slightly lowe r natural gas production (in 2025, about 4 percent lower in 2015 AEO15), lower Brent spot and West Texas Intermediate crude oil prices,
and lower total wells drilled in the lower 48 state s (in 2025, about 20 percent lower in 2015 AEO). If this RIA were updated to reflect the lower drilling activity in 2015 AEO, then the
national costs and emissions reductions of the oil well completions and well site fugitives provisions of the rule would likely be reduced. Cos ts and emissions reductions per facility would not be affected, however.

We also reviewed state regulations and permitting r equirements, which require mitigation measures for many emission sources in the oil and n atural gas sector. State regulations in3-10

Colorado and Wyoming both require RECs for hydrauli cally fractured oil and gas wells. Sources in Colorado, Wyoming, Utah, and Ohio are subject to fugitive emissions requirements. Applicable facilities in these states are not inclu ded in the estimates of incrementally affected facilities presented in the RIA, as sources in thos e states are already subject to similar requirements to the federal standards. A more detai led discussion on the derivation of the baseline for the current proposal is presented for each emissions source is the TSD. The estimated counts of hydraulically-fractured and re- fracture oil well completions also account for the wells anticipated to be excluded from the propo sed NSPS requirements because of a gas-tooil ratio (GOR) of 300 or below.

Table 3-2 Number of Incrementally Affected Sources for the NSPS

Emissions Sources Incrementally Affected Sources
2020 2025 1 Hydraulically Fractured and Re-fractured Oil Well C ompletions 15,000 15,000 Fugitive Emissions 2 14,000 to 22,000 86,000 to 140,000 Pneumatic Pumps 3,000 18,000 Compressors 68 410 Pneumatic Controllers 210 1,300 Total 2 31,000 to 40,000 120,000 to 180,000

1 In addition to newly affected sources in 2025, incr ementally affected sources in 2025 include sources that become affected in the 2020-24 time period and are assumed to be in continued operation in 2025.
2 The low end of the range in the fugitive emissions and total rows reflect the number of incrementally affected sources under the low impact co-proposed Option 2, which excludes low production well sites. Table 3-2 presents the estimates of the number of i ncrementally affected sources for this proposal after accounting for state regulations as described above. Note that hydraulically fractured and re-fractured oil well completions do not grow significantly from 2020 to 2025, while other sources do. This is a result of complet ions being a one-time activity in a given year,
while other sources are affected and remain affecte d as they continue to operate, thus these
sources accumulate over time. The estimates for tha t hydraulically fractured and re-fractured oil well completions and fugitive emissions at well sit es (a large fraction of the incrementally affected sources under the proposed rule fugitive e missions provisions) include both new and
modified sources. The estimates for other sources a re based upon projections of new sources alone. While some of these sources, particularly pn eumatic pumps and controllers, are likely to be predominantly new sources, the impact estimates may be under-estimated by the under-3-11

represented modified sources. In the preamble to th e proposed rule, the EPA solicits comments on these projection methods as well as solicits inf ormation that would improve our estimate of
the turnover rates or rates of modification of rele vant sources, as well as the number of wells on
well sites.

3.4.3 Emissions Reductions

Table 3-3 summarizes the national emissions reducti ons for the evaluated NSPS emissions sources and points for 2020 and 2025. The se reductions are estimated by multiplying
the unit-level emissions reductions associated with each applicable control and facility type by the number of incrementally affected sources. Table 3-1 summarizes the applicable controls, and Table 3-2 summarizes the affected facilities, aggre gating multiple model plant types within each source category (e.g., oil well completions combine development and exploratory wells). The detailed description of emissions controls is provi ded in the TSD. Please note that all results have been rounded to two significant digits.

Table 3-3 Emissions Reductions for Proposed NSPS Op tion 2, 2020 and 2025

Source/Emissions Point Emissions Reductions, 2020

Methane (short tons) VOC

(short tons) HAP

(short tons) Methane

(metric tons CO 2 Eq.) Oil Well Completions and Recompletions 140,000 110,000 14 63,100,000 Fugitive Emissions 24,000 to 33,000 6,200 to 8,700 230 to 330 740,000 to 750,000 Pneumatic Pumps 5,400 1,500 57 120,000 Compressors 1,600 43 1 36,000 Pneumatic Controllers 590 16 0 13,000 Total 170,000 to 180,000 120,000 310 to 400 3,800,0 00 to 4,000,000

Source/Emissions Point Emissions Reductions, 2025

Methane (short tons) VOC

(short tons) HAP

(short tons) Methane

(metric tons CO 2 Eq.) Oil Well Completions and Recompletions 140,000 120,000 14 3,100,000 Fugitive Emissions 150,000 to 210,000 40,000 to 57, 000 1,500 to 2,200 3,500,000 to 4,900,000 Pneumatic Pumps 32,000 9,000 340 740,000 Compressors 9,400 260 8 210,000 Pneumatic Controllers 3,500 97 3 80,000 Total 340,000 to 400,000 170,000 to 180,000 2,200 t o 2,500 7,700,000 to 9,000,0003-12

3.4.4 Product Recovery

The annualized cost estimates presented below inclu de revenue from additional natural gas recovery in the production and processing segme nts. Several emission controls for the NSPS capture methane and VOC emissions that otherwise wo uld be vented to the atmosphere. A large proportion of the averted methane emissions can be directed into natural gas production streams
and sold. For environmental controls that avert the emission of saleable natural gas, we base the estimated revenues from averted natural gas emissio ns on an estimate of the amount of natural gas that would not be emitted during one year for t he control.

The standards that result in natural gas recovery a re: RECs at hydraulically fractured oil wells, fugitive emissions monitoring and repair, ro d packing replacement in reciprocating compressors, and low-bleed pneumatic devices. The p roposed requirements for completions at exploration and delineation wells, pneumatic pumps, and centrifugal compressors do not result in natural gas recovery. In some of these cases, alter native control strategies do result in natural gas recovery, but these alternative controls were not a ssumed as part of this analysis. For example, alternatives to routing pneumatic pump emissions to a control device include substituting a solar or electric pump where a gas-driven pump would have otherwise been used.

Table 3-5 summarizes natural gas recovery and reven ue included in annualized cost calculations. When including the additional natural gas recovery in the cost analysis, we assume that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the wellhead. The Energy Information Administration’s 2014 Annual Energy Outlook forecasted wellhead prices paid to lower 48 state producers to be $4.46 /Mcf in 2020 and $5.06/Mcf in 2025. The $4/Mcf price assumed in this RIA is intended to ref lect the AEO estimate but simultaneously be conservatively low.

Natural gas recovery at any point in the system pro vide benefits to the energy system and to the public. However, due to contractual arrangem ents, transmission and storage companies do not always benefit from lowering the leak rate of t heir operations because they do not necessarily own the gas, and fixed loss rates are included in l ong-term contracts. As a result, the EPA excludes revenue from natural gas recovery in estim ating compliance costs for the transmission and storage segment. This approach likely overestim ates the long-term compliance cost of the3-13

controls.

Table 3-4 Estimated Natural Gas Recovery (Mcf) for Proposed NSPS Option 2 in 2020 and 2025

Source/Emissions Point 2020 2025

Gas recovery (Mcf) Revenue from

recovery (millions 2012$) Gas recovery (Mcf) Revenue from

recovery (millions 2012$) Oil Well Completions and Recompletions 6,200,000 $25 6,200,000 $25
Fugitive Emissions 1,400,000 to 1,900,000 $5.1 to $7.3 8,900,000 to 12,000,000 $33 to $47 Pneumatic Pumps 0 $0 0 $0 Compressors 76,000 $0 450,000 $0 Pneumatic Controllers 30,000 $0 180,000 $0
Total 7,700,000 to 8,200,000 $30 to $32 16,000,000 to 19,000,000 $58 to $72

As natural gas prices can increase or decrease rapi dly, the estimated engineering compliance costs can vary when revenue from additio nal natural gas recovery is included. There is also geographic variability in wellhead prices, which can also influence estimated engineering costs. For the proposed option, a $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $8 million in 2020 and $16 to $19 million in 2025, in 2012 dollars.

3.4.5 Engineering Compliance Costs

Table 3-6 summarizes the capital and annualized cos ts for the evaluated emissions sources and points. The detailed description of cos ts estimates is provided in TSD. To estimate total annualized engineering compliance costs, we a dded the annualized costs of each item without accounting for different expected lifetimes . This approach is mathematically equivalent to establishing an overall, representative project time horizon and annualizing costs after consideration of control options that would need to be replaced periodically within the given
time horizon.3-14

Table 3-5 Engineering Compliance Cost Estimates for Proposed NSPS Option 2 in 2020 and 2025 (millions 2012$)

Source/Emissions Point Compliance Costs, 2020 Compliance Costs, 2025 Capital Costs (2012$) Nationwide

Annualized Costs (2012$) Capital Costs (2012$) Nationwide

Annualized Costs (2012$) Oil Well Completions and Recompletions $150 $120 $ 150 $120 Fugitive Emissions $15 to $22 $29 to $47 $95 to $1 40 $180 to $290 Pneumatic Pumps $5.9 $0.84 $36.0 $5.1 Compressors $0.54 $0.25 $3.2 $1.5 Pneumatic Controllers $0.048 $0.0052 $0.29 $0.031 Reporting and Recordkeeping $0.0 $1.4 $0.0 $4.1 Total $170 to180 $150 to $170 $280 to $330 $320 to $420

Engineering capital costs were annualized using a 7 percent interest rate. Section 3.4 provides a comparison to using a 3 percent interest rate. Different emissions control options were annualized using expected lifetimes that were deter mined to be most appropriate for individual options. 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)

• Fugitive emissions monitoring program design: 8 yea rs

• Reciprocating compressors rod packing: 3.8 – 4.4 years

• Centrifugal compressors, pneumatic controllers, and pneumatic pumps: 10 years
Reporting and recordkeeping costs were drawn from t he information collection requirements (ICR) in this proposed rule that have been submitte d for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act (see Chapter 5 for more detail). The 2020 reporting and recordkeeping costs in this RIA ($1.4 million) are based on the first year ICR cost estimates. Meanwhile, we drew upon the first y ear cost in the ICR cost estimates ($4.1 million) and applied that cost to 2025 in this RIA.

3.4.6 Cost-Effectiveness

This section summarizes the cost-effectiveness of t he proposed standards for each source in 2020 and 2025. The proposed NSPS includes standa rds for both methane and VOC reductions.3-15

As discussed in the preamble to this action, cost-e ffectiveness analysis allows comparisons of relative costs and outcomes (effects) of two or mor e options. In general, cost-effectiveness is a measure of the benefit produced by resources spent. In the context of air pollution control options, cost-effectiveness typically refers to the annualized cost of implementing an air pollution control option divided by the amount of p ollutant reductions realized annually. A costeffectiveness analysis is not intended to constitut e or approximate a cost-benefits analysis but rather provides a metric of the relative cost to re duction ratios of various control options.

The estimation and interpretation of cost-effective ness values is relatively straightforward when an abatement measure controls a single polluta nt. Increasingly, however, air pollution reduction programs require reductions in emissions of multiple pollutants, and in such programs multipollutant controls may be employed. Consequent ly, there is a need for determining costeffectiveness for a control option across multiple pollutants (or classes of multiple pollutants). This is the case for the current proposal where the EPA is proposing to directly regulate both
methane and VOC.

To assign the entire annualized cost to the reducti on in emissions of a single pollutant reduced by the multipollutant control option is app ropriate when reductions of the other pollutants are considered to cobenefits with no cos t. However, under the current proposal, methane and VOCs are both directly regulated; there fore, reductions of each pollutant must be properly considered benefits, not co-benefits, and consideration of only one of the regulated pollutants is not appropriate.

Alternatively, all annualized costs can be allocate d to each of the pollutant emission reductions addressed by the multipollutant control option. Unlike the approach above, no emission reduction is treated as a co-benefit; each emission reduction is assessed based on the full cost of the control. However, this approach, w hich is often used for assessing singlepollutant controls, evaluates emission reduction of each pollutant separately, assuming that each bears the entire cost, and thus inflates the contro l cost in the multiple of the number of additional pollutants being reduced. This approach therefore o ver-estimates the cost of obtaining emissions reductions with a multipollutant control as it does not recognize the simultaneity of the reductions achieved by the application of the contr ol option. Another approach allocates the3-16

annualized cost to the sum of the individual pollut ant emission reductions addressed by the multipollutant control option. The multipollutant c ost-effectiveness approach may be appropriate when each of the pollutant reductions is similar in value or impact. However, in the current proposal, methane and VOC have quite different heal th and environmental impacts, and therefore summing the pollutants to derive the deno minator of the cost-effectiveness equation (i.e., assuming a ton of methane is equivalent in i ts impacts to a ton of VOC) is inappropriate.

For purposes of this proposal, we have identified a nd are proposing to use two approaches for considering the cost of reducing emi ssions from multiple pollutants using one control. One approach is to assign all costs to the emission reduction of one pollutant and zero to all other concurrent reductions; if the cost is rea sonable for reducing any of the targeted emissions alone, the cost of such control is clearl y reasonable for the concurrent emission reduction of all the other pollutants because they are being reduced at no additional cost. While this approach assigns all costs to only a portion o f the emission reduction, it does not overstate the cost. It also does not require unreasonable ass umptions about the equivalency of the impacts
between a ton of methane and VOC emission reduction , which is not appropriate as discussed in the option immediately above. In addition, this app roach is simple and straight forward in application. If the multipollutant control is cost effective for reducing emissions of either of the targeted pollutant, it is clearly cost effective fo r reducing all other targeted emissions that are being achieved simultaneously.

A second approach, which we term a “multipollutant cost-effectiveness” approach, apportions the annualized cost across the pollutant reductions addressed by the control option in proportion to the relative percentage reduction of each pollutant controlled by mass. For example, in this proposal both methane and VOC emis sions are reduced in equal proportion by the multipollutant control option. As a result, hal f of the control costs are allocated to methane, the other half to VOC. This approach similarly does not inflate the control cost nor requires unreasonable assumptions about the equivalency of t he impacts between a ton of methane and
VOC emission reduction.

We believe that both approaches discussed above are appropriate for assessing the reasonableness of the multipollutant controls consi dered in this action. As such, in our analyses3-17

below, if a device is cost effective under either o f these two approaches, we find it to be cost effective. The EPA recognize, however, not all situ ations where multipollutant controls are applied are the same, and that other approaches, in cluding those described above as inappropriate for this action, might be appropriate in other inst ances.
Under the single pollutant cost-effectiveness appro ach, the total national compliance costs are divided by the emissions reductions for m ethane and VOC separately (Table 3-6). This approach does not account for the combined emission s reductions of both pollutants. We only present the cost-effectiveness for the high impact case for fugitive emissions requirements at well sites. The low impact case would show lower do llar per ton estimates.

Table 3-6 Single Pollutant Approach to Engineering Compliance Cost-Effectiveness Estimates in 2020 and 2025 for Proposed NSPS Option 2 (High Impact Case for Well Site Fugitive Emissions Requirements)

Source/ Emissions Point Cost-Effectiveness, 2020 (2012$) Cost-Effectiveness, 2025 (2012$)

Methane ($/short ton) VOC

($/short ton) Methane

($/metric ton CO 2 Eq.) Methane

($/short ton) VOC

($/short ton) Methane

($/metric ton CO 2 Eq.) Oil Well Completions $910 $1,100 $40 $900 $1,100 $39 Fugitive Emissions $1,400 $5,300 $62 $1,400 $5,10 0 $60 Pneumatic Pumps $160 $560 $7 $160 $560 $7 Compressors $160 $5,600 $7 $160 $5,600 $7
Pneumatic Controllers $9 $320 $0 $9 $320 $0

Total $980 $1,400 $43 $1,100 $2,300 $47

For the multipollutant cost-effectiveness approach, costs are allocated proportionally to methane and VOC reductions based on the percent red uction achieved in each pollutant (Table 3- 7). Because the relevant oil and gas controls reduc e methane and VOC in equal proportion, 50 percent of costs are allocated to each emission.3-18

Table 3-7 Multipollutant Approach to Engineering Co mpliance Cost-Effectiveness Estimates for Proposed NSPS Option 2 in 2020 and 20 25 (High Impact Case for Well Site Fugitive Emissions Requirements)

Source/ Emissions Point Cost-Effectiveness, 2020 (2012$) Cost-Effectiveness, 2025 (2012$)

Methane ($/short ton) VOC

($/short ton) Methane

($/metric ton CO 2 Eq.) Methane

($/short ton) VOC

($/short ton) Methane

($/metric ton CO 2 Eq.) Oil Well Completions $450 $540 $20 $450 $530 $20 Fugitive Emissions $710 $2,700 $31 $680 $2,500 $3 0 Pneumatic Pumps $78 $280 $3 $78 $280 $3 Compressors $78 $2,800 $3 $78 $2,800 $3 Pneumatic Controllers $5 $160 $0 $5 $160 $0 Total $490 $690 $22 $530 $1,200 $24

3.4.7 Comparison of Regulatory Alternatives

Table 3-8 presents a comparison of the regulatory a lternatives through each step of the emissions analysis in 2020 and 2025. 20 The requirements between the options vary with res pect to the fugitive emissions requirements. Option 1 in cludes requirements for annual fugitive emissions surveys at well sites but semiannual freq uency at other sites, and Option 3 includes requirements for quarterly fugitive emissions surve ys, as opposed the semiannual requirement in Options 2. Annual, semiannual, and quarterly fugiti ve emissions surveys are assumed to result in respective reductions in emissions of 40 percent, 6 0 percent, and 80 percent, but affect the same number of sources. Natural gas recovery also varies as a result of survey frequency. Variation in natural gas recovery, capital and annualized costs reflect these differences in the number of affected facilities and frequency of fugitive emiss ions surveys.

20 The EPA also analyzed a variant of proposed Option 2 where only emissions combustion is required for hydraulically fractured and re-fracture oil well co mpletions, rather than require reduced emissions co mpletions in combination with combustion (RECs). This variation of the proposed Option 2 would achieve direct emiss ion reduction that are equivalent to requiring RECs and combustion, but at an approximately $70 million pe r year lower cost. However, as explained in Section VIII.F of the preamble to the proposed NSPS, the EPA dete rmined RECs and combustion to be the best system of emissi ons reduction. Section 4 of the Technical Support Document for the proposal presents the detailed tec hnical analysis of the regulatory options for hydra ulically fractured and re-fractured oil well completions.3-19

Table 3-8 Comparison of Regulatory Alternatives Regulatory Alternative

Option 1 Option 2 (proposed) Option 3 Impacts in 2020 Affected Sources 40,000 31,000 to 40,000 40,000 Emissions Reductions Methane Emissions Reduction (short tons/year) 170,000 170,000 to 180,000 190,000 VOC Emissions Reduction (short tons/year) 120,000 120,000 130,000 Natural Gas Recovery (Mcf) 7,700,000 7,700,000 to 8 ,200,000 8,800,000 Compliance Costs Capital Costs (2012$) $180,000,000 $170,000,000 to $180,000,000 $180,000,000 Annualized Costs (2012$) $150,000,000 $150,000,000 to $170,000,000 $210,000,000 Cost-Effectiveness (Single Pollutant Approach) 1 Methane (2012$ / short ton) $920 $920 to $980 $1,1 00 VOC (2012$ / short ton) $1,300 $1,300 to $1,400 $1 ,700 Cost-Effectiveness (Multipollutant Approach) 1 Methane (2012$ / short ton) $460 $460 to $490 $570 VOC (2012$ / short ton) $630 $640 to $690 $840

Impacts in 2025 Affected Sources 180,000 120,000 to 180,000 180,000 Emissions Reductions Methane Emissions Reduction (short tons/year) 340,000 340,000 to 400,000 470,000 VOC Emissions Reduction (short tons/year) 170,000 170,000 to 180,000 200,000 Natural Gas Recovery (Mcf) 16,000,000 16,000,000 to 19,000,000 23,000,000 Compliance Costs Capital Costs (2012$) $330,000,000 $280,000,000 to $330,000,000 $330,000,000 Annualized Costs (2012$) $310,000,000 $320,000,000 to $420,000,000 $680,000,000 Cost-Effectiveness (Single Pollutant Approach) 1 Methane (2012$ / short ton) $920 $940 to $1,100 $1 ,400 VOC (2012$ / short ton) $1,900 $1,900 to $2,300 $3 ,400 Cost-Effectiveness (Multipollutant Approach) 1 Methane (2012$ / short ton) $460 $470 to $530 $720 VOC (2012$ / short ton) $940 $960 to $1,200 $1,70 0

1 Cost-effectiveness based on high impact case for we ll site fugitive emissions requirements.3-20

3.4.8 Capital and Annualized Compliance Costs Compared to Industry-level Capital Expenditures and Revenues
In order to provide another perspective on the reas onableness of the estimated cost of control as determined in our evaluation of "Best Sy stem of Emission Reduction" (BSER) for the proposed standards, we analyzed the total cost of t he rule for each type of affected facility under two additional approaches using industry economic d ata. First, we compared the total nationwide capitals co sts that would be incurred for each type of affected facility to comply with the propos ed standards to the industry’s estimated new annual capital expenditures. This analysis allowed us to compare the capital costs that would be incurred to comply with the proposed standards to t he level of new capital expenditures that the industry is incurring in the absence of the propose d standards. Capital expenditure data for relevant NAICS codes covered by the rule were obtai ned from the U.S. Census 2013 Annual Capital Expenditures Survey 21 . For the capital expenditures analysis, we determi ned the estimated nationwide capital costs incurred by each type of affected facility to comply with the proposed standards, then divided the nationwide cap ital costs by the new capital expenditures (Census data) for the appropriate NAICS code(s) to determine the percentage that the nationwide capital costs represent of the capital expenditures . For example, we used the total estimated capital cost (nationwide) for hydraulically fractur ed development oil well completions and compared that to the total capital expenditures the NAICs codes that correspond to oil and natural gas production segment. Table 3-9 below sum marizes the capital expenditure data used for our analysis.
Table 3-9 NAICS-Based Capital Expenditure Data

Oil and Natural Gas Segment NAICS Code NAICS Description Total New Expenditures (millions, current $)

Production 2111 Crude Petroleum and Natural Gas Extraction $158,911

213111, 213112 Support Activities for Oil and Gas Operations $19,966

Transmission and Storage 4862 Pipeline transportation of natural gas $12,891

21 Capital Expenditures for Structures and Equipment for Companies With Employees by Industry: 2013, Tab le 4a. See http://www.census.gov/econ/aces/xls/2013/full_r eport.html3-21

For fugitive emissions standards at well sites and compressor stations, there are no actual capital cost identified in the TSD. First year cost s, which are corporate-based costs for these standards are factored into the annual costs; howev er, these first year costs are not actual capital costs and we therefore, determined that comparison of these costs to industry capital expenditures would be inappropriate.
In the second approach, we compared the annualized costs that would be incurred to comply with the standards to the industry’s estimat ed annual revenues. This analysis allowed us determine whether the annualized costs appear reaso nable as a percentage of the revenues being generated by the industry. The annualized costs, as calculated for the rule, include capital cost annualized using a seven percent discount rate plus any annually incurred cost for implementation of a control technology. We used ann ual costs without savings from natural gas recovery in order to present the highest costs. The annual revenue data for relevant NAICS codes were obtained from the U.S. Census 2012 County Busi ness Patterns and 2012 Economic
Census 22 . For the annual revenues analysis, we determined t he estimated nationwide annualize costs incurred by each type of affected facility to comply with the proposed standards, then divided the nationwide annualized costs by the annu al revenues (Census data) for the appropriate NAICS code(s) to determine the percentage that the nationwide annualized costs represent of annual revenues. For example, we used the total ann ual cost (nationwide) for hydraulically fractured development oil well completions and comp ared that to the total receipts for the NAICs codes that correspond to oil and natural gas produc tion segment. Table 3-10 below summarizes the revenue data used for our analysis.

Table 3-10 NAICS-Based Revenue Data

Oil and Natural Gas Segment NAICS Code NAICS Description Estimated Receipts (millions 2012$)

Production 211111 Crude Petroleum and Natural Gas Extraction $ 276,077 213112 Support Activities for Oil and Gas Operation s $90,646 Processing 211112 Natural Gas Liquid Extraction $49 ,236 Transmission and Storage 486210 Pipeline Transporta tion of Natural Gas $26,587

22 Number of Firms, Number of Establishments, Employm ent, Annual Payroll, and Estimated Receipts by Ente rprise Employment Size for the United States, All Industri es: 2012. Release date: 6/22/2015. 2012 County Bus iness Patterns and 2012 Economic Census. For information on confidentiality protection, sampling error, and nonsampling error, see http://www.census.gov/econ/susb/methodology.html . For definitions of estimated receipts and other definitions, see http://www.census.gov/ec on/susb/definitions.html.3-22

For the capital expenditures, the production segmen t was represented with the NAICS
codes 21111 " Crude Petroleum and Natural Gas Extraction" and 213 111 and 213112 " Support Activities for Oil and Gas Operations". The transmi ssion and storage segment was represented with the NAICS code 4862 "Pipeline transportation o f natural gas". For revenue, the production segment was represented with the NAICS codes 21111 " Crude Petroleum and Natural Gas
Extraction" and 213112 " Support Activities for Oil and Gas Operations". The transmission and storage segment was represented with the NAICS code 486210 "Pipeline Transportation of Natural Gas". Although there is not a one-to-one co rrespondence between NAICS codes and the industry segments we used in the development of the analysis, we believe there is enough similarity to draw accurate conclusions.
Because we are aware that different owners or opera tors are generally involved in the different industry segments, we conducted the analy sis at the affected facility level to ensure proper characterization of the impact. We also cond ucted the analysis for all sources in the production segment and in the transmission and stor age segment. Table 3-11 summarizes the result of our analysis. In all cases we found that the impacts of the proposed rule in comparison to either capital expenditures or revenues represen t a fraction of one percent.3-23

Table 3-11 Comparison of Proposed NSPS Nationwide C ost by Affected Facility Cost to Industry-wide Capital Expenditures and Revenues

Oil and Natural Gas Segment/ Number of Sources Subject to NSPS Total

Nationwide Capital Costs (millions 2012$) Total

Nationwide Annual Cost (millions 2012$) Nationwide

Capital Cost / Capital Expenditur es (%) Nationwide

Annual Cost / Receipts (%) Affected Facility Production Hydraulically Fractured Oil Well Completions and Re completions - Development Oil Wells 13,804 $144 $144 0.08% 0.03% - Exploratory/Delineation Oil Wells 1,166 $4 $4 0.00% 0.00% Gas-Driven Pumps 17,760 $36 $5 0.02% 0.00% Fugitives - Well Sites 138,568 NA $310 NA 0.09% Total Production Segment 171,298 $184 $464 0.10% 0.13% Transmission and Storage Compressors - Reciprocating 402 $2.80 $0.79 0.02% 0.00% - Centrifugal 6 $0.14 $0.02 0.01% 0.00% Pneumatic Controllers 1,260 $0.29 $0.03 0.00% 0.0 0% Fugitives - Compressor Stations 1,680 NA $27 NA 0. 10% Total Transmission and Storage Segment 3,348 $3 $28 0.03% 0.11%

Source : All cost information is from the "Oil and Natural Gas Sector: Standards of Performance for Cr ude Oil and Natural Gas Production, Transmission and Distributi on, Background Technical Support Document for the P roposed New Source Performance Standards, 40 CFR Part 60, s ubpart OOOOa" available in the docket. For Hydrauli cally Fractured Oil Well Completions and Recompletions fr om Table 4-8, for Gas Driven Pumps from Table 7-19, for Fugitives - Well sites from Table 5-31, for Compres sors, Reciprocating from Table 8-13,for Centrifuga l from Table8-14, for Pneumatic controllers from- Table 6- 9, and for Fugitives - Compressor Stations from Tab le 5-31.3-24

3.5 Compliance Costs Estimated using 3 and 7 Percent Di scount Rates

Table 3-9 shows that the choice of discount rate ha s very minor effects on the nationwide annualized costs of the proposed option.

Table 3-12 Annualized Costs using 3 and 7 Percent D iscount Rates for Proposed NSPS Option 2 in 2020 and 2025 (millions 2012$)

Nationwide Annualized Costs, 2020 (2012$) Nationwide Annualized Costs, 2025 (2012$)
7 percent 3 percent 7 percent 3 percent Oil Well Completions and Recompletions $120 $120 $ 120 $120 Fugitive Emissions $29 to $47 $29 to $46 $180 to 2 90 $180 to $290 Pneumatic Pumps $0.84 $0.69 $5.1 $4.2 Compressors $0.25 $0.23 $1.5 $1.4 Pneumatic Controllers $0.0052 $0.0040 $0.031 $0.02 4 Reporting and Recordkeeping $1.4 $1.4 $4.1 $4.1 Total $150 to $170 $150 to $170 $320 to $420 $3 10 to $420

The choice of discount rate has a small effect on n ationwide annualized costs. The compliance costs related to oil well completions an d fugitive emissions surveys occur in each year, so the interest rate has little impact on ann ualized costs for these sources. The annualized costs for pneumatic pumps, compressors, and pneumat ic controllers are sensitive to interest rate, but these constitute a relatively small part of the total compliance cost estimates for the proposal.

3.6 Detailed Impacts Tables
The following tables shows the full details of the costs and emissions reduction by emissions sources for each regulatory option in 202 0 and 2025.3-25Table 3-13 Incrementally Affected Units, EmissionsReductions and Costs, Option 1, 2020Source/Emissions PointIncrementallyAffectedUnitsNationwide Emissions Reductions National Costs(2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and Delineation OilWells870 8,000 6,700 1 180,000 $3,200,000 $3,200,000Fugitive EmissionsWell Pads22,000 17,000 4,800 180 390,000 $18,000,000 $25,000,000Gathering and BoostingStations260 5,500 1,500 57 120,000 $4,200,000 $2,800,000Transmission CompressorStations21 1,700 47 1 39,000 $340,000 $440,000Pneumatic PumpsWell Pads3,000 5,400 1,500 57 120,000 $5,900,000 $840,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations67 1,500 40 1 33,000 $470,000 $130,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations1 110 3 0 2,500 $72,000 $110,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations210 590 16 0 13,000 $48,000 $5,200Reporting and RecordkeepingAll 0 0 0 0 $0 $1,400,000TOTAL 40,000 170,000 120,000 310 3,800,000 $180,000,000 $150,000,0003-26Table 3-14 Incrementally Affected Units, EmissionsReductions and Costs, Option 1, 2025Source/Emissions PointIncrementallyAffected UnitsNationwide Emissions Reductions National Costs(2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and DelineationOil Wells1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000Fugitive EmissionsWell Pads140,000 110,000 32,000 1,200 2,600,000 $110,000,000 $160,000,000Gathering and BoostingStations1,600 33,000 9,100 340 740,000 $25,000,000 $17,000,000Transmission CompressorStations130 10,000 280 8 230,000 $2,100,000 $2,600,000Pneumatic PumpsWell Pads18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations400 8,800 240 7 200,000 $2,800,000 $790,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations6 670 18 1 15,000 $430,000 $680,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations1,300 3,500 97 3 80,000 $290,000 $31,000Reporting and RecordkeepingAll 0 0 0 0 $0 $4,100,000TOTAL180,000340,000170,0001,9007,700,000$330,000,000$310,000,0003-27Table 3-15 Incrementally Affected Units, EmissionsReductions and Costs, Proposed Option 2, Low ImpactCase, 2020Source/Emissions PointIncrementallyAffected UnitsNationwide Emissions Reductions National Costs(2012$)Methane (shorttons)VOC(short tons)HAP (shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and Delineation OilWells870 8,000 6,700 1 180,000 $3,200,000 $3,200,000Fugitive EmissionsWell Pads13,000 17,000 4,600 180 380,000 $11,000,000 $26,000,000Gathering and BoostingStations260 5,500 1,500 57 120,000 $4,200,000 $2,800,000Transmission CompressorStations21 1,700 47 1 39,000 $340,000 $440,000Pneumatic PumpsWell Pads3,000 5,400 1,500 57 120,000 $5,900,000 $840,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations67 1,500 40 1 33,000 $470,000 $130,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations1 110 3 0 2,500 $72,000 $110,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations210 590 16 0 13,000 $48,000 $5,200Reporting and RecordkeepingAll 0 0 0 0 $0 $1,400,000TOTAL 31,000 170,000 120,000 310 3,800,000 $170,000,000 $150,000,0003-28Table 3-16 Incrementally Affected Units, EmissionsReductions and Costs, Proposed Option 2, Low ImpactCase, 2025Source/Emissions PointIncrementallyAffected UnitsNationwide Emissions Reductions National Costs (2012$)Methane(short tons)VOC(short tons) HAP (short tons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs WithAddl. RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and DelineationOil Wells1,20011,000 9,000 1 240,000 $4,300,000 $4,300,000Fugitive EmissionsWell Pads84,000110,000 31,000 1,200 2,500,000 $68,000,000 $160,000,000Gathering and BoostingStations1,60033,000 9,100 340 740,000 $25,000,000 $17,000,000Transmission CompressorStations13010,000 280 8 230,000 $2,100,000 $2,600,000Pneumatic PumpsWell Pads18,00032,000 9,000 340 740,000 $36,000,000 $5,100,000Gathering and BoostingStations00 0 0 0 $0 $0Transmission and StorageCompressor Stations00 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations4008,800 240 7 200,000 $2,800,000 $790,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations6670 18 1 15,000 $430,000 $680,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations1,300 3,500 97 3 80,000 $290,000 $31,000Reporting and RecordkeepingAll0 0 0 0 $0 $4,100,000TOTAL 120,000340,000 170,000 1,900 7,700,000 $280,000,000 $320,000,0003-29Table 3-17 Incrementally Affected Units, EmissionsReductions and Costs, Proposed Option 2, High Impact Case, 2020Source/Emissions PointIncrementallyAffectedUnitsNationwide Emissions Reductions National Costs(2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and Delineation OilWells870 8,000 6,700 1 180,000 $3,200,000 $3,200,000Fugitive EmissionsWell Pads22,000 26,000 7,200 270 590,000 $18,000,000 $43,000,000Gathering and BoostingStations260 5,500 1,500 57 120,000 $4,200,000 $2,800,000Transmission CompressorStations21 1,700 47 1 39,000 $340,000 $440,000Pneumatic PumpsWell Pads3,000 5,400 1,500 57 120,000 $5,900,000 $840,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations67 1,500 40 1 33,000 $470,000 $130,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations1 110 3 0 2,500 $72,000 $110,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations210 590 16 0 13,000 $48,000 $5,200Reporting and RecordkeepingAll 0 0 0 0 $0$1,400,000TOTAL 40,000 180,000 120,000 400 4,000,000 $180,000,000 $170,000,0003-30Table 3-18 Incrementally Affected Units, EmissionsReductions and Costs, Proposed Option 2, High Impact Case, 2025Source/Emissions PointIncrementallyAffected UnitsNationwide Emissions Reductions National Costs(2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and DelineationOil Wells1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000Fugitive EmissionsWell Pads140,000 170,000 48,000 1,800 3,900,000 $110,000,000 $270,000,000Gathering and BoostingStations1,600 33,000 9,100 340 740,000 $25,000,000 $17,000,000Transmission CompressorStations130 10,000 280 8 230,000 $2,100,000 $2,600,000Pneumatic PumpsWell Pads18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations400 8,800 240 7 200,000 $2,800,000 $790,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations6 670 18 1 15,000 $430,000 $680,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations1,300 3,500 97 3 80,000 $290,000 $31,000Reporting and RecordkeepingAll 0 0 0 0 $0$4,100,000TOTAL 180,000 400,000 180,000 2,500 9,000,000 $330,000,000 $420,000,0003-31Table 3-19 Incrementally Affected Units, EmissionsReductions and Costs, Option 3, 2020Source/Emissions PointIncrementallyAffectedUnitsNationwide Emissions Reductions National Costs(2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and Delineation OilWells870 8,000 6,700 1 180,000 $3,200,000 $3,200,000Fugitive EmissionsWell Pads22,000 34,000 9,600 360 780,000 $18,000,000 $81,000,000Gathering and BoostingStations260 7,300 2,000 76 170,000 $4,200,000 $5,400,000Transmission CompressorStations21 2,300 63 2 52,000 $340,000 $780,000Pneumatic PumpsWell Pads3,000 5,400 1,500 57 120,000 $5,900,000 $840,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations67 1,500 40 1 33,000 $470,000 $130,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations1 110 3 0 2,500 $72,000 $110,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations210 590 16 0 13,000 $48,000 $5,200Reporting and RecordkeepingAll 0 0 0 0 $0$1,400,000TOTAL 40,000 190,000 130,000 510 4,200,000 $180,000,000 $210,000,0003-32Table 3-20 Incrementally Affected Units, EmissionsReductions and Costs, Option 3, 2025SourceIncrementallyAffected UnitsNationwide Emissions Reductions National Costs(2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and DelineationOil Wells1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000Fugitive EmissionsWell Pads140,000 230,000 64,000 2,400 5,200,000 $110,000,000 $510,000,000Gathering and BoostingStations1,600 44,000 12,000 460 990,000 $25,000,000 $32,000,000Transmission CompressorStations130 14,000 380 11 310,000 $2,100,000 $4,700,000Pneumatic PumpsWell Pads18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations400 8,800 240 7 200,000 $2,800,000 $790,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations6 670 18 1 15,000 $430,000 $680,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations1,300 3,500 97 3 80,000 $290,000 $31,000Reporting and RecordkeepingAll 0 0 0 0 $0$4,100,000TOTAL 180,000 470,000 200,000 3,200 11,000,000$330,000,000 $680,000,0004-1 4 BENEFITS OF EMISSIONS REDUCTIONS

4.1 Introduction

The proposed NSPS amendments are expected to preven t new emissions from the oil and gas sector. For the proposed NSPS, there will be cl imate benefits from methane reductions,
ozone and PM 2.5 health benefits from VOC reductions, and HAP “co-benefits” . These co-benefits occur because the control techniques to meet the st andards simultaneously reduce methane, VOC, and HAP emissions. The proposed NSPS is antici pated to prevent 170,000 to 180,000 tons of methane, 120,000 tons of VOC, and 310 to 400 ton s of HAP from new sources in 2020. In 2025, the NSPS would prevent 340,000 to 400,000 ton s of methane, 170,000 to 180,000 tons of VOC, and 1,900 to 2,500 tons of HAP. The CO 2 -equivalent (CO 2 Eq.) methane emission
reductions are estimated to be 3.8 to 4.0 million m etric tons in 2020 and 7.7 to 9.0 million metric tons in 2025. As described in the subsequent sectio ns, these pollutants are associated with substantial climate, health, and welfare effects. T he only benefits monetized in this RIA are
methane-related climate benefits. The methane-relat ed climate effects are estimated to be $200 to $210 million and $460 to $550 million using a 3 per cent discount rate in 2020 and 2025, respectively. The specific control techniques for t he proposed NSPS are anticipated to have minor emissions disbenefits (e.g., increases in emi ssions of carbon dioxide (CO 2 ), nitrogen oxides (NO X ), PM, carbon monoxide (CO), and total hydrocarbons (THC)) and emission changes associated with the energy system impacts.

While we expect that the avoided VOC emissions will also result in improvements in air quality and reduce health and welfare effects assoc iated with exposure to ozone, fine particulate matter (PM 2.5 ), and HAP, we have determined that quantification of the VOC-related health benefits cannot be accomplished for this rule in a defensible way. This is not to imply that these benefits do not exist; 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. With the data available, we are not able to provide a credible health benefits estimates for this rule, due to the differences in the locations of oi l and natural gas emission points relative to existing information and the highly localized natur e of air quality responses associated with HAP4-2

and VOC reductions. 23 In this chapter, we provide a qualitative assessme nt of the health benefits associated with reducing exposure to these pollutan ts, as well as visibility impairment and ecosystem benefits. Table 4-1 summarizes the quanti fied and unquantified benefits in this analysis.

Table 4-1 Climate and Human Health Effects of Emiss ion Reductions from this Proposal

Category Specific Effect Effect Has Been Quantified Effect Has

Been Monetized More

Information Improved Environment

Reduced climate effects Global climate impacts from methane and

carbon dioxide (CO 2 ) — 1  Marten et al. (2014), SC-CO 2 TSDs Other climate impacts (e.g., ozone, black carbon, aerosols, other impacts) — — IPCC, Ozone ISA, PM ISA 2 Improved Human Health Reduced incidence of premature mortality from exposure to PM 2.5 Adult premature mortality based on cohort study estimates and expert elicitation estimates (age >25 or age >30) — — PM ISA 3

Infant mortality (age <1) — — PM ISA 3

Reduced incidence of morbidity from exposure to PM 2.5 Non-fatal heart attacks (age > 18) — — PM ISA 3

Hospital admissions—respiratory (all ages) — — PM I SA 3 Hospital admissions—cardiovascular (age >20) — — PM ISA 3 Emergency room visits for asthma (all ages) — — PM ISA 3 Acute bronchitis (age 8-12) — — PM ISA 3 Lower respiratory symptoms (age 7-14) — — PM ISA 3 Upper respiratory symptoms (asthmatics age 9- 11) — — PM ISA 3 Asthma exacerbation (asthmatics age 6-18) — — PM IS A 3 Lost work days (age 18-65) — — PM ISA 3 Minor restricted-activity days (age 18-65) — — PM I SA 3 Chronic Bronchitis (age >26) — — PM ISA 3 Emergency room visits for cardiovascular effects (all ages) — — PM ISA 3 Strokes and cerebrovascular disease (age 50- 79) — — PM ISA 3 Other cardiovascular effects (e.g., other ages) — — PM ISA 2 Other respiratory effects (e.g., pulmonary function, non-asthma ER visits, non-bronchitis chronic diseases, other ages and populations) — — PM ISA 2

23 Previous studies have estimated the monetized bene fits-per-ton of reducing VOC emissions associated w ith the effect that those emissions have on ambient PM 2.5 levels and the health effects associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009). While these ran ges of benefit-per-ton estimates provide useful con text, the geographic distribution of VOC emissions from the o il 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 redu ctions in that study are derived from total VOC emissions acr oss all sectors. Coupled with the larger uncertaint ies about the relationship between VOC emissions and PM 2.5 and the highly localized nature of air quality resp onses associated with VOC reductions, these factors lead us to conclude that the available VOC benefit-per-t on estimates are not appropriate to calculate monetize d benefits of these rules, even as a bounding exerc ise.4-3

Category Specific Effect Effect Has Been Quantified Effect Has

Been Monetized More

Information Reproductive and developmental effects (e.g., low birth weight, pre-term births, etc) — — PM ISA 2,4 Cancer, mutagenicity, and genotoxicity effects — — PM ISA 2,4

Reduced incidence of mortality from exposure to ozone Premature mortality based on short-term study

estimates (all ages) — — Ozone ISA 3 Premature mortality based on long-term study estimates (age 30–99) — — Ozone ISA 3

Reduced incidence of morbidity from exposure to ozone Hospital admissions—respiratory causes (age > 65) — — Ozone ISA 3 Hospital admissions—respiratory causes (age <2) — — Ozone ISA 3 Emergency department visits for asthma (all ages) — — Ozone ISA 3 Minor restricted-activity days (age 18–65) — — Ozon e ISA 3 School absence days (age 5–17) — — Ozone ISA 3 Decreased outdoor worker productivity (age 18–65) — — Ozone ISA 3 Other respiratory effects (e.g., premature aging of lungs) — — Ozone ISA 2 Cardiovascular and nervous system effects — — Ozone ISA 2 Reproductive and developmental effects — — Ozone IS A 2,4 Reduced incidence of morbidity from exposure to HAP Effects associated with exposure to hazardous air pollutants such as benzene — — ATSDR, IRIS 2,3

Improved Environment Reduced visibility impairment Visibility in Class 1 areas — — PM ISA 3 Visibility in residential areas — — PM ISA 3 Reduced effects from PM deposition (organics) Effects on Individual organisms and

ecosystems — — PM ISA 2

Reduced vegetation and ecosystem effects from exposure to

ozone Visible foliar injury on vegetation — — Ozone ISA 3

Reduced vegetation growth and reproduction — — Ozon e ISA 3 Yield and quality of commercial forest products and crops — — Ozone ISA 3 Damage to urban ornamental plants — — Ozone ISA 2 Carbon sequestration in terrestrial ecosystems — — Ozone ISA 3 Recreational demand associated with forest aesthetics — — Ozone ISA 2

Other non-use effects Ozone ISA 2 Ecosystem functions (e.g., water cycling, biogeochemical cycles, net primary productivity, leaf-gas exchange, community composition) — — Ozone ISA 2

1 The global climate and related impacts of CO 2 and CH 4 emissions changes, such as sea level rise, are est imated within each integrated assessment model as part of the calculat ion of the SC-CO 2 and SC-CH 4 . The resulting monetized damages, which are relevant for conducting the benefit-cost analys is, are used in this RIA to estimate the welfare ef fects of quantified changes in CO 2 emissions. 2 We assess these benefits qualitatively because we do not have sufficient confidence in available data or methods. 3 We assess these benefits qualitatively due to data limitations for this analysis, but we have quantif ied them in other analyses. 4 We assess these benefits qualitatively because curr ent evidence is only suggestive of causality or the re are other significant concerns over the strength of the association.4-4

4.2 Emission Reductions from the Proposed NSPS

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 methane, VOC, and HA P, including wells, well sites, processing plants, compressor stations, storage equipment, and transmission and distribution lines. These emission points are located throughout much of the country with significant concentrations in particular regions. For example, wells and processi ng plants are largely concentrated in the South Central, Midwest, and Southern California regions o f the U.S., whereas gas compression stations are located all over the country. Distribution line s to customers are frequently located within areas of high population density.

In implementing this rule, emission controls may le ad to reductions in ambient PM 2.5 and ozone below the National Ambient Air Quality Standa rds (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 this rule might affect attainment sta tus without air quality modeling data. 24 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. 25 By contrast, the emission reductions for implementation rules, including this rule, are generally from a specific class of wellcharacterized sources. In general, the EPA is more confident in the magnitude and location of the emission reductions for implementation rules rather than illustrative NAAQS analyses. Emission reductions achieved under these and other promulgat ed rules will ultimately be reflected in the baseline of future NAAQS analyses, which would redu ce the incremental costs and benefits associated with attaining the NAAQS.

24 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. 25 NAAQS RIAs hypothesize, but do not predict, the c ontrol strategies that States may choose to enact w hen implementing a NAAQS. The setting of a NAAQS does n ot directly result in costs or benefits, and as suc h, 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 contro l and emission reductions. However, some costs and benefits estimated in this RIA may account for the same air quality improvements as estimated in an illustrativ e NAAQS RIA.4-5

Table 4-2 shows the direct emission reductions anti cipated for this rule, across the regulatory options examined in the rule. It is impo rtant to note that these benefits accrue at different spatial scales. HAP emission reductions r educe exposure to carcinogens and other toxic pollutants primarily near the emission source. Redu cing VOC emissions would reduce precursors to secondary formation of PM 2.5 and ozone, which reduces exposure to these pollutan ts on a regional scale. Climate effects associated with lon g-lived greenhouse gases like methane generally do not depend on the location of the emis sion of the gas, and have global impacts. Methane is also a precursor to global background co ncentrations of ozone.

Table 4-2 Direct Emission Reductions across NSPS Re gulatory Options in 2020 and 2025

Pollutant Option 1 Option 2 (proposed) Option 3 20 20 Methane (short tons/year) 170,000 170,000 to 180,00 0 190,000 VOC (short tons/year) 120,000 120,000 130,000 HAP (short tons/year) 310 310 to 400 510 Methane (metric tons) 150,000 150,000 to 160,000 17 0,000 Methane (metric tons CO 2 Eq.) 3,800,000 3,800,000 to 4,000,000 4,200,000
202 5 Methane (short tons/year) 340,000 340,000 to 400,00 0 470,000 VOC (short tons/year) 170,000 170,000 to 180,000 20 0,000 HAP (short tons/year) 1,900 1,900 to 2,500 3,200 Methane (metric tons) 310,000 310,000 to 360,000 43 0,000 Methane (metric tons CO 2 Eq.) 7,700,00 7,700,000 to 9,000,000 11,000,000

4.3 Methane

4.3.1 Methane climate effects and valuation
Methane is the principal component of natural gas. Methane is also a potent greenhouse gas (GHG) that once emitted into the atmosphere abs orbs terrestrial infrared radiation that 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. 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 pr ecipitation patterns, melting and thawing of4-6

global glaciers and ice, increasingly severe weathe r events, such as hurricanes of greater intensity, and sea level rise, among other impacts.

According to the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report (AR5, 2013), changes in methane concentratio ns since 1750 contributed 0.48 W/m 2 of forcing, which is about 17 percent of all global fo rcing due to increases in anthropogenic GHG concentrations, and which makes methane the second leading long-lived climate forcer after
CO 2 . However, after accounting for changes in other gr eenhouse substances such as ozone and stratospheric water vapor due to chemical reactions of methane in the atmosphere, historical
methane emissions were estimated to have contribute d to 0.97 W/m 2 of forcing today, which is about 30 percent of the contemporaneous forcing due to historical greenhouse gas emissions.

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 13 (published April 2015) estimates 2013 methane emissions from Petroleum and Natural Gas Sy stems (not including petroleum refineries and petroleum transportation) to be 182 MMt CO 2 Eq. In 2013, total methane emissions from the oil and gas industry represented nearly 29 percent of the total methane emissions from all sources and account for about 3 percent of all CO 2 Eq. emissions in the U.S., with the combined petroleum and natural gas systems being the largest contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2015c).

It is important to note that the 2013 GHG emissions estimates do not include methane emissions from hydraulically fractured and re-fract ured oil well completions due to lack of available data when the 2013 GHG Inventory estimate was developed. The estimate in this proposed rule includes an adjustment for hydraulica lly fractured oil wells, and such an adjustment is also being considered as a planned im provement in the 2014 Inventory (to be published April 2016). This adjustment would increa se the 2013 Inventory methane estimate by
about 3 MMt CO 2 Eq. The total methane emissions from Petroleum and Natural Gas Systems based on the 2013 GHG Inventory, adjusted for hydra ulically fractured and re-fractured oil well completions, is approximately 185 MMt CO 2 Eq.

Actions taken to comply with the proposed NSPS are anticipated to significantly decrease methane emissions from the oil and natural gas sect or in the United States. The proposed NSPS4-7

is expected to reduce methane emissions by about 17 0,000 to 180,000 short tons or approximately 150,000 to 160,000 metric tons methan e (or 3.8 to 4.0 MMt CO 2 Eq.) in 2020. In 2025, the proposed NSPS is expected to reduce metha ne emissions by about 340,000 to 400,000 short tons or approximately 310,000 to 360,000 metr ic tons methane (or 7.7 to 9.0 MMt CO 2 Eq.). These reductions in 2020 and 2025 represent a bout 2 percent and 4 to 5 percent, respectively, of the GHG emissions for this sector (excluding petroleum refineries and petroleum transportation) reported in the 1990-2013 U.S. GHG Inventory (182 MMt CO 2 Eq.).

We calculated the global social benefits of methane emissions reductions expected from the proposed NSPS using estimates of the social cos t of methane (SC-CH 4 ), a metric that estimates the monetary value of impacts associated with marginal changes in methane emissions in a given year. It includes a wide range of antici pated climate impacts, such as net changes in agricultural productivity and human health, propert y damage from increased flood risk, and changes in energy system costs, such as reduced cos ts for heating and increased costs for air conditioning. The SC-CH 4 estimates applied in this analysis were developed by Marten et al. (2014) and are discussed in greater detail below.

A similar metric, the social cost of CO 2 (SC-CO 2 ), provides important context for understanding the Marten et al. SC-CH 4 estimates. Estimates of the SC-CO 2 have been used by the EPA and other federal agencies to value the imp acts of CO 2 emissions changes in benefit cost analysis for GHG-related rulemakings since 2008. Th e SC-CO 2 is a metric that estimates the monetary value of impacts associated with marginal changes in CO 2 emissions in a given year.
Similar to the SC-CH 4 , it includes a wide range of anticipated climate i mpacts, such as net changes in agricultural productivity, property dama ge from increased flood risk, and changes in energy system costs, such as reduced costs for heat ing and increased costs for air conditioning. It is used to quantify the benefits of reducing CO 2 emissions, or the disbenefit from increasing emissions, in regulatory impact analyses.

The SC-CO 2 estimates were developed over many years, using th e best science available, and with input from the public. Specifically, an in teragency working group (IWG) that included the EPA and other executive branch agencies and off ices used three integrated assessment models (IAMs) to develop the SC-CO 2 estimates and recommended four global values for u se in4-8

regulatory analyses. The SC-CO 2 estimates were first released in February 2010 and updated in 2013 using new versions of each IAM. The 2013 updat e did not revisit the 2010 modeling decisions with regards to the discount rate, refere nce case socioeconomic and emission scenarios, and equilibrium climate sensitivity distribution. R ather, improvements in the way damages are modeled are confined to those that have been incorp orated into the latest versions of the models by the developers themselves and published in the p eer-reviewed literature. The 2010 SC-CO 2 Technical Support Document (2010 SC-CO 2 TSD) provides a complete discussion of the methods used to develop these estimates and the cur rent SC-CO 2 TSD presents and discusses the 2013 update (including recent minor technical corre ctions to the estimates). 26

The 2010 SC-CO 2 TSD noted a number of limitations to the SC-CO 2 analysis, including the incomplete way in which the IAMs capture catast rophic and non-catastrophic impacts, their incomplete treatment of adaptation and technologica l change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regar ding risk aversion. Currently IAMs do not assign value to all of the important physical, ecol ogical, and economic impacts of climate change recognized in the climate change literature due to a lack of precise information on the nature of damages and because the science incorporated into t hese models understandably lags behind the most recent research. Nonetheless, these estimates and the discussion of their limitations represent the best available information about the social benefits of CO 2 reductions to inform benefit-cost analysis. The new versions of the mode ls offer some improvements in these areas, although further work is warranted.

Accordingly, the EPA and other agencies continue to engage in research on modeling and valuation of climate impacts with the goal to impro ve these estimates. The EPA and other agencies also continue to consider feedback on the SC-CO 2 estimates from stakeholders through a range of channels, including public comments on A gency rulemakings that use the SC-CO 2 in supporting analyses and through regular interaction s with stakeholders and research analysts implementing the SC-CO 2 methodology used by the IWG. In addition, OMB soug ht public

26 Both the 2010 SC-CO 2 TSD and the current SC-CO 2 TSD are available at: https://www.whitehouse.gov/omb/oira/social-cost-of- carbon4-9

comment on the approach used to develop the SC-CO 2 estimates through a separate comment period that ended on February 26, 2014. 27

After careful evaluation of the full range of comme nts, the IWG continues to recommend
the use of the SC-CO 2 estimates in regulatory impact analysis. With the release of the response to comments, the IWG announced plans to obtain expe rt independent advice from the National Academy of Sciences to ensure that the SC-CO 2 estimates continue to reflect the best available
scientific and economic information on climate chan ge. 28 The NRC review will be informed by the public comments received and focus on the techn ical merits and challenges of potential approaches to improving the SC-CO 2 estimates in future updates.

Concurrent with OMB’s publication of the response t o comments on SC-CO 2 and announcement of the NRC process, OMB posted a revis ed TSD that includes two minor
technical corrections to the current estimates. One technical correction addressed an inadvertent omission of climate change damages in the last year of analysis (2300) in one model and the second addressed a minor indexing error in another model. On average the revised SC-CO 2 estimates are one dollar less than the mean SC-CO 2 estimates reported in the November 2013 TSD. The change in the estimates associated with th e 95th percentile estimates when using a 3 percent discount rate is slightly larger, as those estimates are heavily influenced by the results from the model that was affected by the indexing er ror.

The four SC-CO 2 estimates are: $13, $45, $67, and $130 per metric ton of CO 2 emissions in the year 2020 (2012 dollars). 29 The first three values are based on the average SC -CO 2 from the three IAMs, at discount rates of 5, 3, and 2.5 percent, respectively. Estimates of the SC-CO 2 for several discount rates are included because the literature shows that the SC-CO 2 is sensitive to assumptions about the discount rate, and because no consensus exists on the appropriate rate

27 For the IWG’s response to comments, see https://www.whitehouse.gov/sites/default/files/omb/ inforeg/sccresponse-to-comments-final-july-2015.pdf

. 28 See https://www.whitehouse.gov/blog/2015/07/02/estimati ng-benefits-carbon-dioxide-emissions-reductions

. 29 The current version of the SC-CO 2 TSD is available at: <link to be added when availa ble>. The TSDs present SC-CO 2 in $2007. The estimates were adjusted to 2012$ usi ng the GDP Implicit Price Deflator (1.0804). Also available at: http://www.bea.gov/iTable/index_nipa. cfm. The SC-CO 2 values have been rounded to two significant digits. Unrounded numbers from the 2013 SCC TSD were adjusted to 2012$ and used to calcula te the CO 2 benefits.4-10

to use in an intergenerational context (where costs and benefits are incurred by different generations). The fourth value is the 95 th percentile of the SC-CO 2 across all three models at a 3 percent discount rate. It is included to represent higher-than-expected impacts from temperature change further out in the tails of the SC-CO 2 distribution. The SC-CO 2 increases over time because future emissions are expected to produce la rger incremental damages as economies grow and physical and economic systems become more stres sed in response to greater climate change.

A challenge particularly relevant to this proposal is that the IWG did not estimate the
social costs of non-CO 2 GHG emissions at the time the SC-CO 2 estimates were developed. One alternative approach to value methane impacts is to use the global warming potential (GWP) to
convert the emissions to CO 2 equivalents which are then valued using the SC-CO 2 estimates.

The GWP measures the cumulative radiative forcing f rom a perturbation of a non-CO 2 GHG relative to a perturbation of CO 2 over a fixed time horizon, often 100 years. The GW P mainly reflects differences in the radiative effici ency of gases and differences in their atmospheric lifetimes. While the GWP is a simple, t ransparent, and well-established metric for assessing the relative impacts of non-CO 2 emissions compared to CO 2 on a purely physical basis,
there are several well-documented limitations in us ing it to value non-CO 2 GHG benefits, as
discussed in the 2010 SC-CO 2 TSD and previous rulemakings (e.g., U.S. EPA 2012b , 2012d). 30 In particular, several recent studies found that GW P-weighted benefit estimates for methane are likely to be lower than the estimates derived using directly modeled social cost estimates for these gases. Gas comparison metrics, such as the GWP, are design ed to measure the impact of
non-CO 2 GHG emissions relative to CO 2 at a specific point along the pathway from emissio ns to monetized damages (depicted in Figure 4-1), and thi s point may differ across measures.

Source: Marten et al. 2014 Figure 4-1 Path from GHG Emissions to Monetized Dam ages

30 See also Reilly and Richards, 1993; Schmalensee, 1 993; Fankhauser, 1994; Marten and Newbold, 2012.4-11

The GWP is not ideally suited for use in benefit-co st analyses to approximate the social
cost of non-CO 2 GHGs because it ignores important nonlinear relati onships beyond radiative forcing in the chain between emissions and damages. These can become relevant because gases
have different lifetimes and the SC-CO 2 takes into account the fact that marginal damages from an increase in temperature are a function of existi ng temperature levels. Another limitation of gas comparison metrics for this purpose is that some en vironmental and socioeconomic impacts are not linked to all of the gases under consideration, or radiative forcing for that matter, and will therefore be incorrectly allocated. For example, th e economic impacts associated with increased agricultural productivity due to higher atmospheric CO 2 concentrations included in the SC-CO 2 would be incorrectly allocated to methane emissions with the GWP-based valuation approach.

Also of concern is the fact that the assumptions ma de in estimating the GWP are not consistent with the assumptions underlying SC-CO 2 estimates in general, and the SC-CO 2 estimates developed by the IWG more specifically. F or example, the 100-year time horizon usually used in estimating the GWP is less than the approximately 300-year horizon the IWG used in developing the SC-CO 2 estimates. The GWP approach also treats all impact s within the time horizon equally, independent of the time at wh ich they occur. This is inconsistent with the role of discounting in economic analysis, which acc ounts for a basic preference for earlier over later gains in utility and expectations regarding f uture levels of economic growth. In the case of methane, which has a relatively short lifetime comp ared to CO 2 , the temporal independence of the GWP could lead the GWP approach to underestimat e the SC-CH 4 with a larger downward bias under higher discount rates (Marten and Newbol d, 2012). 31

The EPA sought public comments on the valuation of non-CO 2 GHG impacts in previous rulemakings (e.g., U.S. EPA 2012b, 2012d). In gener al, the commenters strongly encouraged the EPA to incorporate the monetized value of non-CO 2 GHG impacts into the benefit cost analysis, however they noted the challenges associated with t he GWP-approach, as discussed above, and encouraged the use of directly-modeled estimates of the SC-CH 4 to overcome those challenges.

31 We note that the truncation of the time period in the GWP calculation could lead to an overestimate o f SC-CH 4 for near term perturbation years when the SC-CO 2 is based on a sufficiently low or steeply declinin g discount rate.4-12

The EPA had cited several researchers that had dire ctly estimated the social cost of nonCO 2 emissions using IAMs but noted that the number of such estimates was small compared to the large number of SC-CO 2 estimates available in the literature. The EPA fou nd considerable variation among these published estimates in terms of the models and input assumptions they employ (U.S. EPA, 2012d). These studies differed in the emissions perturbation year, employed a wide range of constant and variable discount rate specifications, and considered a range of
baseline socioeconomic and emissions scenarios that have been developed over the last 20 years. Furthermore, at the time, none of the other publish ed estimates of the social cost of non-CO 2 GHG were consistent with the SC-CO 2 estimates developed by the IWG, and most were like ly underestimates due to changes in the underlying sci ence since their publication.

Therefore, the EPA concluded that the GWP approach would serve as an interim method of analysis until directly modeled social cost esti mates for non-CO 2 GHGs, consistent with the
SC-CO 2 estimates developed by the IWG, were developed. Th e EPA presented GWP-weighted estimates in sensitivity analyses rather than the m ain benefit-cost analyses. 32

Since then, a paper by Marten et al. (2014) provided the first set of published SC-CH 4 estimates in the peer-reviewed literature that are consistent with the modeling assumptions underlying the SC-CO 2 estimates. 33 Specifically, the estimation approach of Marten et al. used the same set of three IAMs, five socioeconomic and emissions scenarios, equilibrium climate sensitivity distribution, three constant discount r ates, and aggregation approach used by the IWG to develop the SC-CO 2 estimates. The aggregation method involved distill ing the 45 distributions
of the SC-CH 4 produced for each emissions year into four estimat es: the mean across all models and scenarios using a 2.5 percent, 3 percent, and 5 percent discount rate, and the 95 th percentile of the pooled estimates from all models and scenari os using a 3 percent discount rate. The atmospheric lifetime and radiative efficacy of meth ane used by Marten et al. is based on the

32 For example, the 2012 New Source Performance Stand ards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry are expected to reduce met hane emissions by 900,000 metric tons annually, see http ://www.gpo.gov/fdsys/pkg/FR-2012-08-16/pdf/2012- 16806.pdf. Additionally, the 2017-2025 Light-duty V ehicle Greenhouse Gas Emission Standards and Corpor ate Average Fuel Economy Standards, promulgated jointly with the National Highway Traffic Safety Administration, is expected to reduce methane emiss ions by over 100,000 metric tons in 2025 increasing to nearly 500,000 metric tons in 2050, see http://www. gpo.gov/fdsys/pkg/FR-2012-10-15/pdf/2012-21972.pdf 33 Marten et al. (2014) also provided the first set of SC-N 2 0 estimates that are consistent with the assumption s underlying the SC-CO 2 estimates.4-13

estimates reported by the IPCC in their Fourth Asse ssment Report (AR4, 2007), including an adjustment in the radiative efficacy of methane to account for its role as a precursor for tropospheric ozone and stratospheric water. These v alues represent the same ones used by the IPCC in AR4 for calculating GWPs. At the time Marte n et al. developed their estimates of the
SC-CH 4 , AR4 was the latest assessment report by the IPCC. The IPCC updates GWP estimates with each new assessment, and in the most recent as sessment, AR5, the latest estimate of the methane GWP ranged from 28-36, compared to a GWP of 25 in AR4. The updated values reflect a number of changes: changes in the lifetime and ra diative efficiency estimates for CO 2 , changes in the lifetime estimate for methane, and changes i n the correction factor applied to methane’s
GWP to reflect the effect of methane emissions on o ther climatically important substances such as tropospheric ozone and stratospheric water vapor . In addition, the range presented in the latest IPCC report reflects different choices regarding wh ether to account for how biogenic and fossil methane have different carbon cycle effects, and fo r whether to account for climate feedbacks on the carbon cycle for both methane and CO 2 (rather than just for CO 2 as was done in AR4). 34 , 35

Marten et al. (2014) discuss these estimates, (SC-CH 4 estimates presented below in Table 4-3), and compare them with other recent estimates in the literature. 36 The authors noted that a direct comparison of their estimates with all of th e other published estimates is difficult, given
the differences in the models and socioeconomic and emissions scenarios, but results from three relatively recent studies offer a better basis for comparison (see Hope (2006), Marten and Newbold (2012), Waldhoff et al. (2014)). Marten et al. found that in general the SC-CH 4 estimates from their 2014 paper are higher than pre vious estimates. The higher SC-CH 4 estimates are partially driven by the higher effective radiat ive forcing due to the inclusion of indirect effects from methane emissions in their modeling. M arten et al. , similar to other recent studies, also find that their directly modeled SC-CH 4 estimates are higher than the GWP-weighted

34 Climate Change 2013: The Physical Science Basis. Co ntribution of Working Group I to the Fifth Assessme nt Report of the Intergovernmental Panel on Climate Ch ange [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Pres s, Cambridge, United Kingdom and New York, NY, USA. 35 Note that this proposal uses a GWP value for metha ne of 25 for CO 2 equivalency calculations, consistent with the GHG emissions inventories and the IPCC Fourth A ssessment Report (AR4). 36 Marten et al. (2014) estimates are presented in 2007 dollars. Th ese estimates were adjusted for inflation using National Income and Product Accounts Tables, Table 1.1.9, Implicit Price Deflators for Gross Domestic Product (US Department of Commerce, Bureau of Econo mic Analysis), http://www.bea.gov/iTable/index_nipa.cfm (1.0804) Accessed 3/3/15.4-14

estimates. More detailed discussion of the SC-CH 4 estimation methodology, results and a comparison to other published estimates can be foun d in Marten et al.

Table 4-3 Social Cost of Methane (SC-CH 4 ), 2012 – 2050 a [in 2012$ per metric ton] (Source: Marten et al. , 2014 b )

Year SC-CH 4

5 Percent Average 3 Percent

Average 2.5 Percent

Average 3 Percent 95th percentile 2012 $430 $1,000 $1,400 $2,800 2015 $490 $1,100 $1,500 $3,000 2020 $580 $1,300 $1,700 $3,500 2025 $700 $1,500 $1,900 $4,000 2030 $820 $1,700 $2,200 $4,500 2035 $970 $1,900 $2,500 $5,300 2040 $1,100 $2,200 $2,800 $5,900 2045 $1,300 $2,500 $3,000 $6,600 2050 $1,400 $2,700 $3,300 $7,200

a The values are emissions-year specific and are def ined in real terms, i.e., adjusted for inflation us ing the GDP implicit price deflator. b The estimates in this table have been adjusted to reflect the minor technical corrections to the SC-C O 2 estimates described above. See Corrigendum to Marten et al . (2014) for more details http://www.tandfonline.com/doi/abs/10.1080/14693062 .2015.1070550

.

The application of directly modeled estimates from Marten et al. (2014) to benefit-cost analysis of a regulatory action is analogous to the use of the SC-CO 2 estimates. Specifically, the
SC-CH 4 estimates in Table 4-3 are used to monetize the be nefits of reductions in methane emissions expected as a result of the proposed rule making. Forecast changes in methane emissions in a given year, expected as a result of the proposed regulatory action, are multiplied by the SC-CH 4 estimate for that year. To obtain a present value estimate, the monetized stream
of future non-CO 2 benefits are discounted back to the analysis year using the same discount rate
used to estimate the social cost of the non-CO 2 GHG emission changes. In addition, the
limitations for the SC-CO 2 estimates discussed above likewise apply to the SC -CH 4 estimates, given the consistency in the methodology.

The EPA recently conducted a peer review of the app lication of the Marten et al. (2014)
non-CO 2 social cost estimates in regulatory analysis and r eceived responses that supported this4-15

application. Three reviewers considered seven charg e questions that covered issues such as the EPA’s interpretation of the Marten et al. estimates, the consistency of the estimates with t he SCCO 2 estimates, the EPA’s characterization of the limit s of the GWP-approach to value non-CO 2 GHG impacts, and the appropriateness of using the M arten et al. estimates in regulatory impact analyses. The reviewers agreed with the EPA’s inter pretation of Marten et al. ’s estimates; generally found the estimates to be consistent with the SC-CO 2 estimates; and concurred with the limitations of the GWP approach, finding directly m odeled estimates to be more appropriate. While outside of the scope of the review, the revie wers briefly considered the limitations in the
SC-CO 2 methodology (e.g., those discussed earlier in this section) and noted that because the
SC-CO 2 and SC-CH 4 methodologies are similar, the limitations also ap ply to the resulting SCCH 4 estimates. Two of the reviewers concluded that use in RIAs of the SC-CH 4 estimates developed by Marten et al. and published in the peer-reviewed literature is a ppropriate, provided that the Agency discuss the limitations, similar to the discussion provided for SC-CO 2 and other economic analyses. All three reviewers encouraged c ontinued improvements in the SC-CO 2 estimates and suggested that as those improvements are realized they should also be reflected in
the SC-CH 4 estimates, with one reviewer suggesting the SC-CH 4 estimates lag this process. The EPA supports continued improvement in the SC-CO 2 estimates developed by the U.S. government and agrees that improvements in the SC-C O 2 estimates should also be reflected in
the SC-CH 4 estimates. The fact that the reviewers agree that the SC-CH 4 estimates are generally
consistent with the SC-CO 2 estimates that are recommended by OMB’s guidance o n valuing CO 2 emissions reductions, leads the EPA to conclude tha t use of the SC-CH 4 estimates is an analytical improvement over excluding methane emiss ions from the monetized portion of the benefit cost analysis.

In light of the favorable peer review and past comm ents urging the EPA to value nonCO 2 GHG impacts in its rulemakings, the Agency has use d the Marten et al. (2014) SC-CH 4 estimates to value methane impacts expected from th is proposed rulemaking and has included those benefits in the main benefits analysis. The E PA seeks comments on the use of these directly modeled estimates, from the peer-reviewed literature, for the social cost of non-CO 2 GHGs in this RIA.4-16

The methane benefits are presented below in Table 4 -4 for years 2020 and 2025 across regulatory options. Applying this approach to the m ethane reductions estimated for the proposed NSPS option, the 2020 methane benefits vary by disc ount rate and range from about $88 million to approximately $550 million; the mean SC-CH 4 at the 3 percent discount rate results in an estimate of about $200 to $210 million in 2020. The methane benefits increase for the proposed option in 2025 and likewise vary by discount rate, ranging from about $220 million to approximately $1.4 billion in that year; the mean S C-CH 4 at the 3-percent discount rate results in an estimate of about $460 to $550 million in 2025.

Table 4-4 Estimated Global Benefits of Methane Redu ctions* (in millions, 2012$)

Discount rate and statistic Option 1 Proposed Option 2 (Low) Proposed Option 2

(High) Option 3

2020 2025 2020 2025 2020 2025 2020 2025 Million metric tonnes of methane reduced 0.15 0.31 0.15 0.31 0.16 0.36 0.17 0.43

Million metric tonnes of CO 2 Eq. 3.8 7.7 3.8 7.7 4.0 9.0 4.2 11 5% (average) $89 $220 $88 $220 $93 $250 $99 $300 3% (average) $200 $470 $200 $460 $210 $550 $220 $640 2.5% (average) $260 $600 $260 $600 $280 $700 $290 $830 3% (95 th percentile) $530 $1,200 $520 $1,200 $550 $1,400 $590 $1,700 *The SC-CH 4 values are dollar-year and emissions-year specific . SC-CH 4 values represent only a partial accounting of climate impacts.
The vast majority of this proposal’s climate-relate d benefits are associated with methane reductions, but some climate-related impacts are ex pected from the proposal’s secondary air impacts. The secondary impacts are discussed in Sec tion 4.7.

Methane is also a precursor to ozone. In remote areas, methane is a dominant precursor to tropospheric ozone formation (U.S. EPA, 2013). Appr oximately 40 percent of the global annual mean ozone increase since preindustrial times is be lieved to be due to anthropogenic methane (HTAP, 2010). Projections of future emissions also indicate that methane is likely to be a key contributor to ozone concentrations in the future ( HTAP, 2010). Unlike NO X and VOCs, which affect ozone concentrations regionally and at hourl y time scales, methane emissions affect ozone concentrations globally and on decadal time scales given methane’s relatively long atmospheric lifetime (HTAP, 2010). Reducing methane emissions, therefore, can reduce global background ozone concentrations, human exposure to ozone, and the incidence of ozone-related health4-17

effects (West et al. , 2006, Anenberg et al. , 2009). These benefits are global and occur in bot h urban and rural areas. Reductions in background ozo ne concentrations can also have benefits for agriculture and ecosystems (UNEP/WMO, 2011). Studie s show that controlling methane emissions can reduce global ozone concentrations an d climate change simultaneously, but controlling other shorter-lived ozone precursors su ch as NO X , carbon monoxide, or non-methane VOCs have larger local health benefits from greater reductions in local ozone concentrations (West and Fiore, 2005; West et al. , 2006; Fiore et al. , 2008; Dentener et al. , 2005; Shindell et al.
, 2005, 2012; UNEP/WMO, 2011). The health, welfare, a nd climate effects associated with ozone are described in the preceding sections. Without de tailed air quality modeling, we are unable to estimate the effect that reducing methane will have on ozone concentrations at particular
locations.

Recently, a paper was published in the peer-reviewe d scientific literature that presented a range of estimates of the monetized ozone-related m ortality benefits of reducing methane emissions (Sarofim et al. 2015). For example, under their base case assumpti ons using a 3% discount rate, Sarofim et al . find global ozone-related mortality benefits of m ethane emissions reductions to be $790 per tonne of methane in 2020, with 10.6%, or $80, of this amount resulting from mortality reductions in the United States. The methodology used in this study is consistent in some (but not all) aspects with the modeling und erlying the SC-CO2 and SC-CH4 estimates discussed above, and required a number of additiona l assumptions such as baseline mortality rates and mortality response to ozone concentration s. The Sarofim et al. (2015) study may have implications for this benefits analysis as it provi des a potential approach to estimating the ozone related mortality benefits resulting from the metha ne reductions expected from this proposed rulemaking. The EPA requests comment on Sarofim et al. ’s approach to estimating the ozone related mortality benefits of methane emissions red uctions, including technical considerations in applying their methodology to this regulatory impac t analysis.

4.4 VOC as a PM 2.5 precursor This rulemaking would reduce emissions of VOC, whic h are a precursor to PM 2.5. Most
VOC emitted are oxidized to CO 2 rather than to PM, but a portion of VOC emission c ontributes
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 -4-18

related health effects. However, we have not quanti fied the PM 2.5 -related benefits in this analysis. Analysis of organic carbon measurements suggest onl y a fraction of secondarily formed organic carbon aerosols are of anthropogenic origin. The cu rrent state of the science of secondary organic carbon aerosol formation indicates that ant hropogenic VOC contribution to secondary organic carbon aerosol is often lower than the biog enic (natural) contribution. Given that a fraction of secondarily formed organic carbon aeros ols is from anthropogenic VOC emissions and the extremely small amount of VOC emissions fro m this sector relative to the entire VOC inventory it is unlikely this sector has a large co ntribution to ambient secondary organic carbon aerosols. Photochemical models typically estimate s econdary organic carbon from anthropogenic VOC emissions to be less than 0.1 μg/m 3

.
Due to data limitations regarding potential locatio ns of new and modified sources affected by this rulemaking, we did not perform air quality modeling for this rule needed to quantify the PM 2.5 benefits associated with reducing VOC emissions. D ue to the high degree of variability in the responsiveness of PM 2.5 formation to VOC emission reductions, we are unable to estimate the effect that reducing VOC will have on ambient PM 2.5 levels without air quality modeling. However, we provide the discussion below for context regarding findings from previous modeling.

4.4.1 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, the EPA generally quantifi es several health effects associated with exposure to PM 2.5 (e.g., U.S. EPA (2011g)). These health effects incl ude premature mortality for adults and infants; cardiovascular morbidity, such as heart attacks; respiratory morbidity, such as asthma attacks and acute and chronic bronchitis; wh ich result in hospital and ER visits, lost work days, restricted activity days, and respiratory sym ptoms. Although the EPA has not quantified these effects in previous benefits analyses, the sc ientific literature suggests that exposure to4-19

PM 2.5 is also associated with adverse effects on birth w eight, pre-term births, pulmonary function, other cardiovascular effects, and other r espiratory effects (U.S. EPA, 2009a).

When the EPA quantifies PM 2.5 -related benefits, the Agency assumes that all fine particles, regardless of their chemical composition , are equally potent in causing premature mortality because the scientific evidence is not ye t sufficient to allow differentiation of effect estimates by particle type (U.S. EPA, 2009a). Based on our review of the current body of scientific literature, the EPA estimates PM-related premature mortality without applying an
assumed concentration threshold. This decision is s upported by the data, which are quite consistent in showing effects down to the lowest me asured levels of PM 2.5 in the underlying epidemiology studies.

Previous studies have estimated the monetized benef its-per-ton of reducing VOC
emissions associated with the effect that those emi ssions have on ambient PM 2.5 levels and the
health effects associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009), and th ese estimates can provide useful context for this rulem aking. Using the estimates in Fann, Fulcher, and Hubbell (2009), the monetized benefit-per-ton o f reducing VOC emissions in nine urban areas of the U.S. ranges from $560 in Seattle, WA t o $5,700 in San Joaquin, CA, with a national average of $2,400. These estimates assume a 50 perc ent reduction in VOC, the Laden et al. (2006) mortality function (based on the Harvard Six Cities study, a large cohort epidemiology study in the Eastern U.S., an analysis year of 2015 , a 3 percent discount rate, and 2006$). Additional benefit-per-ton estimates are available from this dataset using alternate assumptions regarding the relationship between PM 2.5 exposure and premature mortality from empirical studies and supplied by experts (e.g., Pope et al. , 2002; Laden et al. , 2006; Roman et al. , 2008). The EPA generally presents a range of benefits esti mates derived from the American Cancer Society cohort (e.g., Pope et al. , 2002; Krewski et al. , 2009) to the Harvard Six Cities cohort (e.g., Laden et al. , 2006; Lepuele et al. , 2012) because the studies are both well-designed and extensively peer reviewed, and the EPA provides the benefit estimates derived from expert opinions in Roman et al. (2008) as a characterization of uncertainty. As sh own in Table 4-5, the range of VOC benefits that reflects the range of ep idemiology studies and the range of the urban4-20

areas is $300 to $7,500 per ton of VOC reduced (201 2$). 37 Since these estimates were presented in the 2012 Oil and Gas NSPS RIA (U.S. EPA, 2012b), we updated our methods to apply more recent epidemiological studies for these cohorts (i .e., Krewski et al. , 2009; Lepuele et al. , 2012) as well as additional updates to the morbidity stud ies and population data. 38 Because these updates would not lead to significant changes in th e benefit-per-ton estimates for VOC, we have not updated them here.

While these ranges of benefit-per-ton estimates pro vide useful context, the geographic distribution of VOC emissions from the oil and gas sector are not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009). In ad dition, the benefit-per-ton estimates for VOC emission reductions in that study are derived f rom total VOC emissions across all sectors. Coupled with the larger uncertainties about the rel ationship between VOC emissions and PM 2.5 , these factors lead the EPA to conclude that the ava ilable VOC benefit per ton estimates are not appropriate to calculate monetized benefits of this rule, even as a bounding exercise.

37 We also converted the estimates from Fann, Fulcher , and Hubbell (2009) to 2012$ and applied EPA’s cur rent value of a statistical life (VSL) estimate. For mor e information regarding EPA’s current VSL estimate, please see Section 5.6.5.1 of the RIA for the PM NAAQS RIA (U.S. EPA, 2012c). EPA continues to work to update its guidance on valuing mortality risk reductions.

38 For more information regarding these updates, plea se see Section 5.3 of the RIA for the final PM NAAQ S (U.S. EPA, 2012c).4-21Table 4-5 Monetized Benefits-per-Ton Estimates forVOC based on Previous Modeling in 2015 (2012$)AreaPopeet al.(2002)Ladenet al.(2006)ExpertAExpertBExpertCExpertDExpertEExpertFExpertGExpertHExpertIExpertJExpertKExpertLAtlanta $660 $1,600 $1,700$1,300$1,300$920 $2,100$1,200$780 $980 $1,300$1,000$260 $1,000Chicago $1,600 $4,000 $4,200$3,300$3,200$2,300$5,300$3,000$1,900$2,400$3,200$2,600$640 $2,500Dallas $320 $790 $830 $650 $630 $450 $1,000$580 $380 $480 $630 $510 $130 $490Denver $770 $1,900 $2,000$1,500$1,500$1,100$2,400$1,400$910 $1,100$1,500$1,200$300 $910NYC/ Philadelphia$2,300 $5,600 $5,900$4,600$4,500$3,200$7,300$4,100$2,700$3,400$4,500$3,600$890 $3,300Phoenix $1,100 $2,700 $2,800$2,200$2,100$1,500$3,500$2,000$1,300$1,600$2,100$1,700$420 $1,600Salt Lake $1,400 $3,300 $3,500$2,700$2,700$1,900$4,400$2,500$1,600$2,000$2,700$2,200$570 $2,100San Joaquin $3,100 $7,500 $7,900$6,100$6,000$4,300$9,700$5,500$3,600$4,500$6,000$4,900$1,400$4,600Seattle $300 $730 $770 $570 $590 $420 $950 $540 $350 $440 $580 $470 $120 $350National average $1,300 $3,200 $3,400$2,600$2,600$1,800$4,200$2,300$1,500$1,900$2,500$2,100$520 $1,900* These estimates assumed 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 adjusted from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currency year and the EPA’s currentVSL estimate. However, these estimates have not been updated to reflect recent epidemiological studiesfor mortality studies, morbidity studies, or populationdata. Using a discount rate of 7 percent, the benefit-per-ton estimates would be approximately 9 percent lower. Assuming a 75 percent reduction in VOCemissions 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. The EPA generally presents a rangeof benefits estimates derived from the expert functionsfrom Romanet al.(2008) as a characterization of uncertainty.4-22

4.4.2 Organic PM welfare effects
According to the previous residual risk assessment for this sector (U.S. EPA, 2012a), persistent and bioaccumulative HAP reported as emis sions from oil and gas operations include polycyclic organic matter (POM). POM defines a broa d class of compounds that includes polycyclic aromatic hydrocarbon compounds (PAHs). S everal significant ecological effects are associated with deposition of organic particles, in cluding persistent organic pollutants, and PAHs (U.S. EPA, 2009a). This summary is from section 6.6 .1 of the 2012 PM NAAQS RIA (U.S. EPA, 2012c).

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 su rfaces in urban settings increases the metal and organic component of storm water runoff. This a tmospherically-associated pollutant burden can then be toxic to aquatic biota. The contributio n of atmospherically deposited PAHs to aquatic food webs was demonstrated in high 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 et 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 is4-23

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

4.4.3 Visibility Effects
Reducing secondary formation of PM 2.5 from VOC emissions would improve visibility throughout the U.S. Fine particles with significant light-extinction efficiencies include sulfates, nitrates, organic carbon, elemental carbon, and soi l (Sisler, 1996). Suspended particles and gases degrade visibility by scattering and absorbing ligh t. Higher visibility impairment levels in the East are due to generally higher concentrations of fine particles, particularly sulfates, and higher average relative humidity levels. Visibility has di rect significance to people’s enjoyment of daily activities and their overall sense of wellbeing. Go od 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, 2011a; U.S. EPA, 2011g; U.S. EPA, 2012c) 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 ab le to determine whether VOC emission reductions would be likely to have a significant im pact on visibility in urban areas or Class I

areas.

4.5 VOC as an Ozone Precursor
This rulemaking would reduce emissions of VOC, whic h are also precursors to secondary formation of ozone. Ozone is not emitted directly i nto the air, but is created when its two primary components, volatile organic compounds (VOC) and ox ides of nitrogen (NO X ), react in the presence of sunlight. In urban areas, compounds rep resenting all classes of VOC are important for ozone formation, but biogenic VOC emitted from vegetation tend to be more important compounds in non-urban vegetated areas (U.S. EPA, 2 013). Therefore, reducing these emissions would reduce ozone formation, human exposure to ozo ne, and the incidence of ozone-related health effects. However, we have not quantified the ozone-related benefits in this analysis for several reasons. First, previous rules have shown t hat the monetized benefits associated with reducing ozone exposure are generally smaller than PM-related benefits, even when ozone is the pollutant targeted for control (U.S. EPA, 2010a, 20 14b). Second, the complex non-linear chemistry of ozone formation introduces uncertainty to the development and application of a4-24

benefit-per-ton estimate, particularly for sectors with substantial new growth. Third, the impact of reducing VOC emissions is spatially heterogeneou s depending on local air chemistry. Urban areas with a high population concentration are ofte n VOC-limited, which means that ozone is most effectively reduced by lowering VOC. Rural are as and downwind suburban areas are often
NO X -limited, which means that ozone concentrations are most effectively reduced by lowering
NO X emissions, rather than lowering emissions of VOC. Between these areas, ozone is relatively insensitive to marginal changes in both NO X and VOC.

Due to data limitations regarding potential locatio ns of new and modified sources affected by this rulemaking, we did not perform air quality modeling for this rule needed to quantify the ozone benefits associated with reducin g VOC emissions. Due to the high degree of variability in the responsiveness of ozone formation to VOC emission reductions and data limitations regarding the location of new and modif ied well sites, we are unable to estimate the effect that reducing VOC will have on ambient ozone concentrations without air quality modeling.

4.5.1 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). Researchers have associated ozone exposure with adverse health effec ts in numerous toxicological, clinical and epidemiological studies (U.S. EPA, 2013). When adeq uate data and resources are available, the EPA generally quantifies several health effects ass ociated with exposure to ozone (e.g., U.S. EPA, 2010a; U.S. EPA, 2011a). These health effects include respiratory morbidity such as asthma attacks, hospital and emergency department v isits, school loss days, as well as premature mortality. The scientific literature is also sugges tive that exposure to ozone is also associated with chronic respiratory damage and premature aging of the lungs.

In a recent EPA analysis, the EPA estimated that re ducing 15,000 tons of VOC from industrial boilers resulted in $3.6 to $15 million (2008$) of monetized benefits from reduced ozone exposure (U.S. EPA, 2011b). 39 After updating the currency year to 2012$, this im plies a

39 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.4-25

benefit-per-ton for ozone of $260 to $1,070 per ton of VOC reduced. Since EPA conducted the analysis of industrial boilers, the EPA published t he Integrated Science Assessment for Ozone (U.S. EPA, 2013), the Health Risk and Exposure Assessment for Ozone (U.S. EPA, 2014a), and the RIA for the proposed Ozone NAAQS (U.S. EPA, 201 4b). Therefore, the ozone mortality studies applied in the boiler analysis, while curre nt at that time, do not reflect the most updated
literature available. The selection of ozone mortal ity studies used to estimate benefits in RIAs was revisited in the RIA for the proposed Ozone NAA QS. Applying the more recent studies would lead to benefit-per-ton estimates for ozone w ithin the range shown here. While these ranges of benefit-per-ton estimates provide useful context, the geographic distribution of VOC emissions from the oil and gas sector are not consi stent with emissions modeled in the boiler analysis. Therefore, we do not believe that those e stimates to provide useful estimates of the monetized benefits of this rule, even as a bounding exercise.

4.5.2 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, 2013 ). Sensitivity to ozone is highly variable across species, with over 66 vegetation species identified as “ozone-sensitive”, many of which occur in state and national parks and forests. These effects include those that damage or impair the intended use of the plant or ecosystem. Such effect s are considered adverse to the public welfare and can include reduced growth and/or biomass produ ction in sensitive trees, reduced yield and quality of crops, visible foliar injury, species co mposition shift, and changes in ecosystems and associated ecosystem services.

4.5.3 Ozone climate effects
Ozone is a well-known short-lived climate forcing g reenhouse gas (GHG) (U.S. EPA, 2013). Stratospheric ozone (the upper ozone layer) is beneficial because it protects life on Earth from the sun’s harmful ultraviolet (UV) radiation. In contrast, tropospheric ozone (ozone in the lower atmosphere) is a harmful air pollutant that a dversely 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) study4-26

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 quantifiable influence of ground level ozone o n climate leads to increases in global surface temperature and changes in hydrological cycles.

4.6 Hazardous Air Pollutant (HAP) Benefits
When looking at exposures from all air toxic source s of outdoor origin across the U.S., we see that emissions declined by approximately 42 per cent since 1990. However, despite this decline, the 2005 National-Scale Air Toxics Assessm ent (NATA) predicts that most Americans are exposed to ambient concentrations of air toxics at levels that have the potential to cause adverse health effects (U.S. EPA, 2011d). 40 The levels of air toxics to which people are expos ed vary depending on where they live and work and the kinds of activities in which they engage. In order to identify and prioritize air toxics, emissi on source types and locations that are of greatest potential concern, the EPA conducts the NATA. 41 The most recent NATA was conducted for calendar year 2005 and was released in March 2011. NATA includes four steps:

1) Compiling a national emissions inventory of air toxics emissions from outdoor sources
2) Estimating ambient concentrations of air toxics across the U.S. utilizing dispersion
models
3) Estimating population exposures across the U.S. utilizing exposure models
4) Characterizing potential public health risk due to inhalation of air toxics including both
cancer and noncancer effects
Based on the 2005 NATA, the EPA estimates that abou t 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

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

41 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 uncerta inties are discussed on the 2005 NATA website. Even 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 de cision making process. U.S. EPA. (2011) 2005 Nation al-Scale Air Toxics Assessment. http://www.epa.gov/ttn/atw/n ata2005/4-27

cancer risks are formaldehyde and benzene. 42,43 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, 44 subchronic, 45 or acute 46 inhalation exposure to air toxics, and include neurological, c ardiovascular, 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.

Figure 4-2 and Figure 4-3 depict the 2005 NATA esti mated census tract-level carcinogenic risk and noncancer respiratory hazard from the assessment. It is important to note that large reductions in HAP emissions may not nece ssarily translate into significant reductions in health risk because toxicity varies by pollutant , and exposures may or may not exceed levels of concern. For example, acetaldehyde mass emission s were more than double acrolein
emissions on a national basis in the EPA’s 2005 Nat ional Emissions Inventory (NEI). However, the Integrated Risk Information System (IRIS) refer ence concentration (RfC) for acrolein is considerably lower than that for acetaldehyde, sugg esting that acrolein could be potentially more

42 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. 43 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. 44 Chronic exposure is defined in the glossary of the Integrated Risk Information System (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 t han approximately 90 days to 2 years in typically u sed laboratory animal species).

45 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 ty pically used laboratory animal species).

46 Defined in the IRIS database as exposure by the or al, dermal, or inhalation route for 24 hours or les s.4-28

toxic than acetaldehyde. 47 Thus, it is important to account for the toxicity and exposure, as well as the mass of the targeted emissions.

Figure 4-2 2005 NATA Model Estimated Census Tract C arcinogenic Risk from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics Inventory

47 Details on the derivation of IRIS values and avail able supporting documentation for individual chemic als (as well as chemical values comparisons) can be found a t http://cfpub.epa.gov/ncea/iris/compare.cfm.4-29

Figure 4-3 2005 NATA Model Estimated Census Tract N oncancer (Respiratory) Risk from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics Inventory
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 this rule. In a few previous analyses of the benefits of reductions in HAP, the EPA has quantified the benefits of potential reductions in the incidences of cancer and noncancer risk (e.g., U.S. EPA, 1995). In those analyses, EPA relied on unit risk factors (UR F) and reference concentrations (RfC) developed through risk assessment procedures. The U RF is a quantitative estimate of the carcinogenic potency of a pollutant, often expresse d as the probability of contracting cancer from a 70-year lifetime continuous exposure to a concent ration of one μg/m 3 of a pollutant. 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. An RfC is an estimate (with uncertainty spanning perhaps an order of magn itude) of a continuous inhalation exposure4-30

to the human population (including sensitive subgro ups) that is likely to be without an appreciable risk of deleterious noncancer health ef fects during a lifetime. As the purpose of a benefit analysis is to describe the benefits most l ikely to occur from a reduction in pollution, use of high-end, conservative risk estimates would over estimate the benefits of the regulation. While we used high-end risk estimates in past analyses, a dvice from the EPA’s Science Advisory Board (SAB) recommended that we avoid using high-end esti mates in benefit analyses (U.S. EPASAB, 2002). Since this time, the EPA has continued to develop better methods for analyzing the
benefits of reductions in HAP.

As part of the second prospective analysis of the b enefits and costs of the Clean Air Act (U.S. EPA, 2011a), the EPA conducted a case study a nalysis 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, the EPA’s Advisor y Council on Clean Air Compliance Analysis concluded that “the challenges for assessi ng progress in health improvement as a result of reductions in emissions of hazardous air polluta nts (HAP) 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, the EPA convened a workshop to address the inherent complexities, limitations, and uncertainties in current methods to quantify th e benefits of reducing HAP. Recommendations from this workshop included identif ying research priorities, focusing on susceptible and vulnerable populations, and improvi ng 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 HAP, and estimates of the value of an avoided case of cancer (fatal and non-fatal). Due to methodology and data limitations, we did not attempt to monetize the health benefits of reductions in HAP in this analysis. Instead, we pro vide a qualitative analysis of the health effects associated with the HAP anticipated to be reduced b y this rule. The EPA remains committed to4-31

improving methods for estimating HAP benefits by co ntinuing to explore additional concepts of benefits, including changes in the distribution of risk.

Available emissions data show that several differen t HAP are emitted from oil and natural gas operations, either from equipment leaks , processing, compressing, transmission and distribution, or storage tanks. Emissions of eight HAP make up a large percentage of the total 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, 2012a). In the subsequent sections, we describe the health effects associated with the main HAP of concern from the oil and natural gas sector: benzene, tolue ne, carbonyl sulfide, ethyl benzene, mixed xylenes, and n-hexane. This rule is anticipated to avoid or reduce 2,500 tons of HAP in 2025. With the data available, it was not possible to est imate the tons of each individual HAP that
would be reduced.

4.6.1 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. 48,49,50 The EPA states in its IRIS database that data indi cate a causal 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

48 U.S. Environmental Protection Agency (U.S. EPA). 20 00. Integrated Risk Information System File for Ben zene. 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.

49 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.

50 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. 89:3691-3695.4-32

Services has characterized benzene as a known human carcinogen. 51 , 52 A number of adverse noncancer health effects including blood disorders, such as preleukemia and aplastic anemia, have also been associated with long-term exposure t o benzene. 53,54 The most sensitive noncancer effect observed in humans, based on current data, i s the depression of the absolute lymphocyte
count in blood. 55,56 In addition, recent work, including studies sponsor ed by the Health Effects Institute (HEI), provides evidence that biochemical responses are occurring at lower levels of benzene exposure than previously known. 57,58,59,60 The EPA’s IRIS program has not yet evaluated
these new data.

4.6.2 Toluene 61
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

51 International Agency for Research on Cancer (IARC) . 1987. Monographs on the evaluation of carcinogeni c risk of chemicals to humans, Volume 29, Supplement 7, So me industrial chemicals and dyestuffs, World Health Organization, Lyon, France.

52 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.

53 Aksoy, M. (1989). Hematotoxicity and carcinogenicit y of benzene. Environ. Health Perspect. 82: 193-197

. 54 Goldstein, B.D. (1988). Benzene toxicity. Occupatio nal medicine. State of the Art Reviews. 3: 541-554.

55 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.

56 U.S. Environmental Protection Agency (U.S. EPA). 20 00. Integrated Risk Information System File for Ben zene (Noncancer Effects). Research and Development, Nati onal Center for Environmental Assessment, Washingto n, DC. This material is available electronically at: h ttp://www.epa.gov/iris/subst/0276.htm.

57 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.; Meng, M.; Winnik, M.; Kwok, E.; Li, Y.; Mu, R.; Xu, B.; Zhang, X.; Li, K. (2003). HEI Report 115, Validatio n & Evaluation of Biomarkers in Workers Exposed to Benzene in China.

58 Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohe n, et al. (2002). Hematological changes among Chinese workers with a broad range of benzene exposures. Am . J. Industr. Med. 42: 275-285.

59 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels of Benzene. Science 306: 1774-1776.

60 Turtletaub, K.W. and Mani, C. (2003). Benzene metab olism in rodents at doses relevant to human exposur e from Urban Air. Research Reports Health Effect Inst. Rep ort No.113.

61 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 >.4-33

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 include ataxia, tremors, cerebral atrophy, nystagmus (involuntary eye movements), and impaired speech, h earing, and vision. Chronic inhalation exposure of humans to toluene also causes irritatio n of the upper respiratory tract, eye irritation, dizziness, headaches, and difficulty with 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 data base 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.

4.6.3 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 the eyes and skin in humans. 62 No information is available on the chronic (long-t erm), reproductive, developmental, or carcinogenic effect s of carbonyl sulfide in humans. Carbonyl

62 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+463-58-1.4-34

sulfide has not undergone a complete evaluation and determination under the EPA's IRIS program for evidence of human carcinogenic potentia l. 63

4.6.4 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 irrit ation, 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 percentage of animals with tumors of the nasal and oral cavities in male and female rats exposed to ethylbe nzene via the oral route. 64 , 65 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). 66 , 67 The NTP (1999) carried out a chronic inhalation 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

63 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. This material is available electronically at http://www. epa.gov/iris/subst/0617.htm.

64 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.

65 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.

66 International Agency for Research on Cancer (IARC) , 2000. Monographs on the Evaluation of Carcinogeni c Risks to Humans. Some Industrial Chemicals. Vol. 77 , p. 227-266. IARC, Lyon, France.

67 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.4-35

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.

4.6.5 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. 68 Other reported effects include labored breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and kidneys. 69 Long-term inhalation exposure to xylenes in humans has been associated with a number of effects in the nervous system including h eadaches, dizziness, fatigue, tremors, and impaired motor coordination. 70 The EPA has classified mixed xylenes in Category D , not classifiable with respect to human carcinogenicity.

4.6.6 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 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 s tudies in rodents have reported behavioral

68 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. This material is available electronically at http://www. epa.gov/iris/subst/0270.htm.

69 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.

70 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=53.4-36

effects, neurophysiological changes and neuropathol ogical effects upon inhalation exposure to nhexane. Under the Guidelines for Carcinogen Risk As sessment (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. 71

4.6.7 Other Air Toxics
In addition to the compounds described above, other toxic compounds might be affected by this rule, including hydrogen sulfide (H 2 S). Information regarding the health effects of tho se compounds can be found in the EPA’s IRIS database. 72

4.7 Secondary Air Emissions Impacts

The control techniques to meet the standards are as sociated with several types of secondary emissions impacts, which may partially offset the d irect benefits of this rule. Table 4-7 shows the estimated secondary emissions impacts. Relative to the direct emission reductions anticipated from this rule, the magnitude of these secondary ai r pollutant impacts is small.

71 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 at <http://www.epa.gov/ttn/atw/cancer_guidelines_fina l_3- 25-05.pdf>.

72 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris4-37

Table 4-6 Secondary Air Pollutant Impacts (short to ns per year) 2020 Emissions Category CO 2 NO X PM CO THCTotal Hydraulically Fractured and Refractured Oil Well Completions 580,000 300 10 1,600 620 Fugitive Emissions minimal minimal minimal minimal minimal Pneumatic Pumps 24,000 12 0 66 25 Pneumatic Controllers 0 0 0 0 0 Compressors 550 0 0 2 1 Total 2020 610,000 310 10 1,700 640

2025 Emissions Category CO 2 NO X PM CO THCTotal Hydraulically Fractured and Refractured Oil Well Completions 610,000 310 11 1,700 640 Fugitive Emissions minimal minimal minimal minimal minimal Pneumatic Pumps 140,000 72 0 400 150 Pneumatic Controllers 0 0 0 0 0 Compressors 3,300 2 0 9 3 Total in 2025 750,000 380 11 2,100 790

The secondary emision impacts for regulatory option s are equal across the options. This result holds because the only requirements varied a cross the options is the coverage (low and high impact cases of the proposed Option 2) or freq uency (Moving from Option 1 to Option 3 increases the frequency of survey and repair under the fugitive emissions requirement) and secondary emissions from the fugitive emissions req uirements are expected to be minimal. We are not estimating the monetized disbenefits of the secondary emissions of CO 2 because much of
the methane that would have been released in the ab sence of the flare would have eventually
oxidized into CO 2 in the atmosphere. Note that the CO 2 produced from the methane oxidizing in the atmosphere is not included in the calculation o f the SC-CH 4
. However, the EPA does recognize that because the gr owth rate of the SC-CO 2 estimates are lower than their associated discount rates, the estimated impact of CO 2 produced in the future
from oxidized methane would be less than the estima ted impact of CO 2 released immediately from flaring, which would imply a small disbenefit associated with flaring. Assuming an average methane oxidation period of 8.7 years, consistent w ith the lifetime used in IPCC AR4, the disbenefits associated with destroying one metric t on of methane and releasing the CO 24-38

emissions in 2020 instead of being released in the future via the methane oxidation process is estimated to be $5 to $25 per metric ton CH 4 depending on the SC-CO 2 value or 0.7 percent to 0.9 percent of the SC-CH 4 estimates per metric ton for 2020. The analogous e stimates for 2025 are $7 to $34 per metric ton CH 4 or 0.8 percent to 1.0 percent of the SC-CH 4 estimates per metric
ton for 2025. 73 While the EPA is not accounting for the CO 2 disbenefits at this time, we request comment on the appropriateness of the monetization of such impacts using the SC-CO 2 and aspects of the calculation.

Table 4-7 provides a summary of the direct and seco ndary emissions changes. Based on this summary and analysis above, the net impact of both the direct and secondary impacts of this proposal would be an improvement in ambient air qua lity, which would reduce potency of greenhouse gas emissions, reduce exposure to variou s harmful pollutants, improve visibility impairment, and reduce vegetation damage.

Table 4-7 Summary of Emissions Changes (short tons per year, except where noted)
Option 1 Proposed

Option 2 (Low) Proposed

Option 2 (High) Option 3
Pollutant 2020 2025 2020 2025 2020 2025 2020 2025 Change in Direct Emissions Methane 170,000 340,000 170,000 340,000 180,000 400 ,000 190,000 470,000

VOC 120,000 170,000 120,000 170,000 120,000 180,000 130,000 200,000 HAP 310 1,900 310 1,900 400 2,500 510 3,200

Change in Secondary Emissions CO 2 610,000 750,000 610,000 750,000 610,000 750,000 61 0,000 750,000

NOx 310 380 310 380 310 380 310 380 PM 10 11 10 11 10 11 10 11 CO 1,700 2,100 1,700 2,100 1,700 2,100 1,700 2,100 THC 640 790 640 790 640 790 640 790

Net Change in CO 2 Eq. Emissions CO 2 Eq.

(million short tons) 4.2 8.5 4.2 8.5 4.4 9.9 4.7 12

CO 2 Eq. (million metric tons) 3.8 7.7 3.8 7.7 4.0 9.0 4.2 11

Note: Totals may not sum due to independent roundin g.

73 To calculate the disbenefits associated the comple te destruction of a ton of CH 4 through flaring, EPA took the difference between the SC-CO 2 at the time of the flaring and in 8.7 years and di scounted that value to the time of the flaring using the same discount rate as used to estimate the SC-CO 2 . This value was then scaled by 44/16 to account for the relative mass of carbon containe d in a ton of CH 4 versus a ton of CO 2 . The value of the SCCO 2 8.7 years after flaring was estimated by linearly interpolating between the annual SC-CO 2 estimates reported in the TSD and inflated to 2012 dollars.4-39

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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. Marc h. <http://www.epa.gov/cleanairactbenefits/feb11/fullr eport_rev_a.pdf>. Accessed March 30, 2015.4-43

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, 2015.
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/> Acces sed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 20 11g. Regulatory Impact Analysis for the Federal Implementation Plans to Reduce Interstate T ransport of Fine Particulate Matter and Ozone in 27 States; Correction of SIP Approvals for 22 States. Office of Air Quality Planning and Standards, Research Triangle Park, NC. July. <http://www.epa.gov/airtransport/pdfs/FinalRIA.pdf> . Accessed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 20 12a. Residual Risk Assessment for the Oil and Gas Production and Natural Gas Transmission and Storage Source Categories

. Office of Air Quality Planning and Standards, Resea rch Triangle Park, NC.
U.S. Environmental Protection Agency (U.S. EPA). 20 12b. Regulatory Impact Analysis Final New Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry . Office of Air Quality Planning and Standards, Health and Envi ronmental Impacts Division. April. < http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natu ral_gas_final_neshap_nsps_ria.pdf >. Accessed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 20 12c. Regulatory Impact Analysis for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter

. EPA-452/R-12-003. Office of Air Quality Planning an d Standards, Health and Environmental Impacts Division. December. Available at: <http://www.epa.gov/ttnecas1/regdata/RIAs/oil_natur al_gas_final_neshap_nsps_ria.pdf>. Accessed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 20 12d. Regulatory Impact Analysis: Final Rulemaking for 2017-2025 Light-Duty Vehicle Greenho use Gas Emission Standards and Corporate Average Fuel Economy Standards . EPA-420-R-12-016. Office of Transportation and Air Quality, Assessment and Stan dards Division. August. <http://www.epa.gov/otaq/climate/documents/420r1201 6.pdf>. Accessed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 20 13. Integrated Science Assessment of Ozone and Related Photochemical Oxidants (Final Rep ort). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-10/076 F. February. <http://cfpub.epa.gov/ncea/isa/recordisplay.cfm?dei d=247492#Download>. Accessed March 30, 2015.4-44

U.S. Environmental Protection Agency (U.S. EPA). 20 14a. Health Risk and Exposure Assessment for Ozone (Final Report). U.S. Environmental Protection Agency, Research Triangle Park, NC, EPA-452/R-14-004a. August. <http://www.epa.gov/ttn/naaqs/standards/ozone/data/ 20140829healthrea.pdf>. Accessed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 20 14b. Regulatory Impact Analysis for the Proposed Ozone NAAQS. U.S. Environmental Protection Agency, Research Tria ngle Park, NC, EPA-452/P-14-006. December. <http://www.epa.gov/ttnecas1/regdata/RIAs/20141125r ia.pdf>. Accessed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 20 14c. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 . EPA/430-R-14-003. April. < http://www.epa.gov/climatechange/ghgemissions/usinv entoryreport/2014.html >. Accessed April 3, 2015.
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/sab5CSABPRODUCT.NSF/343557 12EC011A358525719A005 BF6F6/$File/ecwkshp020012Bappa-g.pdf>. Accessed Mar ch 30, 2015.
U.S. Environmental Protection Agency—Science Adviso ry Board (U.S. EPA-SAB). 2008. Benefits of Reducing Benzene Emissions in Houston, 1990–2020 . EPA-COUNCIL-08- 001. July. <http://yosemite.epa.gov/sab/sabproduct.nsf/D4D7EC9 DAEDA8A548525748600728A8 3/$File/EPA-COUNCIL-08-001-unsigned.pdf>. Accessed March 30, 2015.
Waldhoff, S., D. Anthoff, S. Rose, R.S.J. Tol. 2014 . “The Marginal Damage Costs of Different Greenhouse Gases: An Application of FUND.” The Open-Access, Open Assessment EJournal . 8(31): 1-33. http://dx.doi.org/10.5018/economics-ejournal.ja.201 4-31 . Accessed April 3, 2014.

West et al. 2006. “Global health benefits of mitigating ozone pollution with methane emission controls.” Proceedings of the National Academy of Sciences 103(11):3988-3993. West, J.J., A.M. Fiore. 2005. “Management of tropos pheric ozone by reducing methane emissions.” Environmental Science & Technology 39:4685-4691.5-1 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 section 3(f)(1) Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more. Accordingly, t he EPA submitted this action to the Office of Management and Budget (OMB) for review under Exe cutive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in res ponse to OMB recommendations have been
documented in the docket for this action. Tables 6- 1 through 6-4 shows the results of the cost and benefits analysis for this proposed rule.

5.2 Paperwork Reduction Act

The Office of Management and Budget (OMB) has previ ously approved the information collection activities contained in 40 CFR part 60, subpart OOOO under the PRA and has assigned OMB control number 2060-0673 and ICR numbe r 2437.01; a summary can be found at 77 F.R. 49537. The information collection requireme nts in today’s proposed rule titled,
Standards of Performance for Crude Oil and Natural Gas Facilities for Construction, Modification, or Reconstruction (40 CFR part 60 sub part OOOOa) have been submitted for approval to the OMB under the PRA. The ICR document prepared by the EPA has been assigned EPA ICR Number 2523.01. You can find a copy of the ICR in the docket for this rule, and is briefly summarized below.

The information to be collected for the proposed NS PS is based on notification, performance tests, recordkeeping and reporting requ irements which will be mandatory for all operators subject to the final standards. Recordkee ping and reporting requirements are specifically authorized by section 114 of the CAA ( 42 U.S.C. 7414). The information will be used by the delegated authority (state agency, or R egional Administrator if there is no delegated state agency) to ensure that the standards and othe r requirements are being achieved. Based on
review of the recorded information at the site and the reported information, the delegated permitting authority can identify facilities that m ay not be in compliance and decide which5-2

facilities, records, or processes may need inspecti on. All information submitted to the EPA pursuant to the recordkeeping and reporting require ments for which a claim of confidentiality is made is safeguarded according to Agency policies se t forth in 40 CFR part 2, subpart B.

Potential respondents under subpart OOOOa are owner s or operators of new, modified or reconstructed oil and natural gas affected faciliti es as defined under the rule. None of the facilities in the United States are owned or operat ed by state, local, tribal or the Federal government. All facilities are privately owned for- profit businesses. The requirements in this action result in industry recording keeping and rep orting burden associated with review of the requirements for all affected entities, gathering r elevant information, performing initial performance tests and repeat performance tests if n ecessary, writing and submitting the notifications and reports, developing systems for t he purpose of processing and maintaining information, and train personnel to be able to resp ond to the collection of information.

The estimated average annual burden (averaged over the first 3 years after the effective date of the standards) for the recordkeeping and re porting requirements in subpart OOOOa for the 2,552 owners and operators that are subject to the rule is 92,658 labor hours, with an annual average cost of $3,163,699. The annual public repor ting and recordkeeping burden for this collection of information is estimated to average 3 .9 hours per response. Respondents must monitor all specified criteria at each affected fac ility and maintain these records for 5 years. Burden is defined at 5 CFR 1320.3(b).

5.3 Regulatory Flexibility Act (RFA)

The RFA generally requires an agency to prepare a r egulatory flexibility analysis of any rule subject to notice and comment rulemaking requi rements under the Administrative Procedure Act or any other statute unless the agency certifie s that the rule will not have a significant economic impact on a substantial number of small en tities. Small entities include small businesses, small organizations, and small governme ntal jurisdictions.
For purposes of assessing the impacts of this rule on small entities, a small entity is defined as: (1) A small business in the oil or natu ral gas industry whose parent company has no more than 500 employees (or revenues of less than $ 7 million for firms that transport natural gas5-3

via pipeline); (2) a small governmental jurisdictio n that is a government of a city, county, town, school district, or special district with a populat ion of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and
is not dominant in its field.
Pursuant to section 603 of the RFA, the EPA prepare d an initial regulatory flexibility analysis (IRFA) that examines the impact of the pro posed rule on small entities along with regulatory alternatives that could minimize that im pact. The complete IRFA is available for
review in the docket and is summarized here.
The IRFA describes the reason why the proposed rule is being considered and describes the objectives and legal basis of the proposed rule , as well as discusses related rules affecting the oil and natural gas sector. The IRFA describes the EPA’s examination of small entity effects prior to proposing a regulatory option and provides information about steps taken to minimize significant impacts on small entities while achievi ng the objectives of the rule.
The EPA also summarized the potential regulatory co st impacts of the proposed rule and alternatives in Section 3 of this RIA. The analysis in the IRFA drew upon the same analysis and assumptions as the analyses presented in RIA. The I RFA analysis is presented in its entirely in
Section 7.3 of the RIA.
Identifying impacts on specific entities is challen ging because of the difficulty of predicting potentially affected new or modified sou rces at the firm level. To identify potentially affected entities under the proposed NSPS, the EPA combined information from industry databases to identify firms drilling and completing wells in 2012, as well as identified their oil and natural gas production levels for that year.
The EPA based the analysis in the IRFA on impacts e stimates for the proposed requirements for hydraulically fractured and re-fra ctured oil well completions and well site fugitive emissions While the IRFA does not incorpor ate potential impacts from other provisions of the proposed NSPS, the completions and fugitive emissions provisions represent a large majority of the estimated compliance costs of the p roposed NSPS in 2020 and 2025. Note incorporating impacts from other provisions in this analysis is a limitation and underestimates impacts, but the EPA believes that detailed analysi s of the two provisions impacts on small entities is illustrative of impacts on small entiti es from the proposed rule in its entirety.5-4

We projected the 2012 base year estimates of increm entally affected facilities to 2020 and 2025 levels based on the same growth rates used to project future activities as described in the TSD and consistent with other analyses in this RIA. This approach assumes that no other firms perform potentially affected activities and f irms performing oil and natural gas activities in
2012 will continue to do so in 2020 and 2025. While likely true for many firms, this will not be
the case for all firms.
For some firms, we estimated their 2012 sales level s by multiplying 2012 oil and natural gas production levels reported in an industry datab ase by assumed oil and natural gas prices at the wellhead. For natural gas, we assumed the $4/Mc f for natural gas. For oil prices, we estimated revenues using two alternative prices, $7 0/bbl and $50/bbl. In the results, we call the case using $70/bbl the “primary scenario” and the c ase using the $50/bbl as the “low oil price
scenario”.
For projected 2020 and 2025 potentially affected ac tivities, we allocated compliance costs across entities based upon the costs estimate d in the TSD and used in the RIA. The RIA and IRFA also estimates the potential implications of the proposed exclusion for low producing sites from the fugitive emission requirements. Fewe r sites in the program due to this exclusion will likely lead to lower costs and emissions.
The analysis indicates about 1,200 to 2,100 small e ntities may be subject to the requirements for hydraulically fractured and re-fra ctured oil well completions and fugitive emissions requirements at well sites. The low end o f this range reflects an estimate of how many entities might be excluded as a result of the low p roduction fugitive emissions exemption. Also, the cost-to-sales ratios with ratios greater than 1 percent and 3 percent increase from 2020 to 2025 as affected sources accumulate under the propo sed NSPS. Cost-to-sales ratios exceeding 1 percent and 3 percent are also reduced from the cas e without the entities that might be excluded from fugitive emissions requirements as a result of the low production exemption.
The analysis above is subject to a number of caveat s and limitations. These are discussed in detail in the IRFA, as well as in Section 3 of t he RIA.
As required by section 609(b) of the RFA, the EPA a lso convened a Small Business Advocacy Review (SBAR) Panel to obtain advice and r ecommendations from small entity representatives that potentially would be subject t o the rule's requirements. The SBAR Panel5-5

evaluated the assembled materials and small-entity comments on issues related to elements of an IRFA. A copy of the full SBAR Panel Report is avail able in the rulemaking docket.

5.4 Unfunded Mandates Reform Act

This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely a ffect small governments. The action imposes no enforceable duty on any state, local or tribal g overnments or the private sector.

5.5 Executive Order 13132: Federalism

This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities amon g the various levels of government. These final rules primarily affect private industry and w ould not impose significant economic costs on state or local governments.

5.6 Executive Order 13175: Consultation and Coordinatio n with Indian Tribal Governments

This action has tribal implications. However, it wi ll neither impose substantial direct compliance costs on federally recognized tribal gov ernments, nor preempt tribal law. The majority of the units impacted by this rulemaking o n tribal lands are owned by private entities, and tribes will not be directly impacted by the com pliance costs associated with this rulemaking. There would only be tribal implications associated with this rulemaking in the case where a unit is owned by a tribal government or a tribal governm ent is given delegated authority to enforce the rulemaking.

The EPA consulted with tribal officials under the “ EPA Policy on Consultation and Coordination with Indian Tribes” early in the proce ss of developing this regulation to permit them to have meaningful and timely input into its d evelopment. Additionally, the EPA has conducted meaningful involvement with tribal stakeh olders throughout the rulemaking process. We provided an update on the methane strategy on th e January 29, 2015, NTAA and EPA Air5-6

Policy call. As required by section 7(a), the EPA’s Tribal Consultation Official has certified that the requirements of the Executive Order have been m et in a meaningful and timely manner. A copy of the certification is included in the docket for this action.

Consistent with previous actions affecting the oil and natural gas sector, there is significant tribal interest because of the growth o f the oil and natural gas production in Indian country. The EPA specifically solicits additional c omment on this proposed action from tribal
officials.

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

This action is subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it is an economically significant regulatory action as defined by Executive Order 12866, and the
EPA believes that the environmental health or safet y risk addressed by this action has a disproportionate effect on children. Accordingly, t he agency has evaluated the environmental health and welfare effects of climate change on chi ldren.

GHGs including methane contribute to climate change and are emitted in significant quantities by the oil and gas sector. The EPA belie ves that the GHG emission reductions resulting from implementation of these final guidel ines will further improve children’s health.

The assessment literature cited in the EPA’s 2009 E ndangerment Finding concluded that certain populations and life stages, including chil dren, the elderly, and the poor, are most
vulnerable to climate-related health effects. The a ssessment literature since 2009 strengthens these conclusions by providing more detailed findin gs regarding these groups’ vulnerabilities and the projected impacts they may experience.

These assessments describe how children’s unique ph ysiological and developmental factors contribute to making them particularly vuln erable to climate change. Impacts to children are expected from heat waves, air pollution, infect ious and waterborne illnesses, and mental health effects resulting from extreme weather event s. In addition, children are among those especially susceptible to most allergic diseases, a s well as health effects associated with heat5-7

waves, storms, and floods. Additional health concer ns may arise in low income households, especially those with children, if climate change r educes food availability and increases prices, leading to food insecurity within households.
More detailed information on the impacts of climate change to human health and welfare is provided in Section V of this preamble.

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

Executive Order 13211 (66 FR 28355, May 22, 2001) p rovides that agencies will prepare
and submit to the Administrator of the Office of In formation and Regulatory Affairs, Office of Management and Budget, a Statement of Energy Effect s for certain actions identified as “significant energy actions.” Section 4(b) of Execu tive Order 13211 defines “significant energy actions” as any action by an agency (normally publi shed in the Federal Register) that promulgates or is expected to lead to the promulgat ion of a final rule or regulation, including notices of inquiry, advance notices of proposed rul emaking, and notices of proposed rulemaking: (1)(i) that is a significant regulatory action unde r Executive Order 12866 or any successor order, and (ii) is likely to have a significant adverse ef fect on the supply, distribution, or use of energy; or (2) that is designated by the Administrator of t he Office of Information and Regulatory Affairs as a significant energy action.

This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not likely t o have a significant adverse effect on the supply, distribution, or use of energy. The basis f or these determinations follows.

The EPA used the National Energy Modeling System (N EMS) to estimate the impacts of the proposed rule on the United States energy syste m. The NEMS is a publically-available model of the United States energy economy developed and m aintained by the Energy Information Administration of the DOE and is used to produce th e Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States energy economy.

The EPA modeled the high impact case of the propose d NSPS with respect the low production exemption from the well site fugitive em issions requirements. As such the NEMS-5-8

based estimates of energy system impacts are likely high end estimates. We estimate that natural gas and crude oil production levels remains essenti ally unchanged in 2020, while slight declines are estimated for 2020 for both natural gas (about 4 billion cubic feet (bcf) or about 0.01 percent) and crude oil production (about 2,000 barrels per d ay or 0.03 percent). Wellhead natural gas prices for onshore lower 48 production are not esti mated to change in 2020, but are estimated to increase about $0.007 per Mcf or 0.14 percent in 20 25. Meanwhile, well crude oil prices for onshore lower 48 production are not estimated to ch ange, despite the incidence of new compliance costs from the proposed NSPS. Meanwhile, net imports of natural gas are estimated to decline slightly in 2020 (by about 1 bcf or 0.05 percent) and in 2025 (by about 3 bcf or 0.09 percent). Crude oil imports are estimated to not ch ange in 2020 and increase by about 1,000 barrels per day (or 0.02 percent) in 2025.

Additionally, the NSPS establishes several performa nce 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. For more information on the estimated energy effects of this proposed rule, please see Section 7 of this RIA.

5.9 National Technology Transfer and Advancement Act (N TTAA) and 1 C.F.R. part 51

Section 12(d) of the National Technology Transfer a nd Advancement Act of 1995 (NTTAA), Public Law No. 104–113 (15 U.S.C. 272 note ) directs the EPA to use voluntary consensus standards (VCS) in its regulatory activit ies unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are te chnical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. NTTAA directs the EPA to pro vide Congress, through OMB, explanations when the Agency decides not to use ava ilable and applicable VCS.

The proposed rule involves technical standards. The refore, the EPA conducted searches
for the Oil and Natural Gas Sector: Emission Standa rds for New and Modified Sources through the Enhanced National Standards Systems Network (NS SN) Database managed by the American National Standards Institute (ANSI). Searches were conducted for EPA Methods 1, 1A, 2, 2A,5-9

2C, 2D, 3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 21, 22, and 25A of 40 C.F.R. part 60 Appendix A. No applicable voluntary consensus standards were ident ified for EPA Methods 1A, 2A, 2D, 21, and 22. All potential standards were reviewed to determ ine the practicality of the VCS for this rule. In this rule, the EPA is proposing to include in a final EPA rule regulatory text for 40 CFR part 60, subpart OOOOa that includes incorporation by re ference. In accordance with requirements of 1 CFR 51.5, the EPA is proposing to incorporate by reference ANSI/ASME PTC 19-10–1981, Flue and Exhaust Gas Analyses (Part 10) to be used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A and 16A manual portions only and not the instrument al portion. This standard is available from the American Society of Mechanical Engineers (ASME) , Three Park Avenue, New York, NY
10016–5990.

The EPA welcomes comments on this aspect of the p roposed 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 Executive Order 12898: Federal Actions to Address E nvironmental Justice in Minority Populations and Low-Income Populations

The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adve rse human health or environmental effects on minority, low-income or indigenous populations. The EPA has determined this because the rulemaking increases the level of environmental pro tection for all affected populations without having any disproportionately high and adverse huma n health or environmental effects on any population, including any minority, low-income or i ndigenous populations. The EPA has provided meaningful participation opportunities for minority, low-income, indigenous populations and tribes during the pre-proposal peri od by conducting community calls and webinars. Additionally, the EPA will conduct outrea ch for communities after the rulemaking is
finalized.6-1 6 COMPARISON OF BENEFITS AND COSTS

Tables 6-1 though Table 6-3 present the summary of the benefits, costs, and net benefits for the NSPS across regulatory options. Table 6-4 p rovides a summary of the direct and secondary emissions changes for each regulatory opt ion.

Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 2020 and 2025 (2012$)
2020 2025
Total Monetized Benefits 1 $200 million $470 million
Total Costs 2 $150 million $310 million
Net Benefits 3 $43 million $160 million

Non-monetized Benefits Non-monetized climate benefits Non-monetized climat e benefits
Health effects of PM 2.5 and ozone exposure from 120,000 tons of VOC

reduced Health effects of PM 2.5 and ozone exposure from 170,000 tons of VOC

reduced Health effects of HAP exposure from 310 tons of HAP reduced Health effects of HAP exposure from 1,900 tons of HAP reduced Health effects of ozone exposure from 170,000 tons of methane Health effects of ozone exposure from 340,000 tons of methane Visibility impairment Visibility impairment Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four di fferent estimates of the social cost of methane (SC -CH 4 ) (model average at 2.5 percent discount rate, 3 perc ent, and 5 percent; 95 th percentile at 3 percent). For purposes of this table, we show the benefits associated with th e model average a 3 percent discount rate. However, we emphasize the importance and value of considering t he benefits calculated using all four SC-CH 4 estimates; the additional benefit estimates range from $89 million to $530 million in 2020 and $220 million to $1,200 million in 2025 for the proposed option, as shown in Section 4 .3. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4. 7 for details.
2 The engineering compliance costs are annualized usi ng a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 p ercent discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate. 3 Estimates may not sum due to independent rounding.6-2

Table 6-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 (Proposed Option) in 2020 and 2025 (2012$)
2020 2025
Total Monetized Benefits 1 $200 to $210 million $460 to $550 million
Total Costs 2 $150 to $170 million $320 to $420 million

Net Benefits 3 $35 to $42 million $120 to $150 million

Non-monetized Benefits Non-monetized climate benefits
Health effects of PM 2.5 and ozone exposure from 120,000 tons of VOC

reduced Non-monetized climate benefits
Health effects of PM 2.5 and ozone exposure from 170,000 to 180,000 tons of VOC reduced Health effects of HAP exposure from 310 to 400 tons of HAP reduced Health effects of ozone exposure from 170,000 to 180,000 tons of methane Health effects of HAP exposure from 1,900 to 2,500 tons of HAP reduced Health effects of ozone exposure from 340,000 to 400,000 tons of methane Visibility impairment Visibility impairment Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four di fferent estimates of the social cost of methane (SC -CH 4 ) (model average at 2.5 percent discount rate, 3 perc ent, and 5 percent; 95 th percentile at 3 percent). For purposes of this table, we show the benefits associated with th e model average a 3 percent discount rate. However, we emphasize the importance and value of considering t he benefits calculated using all four SC-CH 4 estimates; the additional benefit estimates range from $88 million to $550 million in 2020 and $220 million to $1,400 million in 2025 for the proposed option, as shown in Section 4 .3. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 3.8 to 4.0 million metric tons in 20 20 and 7.7 to 9.0 million metric tons in 2025. Also , the specific control technologies for the proposed NSPS are anti cipated to have minor secondary disbenefits. See Se ction 4.7 for details. 2 The engineering compliance costs are annualized usi ng a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 p ercent discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate. 3 Estimates may not sum due to independent rounding.6-3

Table 6-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in 2020 and 2025 (2012$)
2020 2025 Total Monetized Benefits 1 $220 million $640 million Total Costs 2 $210 million $680 million Net Benefits 3 $7.6 million -$35 million

Non-monetized Benefits Non-monetized climate benefits Non-monetized climat e benefits Health effects of PM 2.5 and ozone exposure from 130,000 tons of VOC

reduced Health effects of PM 2.5 and ozone exposure from 200,000 tons of VOC

reduced Health effects of HAP exposure from 510 tons of HAP reduced Health effects of HAP exposure from 3,200 tons of HAP reduced Health effects of ozone exposure from 190,000 tons of methane Health effects of ozone exposure from 470,000 tons of methane Visibility impairment Visibility impairment Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four di fferent estimates of the social cost of methane (SC -CH 4 ) (model average at 2.5 percent discount rate, 3 perc ent, and 5 percent; 95th percentile at 3 percent). For purposes of this table, we show the benefits associated with the model average at a 3 percent discount rate. Ho wever we emphasize the importance and value of considering t he benefits calculated using all four SC-CH 4 estimates; the additional benefit estimates range from $99 million to $590 million in 2020 and $300 million to $1,700 million in 2025 for this more stringent option, as shown in Se ction 4.3. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 4.2 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.
2 The engineering compliance costs are annualized usi ng a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 p ercent discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate. 3 Estimates may not sum due to independent rounding.6-4

Table 6-4 Summary of Emissions Changes across Optio ns for the NSPS in 2020 and 2025 (short tons per year, unless otherwise noted)
Option 1 Proposed

Option 2 (Low) Proposed

Option 2 (High) Option 3
Pollutant 2020 2025 2020 2025 2020 2025 2020 2025 Change in Direct Emissions Methane 170,000 340,000 170,000 340,000 180,000 400 ,000 190,000 470,000

VOC 120,000 170,000 120,000 170,000 120,000 180,000 130,000 200,000 HAP 310 1,900 310 1,900 400 2,500 510 3,200

Change in Secondary Emissions CO 2 610,000 750,000 610,000 750,000 610,000 750,000 61 0,000 750,000

NOx 310 380 310 380 310 380 310 380 PM 10 11 10 11 10 11 10 11 CO 1,700 2,100 1,700 2,100 1,700 2,100 1,700 2,100 THC 640 790 640 790 640 790 640 790

Net Change in CO 2 Eq. Emissions CO 2 Eq.

(million short tons) 4.2 8.5 4.2 8.5 4.4 9.9 4.7 12

CO 2 Eq. (million metric tons) 3.8 7.7 3.8 7.7 4.0 9.0 4.2 11

Note: Totals may not sum due to independent roundin g.7-1

7 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSM ENTS

7.1 Introduction

This section includes three sets of analyses for th e proposed NSPS:

• Energy System Impacts

• Initial Regulatory Flexibility Analysis

• Employment Impacts

7.2 Energy System Impacts Analysis

We use the National Energy Modeling System (NEMS) t o estimate the impacts of the proposed NSPS on the U.S. energy system. The impact s 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 proposed rule might alter the mix of fuels consumed at a national level. The EPA only mo deled the energy system impacts of the high impact case of the proposed NSPS with respect the l ow production exemption from the well site fugitive emissions requirements. As such the NEMS-b ased estimates of energy system impacts are likely high end estimates.

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 presenting results. Economically, it is possible to view the recovered natural gas as an explicit output or as contributing to an efficiency gain in production at the producer level. For example, the analysis for the proposed rule shows that perfo rming reduced emissions completions on hydraulically-fractured oil wells contributes about 75 percent of the natural gas captured by emissions controls in 2020 and about 32 percent of captured natural gas in 2025. The fugitive emissions program at well sites is expected to capt ure about 18 percent of the natural gas captured by emissions controls in 2020 and about 52 percent of captured natural gas in 2025.

The assumed $4/Mcf price for natural gas is the pri ce paid to producers at the wellhead. In the natural gas industry, production is metered at or very near to the wellhead, and producers7-2

are paid based upon this metered production. Depend ing on the situation, the gas captured by a REC is sent through a temporary or permanent meter. Payments for the gas are typically made within 30 days.

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 revenues for representative units. On the other hand, NEMS models the profit maximizing behavior of repre sentative project developers at a drilling project level. The net costs of the regulation alte r the expected discounted cash flow of drilling and implementing oil and gas projects, and the beha vior of the representative drillers adjusts accordingly. While in the regulatory case natural g as drilling has become more efficient because of the gas recovery, project developers still inter act 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 re venues from selling recovered gas (engineering costs) and measured by cost savings fr om 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 (DOE). NEMS is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the energy economy from the current year to 2040. DOE first de veloped NEMS in the 1980s, and the model has undergone frequent updates and expansion since. DOE uses the modeling system extensively to produce issue reports, legislative analyses, and respond to Congressional inquiries.

EIA is legally required to make the NEMS system sou rce code available and fully documented for the public. The source code and acco mpanying 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.7-3

NEMS models the dynamics of energy markets and thei r interactions with the broader U.S. economy. The system projects the production of energy resources such as oil, natural gas, coal, and renewable fuels, the conversion of 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 gove rned 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.gov/forecasts/aeo/ >.

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 NEMS solves a singl e 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 2040. For this RIA, we draw upon the same assumptions and model us ed in the Annual Energy Outlook 2014. 74
The RIA baseline is consistent with that of the Ann ual Energy Outlook 2014 which is used extensively in Section 2 in the Industry Profile.

7.2.2 Inputs to National Energy Modeling System

To model potential impacts associated with the prop osed rule, 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 pro duction from onshore, offshore, Alaskan wells, as well as having a smaller-scale tr eatment of Canadian oil and gas production (U.S. EIA, 2014). The treatment of oil and gas reso urces 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

74 Assumptions for the 2014 Annual Energy Outlook can be found at
< http://www.eia.gov/forecasts/aeo/assumptions/ >.7-4

extracted resources exceeds expected costs, includi ng costs associated with capital, exploration, development, production, and taxes. Detailed techno logy 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 proposed NSPS. We are able to target additional expenditures for environmental controls required by the NSPS on new exploratory and developmental oil and g as production activities. We model the impacts of additional environmental costs, as well as the impacts of additional product recovery. We explicitly model the additional natural gas reco vered when implementing the proposed rule.

While the oil production simulated by the OGSM is s ent to the refining module (the Liquid Fuels Market Module), simulated natural gas production is sent to a transmission and distribution network captured in the NGTDM. The NGT DM 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 is transported through a simplified arc-node represent ation of pipeline infrastructure based upon pipeline economics.

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 for hydraulically frac tured oil well completions are added to the drilling and completion costs of oil wells in the O GSM.

Other costs are operations and maintenance-type cos ts and are added to fixed operation and maintenance (O&M) expenses associated with new projects. The additional expenses are estimated and entered on a per well basis, dependin g on whether the costs would apply to oil wells or natural gas wells. We base the per well co st estimates on the engineering costs. Because we model natural gas recovery, we do not include re venues from additional product recovery in these costs. This approach is appropriate given the structure of the NEMS algorithm that estimates the net present value of drilling project s.7-5

One caveat in introducing new cost requirements int o the model is that potential barriers to obtaining capital may not be adequately incorpor ated in the model. However, in general, potential barriers to obtaining additional capital should be reflected in the annualized cost via these barriers increasing the cost of capital. With this in mind, assuming the estimates of capital costs and product recovery are valid, the NEMS resu lts will reflect barriers to obtaining the required capital. A caveat to this is that the esti mated unit-level capital costs of controls that are newly required at a national-level as a result of t he regulation may not incorporate potential additional transitional costs as the supply of cont rol equipment adjusts to new demand.

Table 7-1 shows the incremental compliance that acc rue to new drilling projects as a result of producers having to comply with the NSPS, across sources anticipated in 2020 and
2025. We estimate those costs as a function of new wells expected to be drilled in a representative year. To arrive at estimates of the per well costs, we first identify whether costs will apply primarily to crude oil wells, to natural gas wells, or to both crude oil and natural gas
wells.

Based on the baseline projections of successful com pletions in 2020, we used 35,404 new crude oil wells and 8,456 new natural gas wells as the basis of these calculations. We then divide the estimated compliance costs for the given emissi ons point by the appropriate number of expected new wells in the year of analysis. The res ult yields an approximation of per well compliance costs. We assume this approximation is r epresentative of the incremental cost faced by a producer when evaluating a prospective drillin g project (Table 1).

Hydraulically fractured oil wells completions and f ugitives at oil and natural gas well sites differ slightly from this approach. Drilling and completion costs of new hydraulically fractured oil wells are incremented by the weighted average of the cost of performing a REC with completion combustion and completion combustio n alone. The resulting cost is itself weighted by the proportion of new hydraulically fra ctured oil wells estimated to be affected by the regulation (70 percent).

Meanwhile, assuming there is an average of two well s per wells site (see TSD for more details), new oil and gas wells face an increased a nnual cost of one-half of implementing the well site fugitive emission requirements.7-6

Table 7-1 Per Well Costs for Environmental Controls Entered into NEMS (2012$)

Emissions Sources/Points Wells Applied To in NEMS Annualized

Cost per Unit (2012$) Per New

Well Costs Applied in NEMS (2012$) Gas

Recovery per Unit (Mcf) Per New

Well Gas Recovery Applied in NEMS (Mcf) Well Completions
Hydraulically Fractured Oil Well Completions New Hydraulically Fractured Oil Wells $17,182 / $3723 $7,067 0 0

Fugitive Emissions Oil Production Well Sites New Oil Wells $2,144 $1, 072 38 19 Natural Gas Production Well Sites New Gas Wells $2,144 $1,072 158 79 Gathering and Boosting Stations New Gas Wells $14,028 $430 1,222 37 Transmission Stations New Gas Wells $13,879 $10 1 ,938 1 Storage Facilities New Gas Wells $21,049 $37 5,10 7 9 Reciprocating Compressors Transmission Stations New Gas Wells $1,748 $5 1,1 22 3 Storage Facilities New Gas Wells $2,077 $11 1,130 6 Centrifugal Compressors Storage Facilities New Gas Wells $114,146 $13 0 0 Pneumatic Controllers - Transmission and Storage Stations New Gas Wells $25 $1 0 0 Pneumatic Pumps Well Sites New Wells $285 $19 0 0 Reporting and Recordkeeping New Wells $1,381,023* $31 0 0

* Note: reporting and recordkeeping costs are assumed to be equally allocated across all new wells.

7.2.2.2 Adding Averted Methane Emissions into Natural Gas P roduction

A result of controlling methane and VOC emissions f rom oil and natural gas production
is that methane that would otherwise be lost to the atmosphere can be directed into the natural gas production stream. We chose to model methane ca pture in NEMS as an increase in natural gas industry productivity, ensuring that, within th e model, natural gas reservoirs are not decremented by production gains from methane captur e. We add estimates of the quantities of methane captured (or otherwise not vented or combus ted) to the base quantities that the OGSM model supplies to the NGTDM model. We subdivide the estimates of commercially valuable averted emissions by region and well type in order to more accurately portray the economics of implementing the environmental technology. Adding t he averted methane emissions in this7-7

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.

We enter the increased natural gas recovery into NE MS on a per-well basis for new natural gas wells, following an estimation procedur e similar to that of entering compliance costs into NEMS on a per-well basis for new wells (Table 7-1). For this analysis, however, we were unable to incorporate the natural gas recovery from performing RECs on hydraulically fractured oil well completions or from other emissions contro l activities at oil well sites. We hope to make
this modification in the RIA for the final rule.

7.2.3 Energy System Impacts

As mentioned earlier, we estimate impacts to drilli ng activity, price and quantity changes in the production of crude oil and natural gas, and changes in international trade of crude oil and natural gas. 75 In each of these estimates, we present estimates f or the baseline years of 2020 and 2025 and predicted results for 2020 and 2025 under the proposal. We also presented impacts over the 2020 to 2025 time period. For context, we provide estimates of production activities in 2012. With the exception of examining crude oil and natural gas trade, we focus the analysis on onshore oil and natural gas production activities i n the continental (lower 48) U.S. We do this because off-shore production is not affected by the proposed NSPS and the bulk of the proposed rule’s impacts are expected in the continental U.S.

We first report estimates of impacts on crude oil a nd natural gas drilling activities and production. Table 7-2 presents estimates of success ful onshore natural gas and crude oil wells
drilled in the continental U.S.

75 The EPA only modeled the high impact case of the p roposed NSPS with respect the low production exempt ion from the well site fugitive emissions requirements. As such the NEMS-based estimates of energy system impacts are likely high end estimates.7-8

Table 7-2 Successful Oil and Gas Wells Drilled (Ons hore, Lower 48 States) Projection, 2020 Projection, 2025 Projection, 2020- 25 2012 Baseline NSPS Baseline NSPS Baseline NSPS

Successful Wells Drilled Natural Gas 10,965 20,298 20,299 24,727 24,800 142 ,764 142,638 Crude Oil 26,517 24,660 24,660 27,648 27,638 155,2 01 155,202 Total 37,482 44,959 44,959 52,375 52,438 297,965 29 7,840

% Change in Successful Wells Drilled from Baseline Natural Gas 0.00% 0.30% -0.09% Crude Oil 0.00% -0.04% 0.00% Total 0.00% 0.12% -0.04% Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption from the well site fugitive emissions requirements. Results show that the proposed NSPS will have a rel atively small impact on onshore well drilling in the lower 48 states. Drilling remains e ssentially unchanged in 2020, but increases for natural gas wells in 2025, while decreasing for cru de oil wells in 2025. The increase in natural gas well drilling in 2025 is somewhat counter-intui tive as production costs have been increased under the proposed NSPS. However, given NEMS is a d ynamic, multi-period model, it is important to examine changes over multiple time per iods. Natural gas well drilling over the 2020 to 2025 period decreases but about 120 wells total. Crude oil drilling, over the same six-year, period remains at the same levels.

Table 7-3 shows estimates of the changes in the dom estic production of natural gas and crude oil under the proposed NSPS.

Table 7-3 Annual Domestic Natural Gas and Crude Oil Production (Onshore, Lower 48 States) Projection, 2020 Projection, 2025 Projection, 2020- 25 2012 Baseline NSPS Baseline NSPS Baseline NSPS Domestic Production Natural Gas (trillion cubic feet) 22.075 26.577 26 .576 28.931 28.927 167.585 167.576 Crude Oil (million barrels/day) 4.599 7.234 7.234 7.064 7.062 7.174 7.173

Natural Gas 0.00% -0.01% -0.01% Crude Oil 0.00% -0.03% -0.01% Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption from the well site fugitive emissions requirements.7-9

As indicated by the estimated change in the new wel l drilling activities, the analysis shows that the proposed NSPS will have a relatively small impact on onshore natural gas and crude oil production in the lower 48 states. Again, production levels Drilling remains essentially unchanged in 2020, while slight declines are estima ted for 2020 for both natural gas (about 4 billion cubic feet (bcf) or about 0.01 percent) and crude oil production (about 2,000 barrels per day or 0.03 percent). Total production over the 202 0 to 2025 is also estimated to decline for natural gas (by about 9 bcf or 0.01 percent) and cr ude oil (by about 1,000 barrels per day or about 0.01 percent)

Note this analysis estimates no increase in domesti c natural gas production, despite some environmental controls anticipated to be used in re sponse to the proposed rule capture natural gas that would otherwise be emitted (8.2 bcf in 2020 an d 19 bcf in 2025). There are two sources for this difference. First, we were unable to incorpora te into the model the natural gas recovery from performing RECs on hydraulically fractured oil well completions or from other emissions control activities at oil well sites. Second, NEMS models t he adjustment of energy markets to the new slightly more costly natural gas and crude oil prod uctive activities. At the new post-rule equilibrium, producers implementing emissions contr ols are still anticipated to capture and sell the captured natural gas, and this natural gas migh t offset other production, but not so much as to make overall production increase from the baseline projections.

Table 7-4 presents estimates of national average we llhead natural gas and crude oil prices for onshore production in the lower 48 states.

Table 7-4 Average Natural Gas and Crude Oil Wellhea d Price (Onshore, Lower 48 States, 2012$)
Projection, 2020 Projection, 2025 Projection, 2020- 25 2012 Baseline NSPS Baseline NSPS Baseline NSPS Lower 48 Average Wellhead Price Natural Gas (2012$ per Mcf) 2.562 4.458 4.458 5.06 4 5.071 4.670 4.673 Crude Oil (2012$ per barrel) 94.938 92.913 92.913 104.889 104.887 98.932 98.931

% Change in Lower 48 Average Wellhead Price from Ba seline Natural Gas 0.00% 0.14% 0.06% Crude Oil 0.00% 0.00% 0.00% Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption from the well site fugitive emissions requirements.7-10

Wellhead natural gas prices for onshore lower 48 pr oduction are not estimated to change in 2020, but are estimated to increase about $0.007 per Mcf or 0.14 percent in 2025. The production weighted average price over the 2020 to 2025 period is estimated to increase by $0.003 per Mcf or about 0.06 percent. Meanwhile, we ll crude oil prices for onshore lower 48 production are not estimated to change, despite the incidence of new compliance costs from the proposed NSPS. This is likely result of both the re latively small scale of the costs of the new compliance requirements, as well as the fact that o il prices are more a function of global prices that are natural gas prices.

Meanwhile, as shown in Table 7-5, net imports of n atural gas are estimated to decline slightly in 2020 (by about 1 bcf or 0.05 percent), 2025 (by about 3 bcf or 0.09 percent), and across the 2020 to 2025 period (by about 4 bcf tota l or about 0.03 percent). Crude oil imports are estimated to not change in 2020, increase by about 1,000 barrels per day (or 0.02 percent) in 2025 or by about 2,000 barrels per day (or about 0. 02 percent) on average during the 2020 to 2025 time period.

Table 7-5 Net Imports of Natural Gas and Crude Oil Projection, 2020 Projection, 2025 Projection, 2020- 25 2012 Baseline NSPS Baseline NSPS Baseline NSPS Net Imports Natural Gas (trillion cubic feet) 1.515 -1.901 -1. 900 -3.211 -3.208 -15.371 -15.367 Crude Oil (million barrels/day) 8.432 5.781 5.781 6.004 6.005 5.914 5.916

% Change in Net Imports Natural Gas -0.05% -0.09% -0.03% Crude Oil 0.00% 0.02% 0.02% Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption from the well site fugitive emissions requirements.

7.3 Initial Regulatory Flexibility Analysis
The Regulatory Flexibility Act (RFA; 5 U.S.C.§ 601 et seq.), as amended by the Small Business Regulatory Enforcement Fairness Act (Publi c Law No. 104-121), provides that whenever an agency is required to publish a general notice of proposed rulemaking, it must prepare and make available an initial regulatory fl exibility analysis (IRFA), unless it certifies that7-11

the proposed rule, if promulgated, will not have a significant economic impact on a substantial number of small entities (5 U.S.C. § 605[b]). Small entities include small businesses, small organizations, and small governmental jurisdictions . An IRFA describes the economic impact of the proposed rule on small entities and any signifi cant alternatives to the proposed rule that would accomplish the objectives of the rule while m inimizing significant economic impacts on small entities. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory flexibility analysis (IRFA) that examines the impac t of the proposed rule on small entities along with regulatory alternatives that could minimize th at impact.

7.3.1 Reasons why Action is Being Considered
This action proposes to amend the new source perfor mance standards (NSPS) for the oil and natural gas source category by setting standard s for both methane and volatile organic compounds (VOC) for certain equipment, processes an d activities across this source category. The EPA is including requirements for methane emiss ions in this proposal because methane is a greenhouse gas (GHG), and the oil and natural gas c ategory is currently one of the country's largest emitters of methane. In 2009, the EPA found that by causing or contributing to climate change, GHGs endanger both the public health and th e public welfare of current and future generations. The EPA is proposing to amend the NSPS to include standards for reducing
methane as well as VOC emissions across the oil and natural gas source category.

7.3.2 Statement of Objectives and Legal Basis for Propose d Rules
The EPA is proposing to amend the NSPS to include s tandards for reducing methane as well as VOC emissions across the oil and natural ga s source category. Specifically, we are proposing both methane and VOC standards for severa l emission sources not currently covered by the NSPS (i.e., hydraulically fractured oil well completions, fugitive emissions from well sites and compressor stations, and pneumatic pumps). In a ddition, we are proposing methane
standards for certain emission sources that are cur rently regulated for VOC (i.e., hydraulically fractured gas well completions, equipment leaks at natural gas processing plants). With respect to certain equipment that are used across the sourc e category, the current NSPS regulates only a subset of these equipment (pneumatic controllers, c entrifugal compressors, reciprocating compressors). The proposed amendents would establis h methane standards for these equipment7-12

across the source category and extend the current V OC standards to the remaining unregulated equipment. Lastly, amendments to the current NSPS a re being proposed that improve implementation of several aspects of the current st andards. These improvements result from reconsideration of certain issues raised in petitio ns for reconsideration that were received by the Administrator on the August 16, 2012, final NSPS fo r the oil and natural gas sector and related amendments. Except for the implementation improveme nts and the setting of standards for methane, these amendments do not change the require ments for operations already covered by
the current standards.

Section 111 of the CAA requires the EPA Administrat or to list categories of stationary sources that, in his or her judgment, cause or cont ribute significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. The EPA must then issue “standards of performance” for new sources in such source categories. The EPA has the authority to define the source categories, determin e the pollutants for which standards should be developed, and identify within each source category the facilities for which standards of performance would be established.

CAA Section 111(a)(1) defines “a standard of perfor mance” as “a standard for emissions of air pollutants which reflects the degree of emis sion limitation achievable through the application of the best system of emission reductio n which (taking into account the cost of achieving such reduction and any nonair quality hea lth and environmental impact and energy requirement) the Administrator determines has been adequately demonstrated.” This definition makes clear that the standard of performance must b e based on controls that constitute "the best system of emission reduction... adequately demonstrat ed". The standard that the EPA develops, based on the BSER, is commonly a numerical emission s limit, expressed as a performance level (e.g., a rate-based standard). Generally, the EPA d oes not prescribe a particular technological system that must be used to comply with a standard of performance. Rather, sources generally can select any measure or combination of measures t hat will achieve the emissions level of the
standard.

Standards of performance under section 111 are iss ued for new, modified and reconstructed stationary sources. These standards a re referred to as “new source performance7-13

standards.” The EPA has the authority to define the source categories, determine the pollutants for which standards should be developed, identify t he facilities within each source category to be
covered and set the emission level of the standards

. CAA section 111(b)(1)(B) requires the EPA to “at le ast every 8 years review and, if appropriate, revise” performance standards unless t he “Administrator determines that such review is not appropriate in light of readily avail able information on the efficacy” of the standard. When conducting a review of an existing p erformance standard, the EPA has discretion
to revise that standard to add emission limits for pollutants or emission sources not currently regulated for that source category.

7.3.3 Description and Estimate of Affected Small Entities
The industry sectors covered by the final rule were identified during the development of the engineering cost analysis. The EPA conducted th is regulatory flexibility analysis at the ultimate (i.e., highest) level of ownership, evalua ting parent entities. 76 The EPA identified the size of ultimate parent entities by using the Small Business Administration (SBA) size threshold guidelines. 77 The criteria for size determination vary by the or ganization/operation category of the ultimate parent entity, as follows:
Table 7-6 SBA Size Standards by NAICS Code NAICS Codes NAICS Industry Description Size Standards (in millions of dollars) Size Standards (in no. of employees) 211111 Crude Petroleum and Natural Gas Extraction - 500 211112 Natural Gas Liquid Extraction - 500 213111 Drilling Oil and Gas Wells - 500 213112 Support Activities for Oil and Gas Operation s $38.5 - 486110 Pipeline Transportation of Crude Oil - 1,500 486210 Pipeline Transportation of Natural Gas $27.5 - Sources: U.S. Census Bureau, Statistics of U.S. Bus inesses, 2012. http://www.census.gov/econ/susb/. SB A Size Standards, 13 CFR 121. 201
We have projections of future potentially affected activities at an aggregate level, but identifying impacts on specific entities is challen ging because of the difficulty of predicting

76 See Section 2.6 of this RIA for more information o n oil and natural gas industry firm characteristics and a breakdown of firms by size at the national level.
77 U.S. Small Business Administration (SBA). 2014. Sm all Business Size Standards. Effective as of July 1 4, 2014. See: http://www.sba.gov/sites/default/files/Size_St andards_Table.pdf.7-14

potentially affected new or modified source at the firm level. Because of these limitations, we based the analysis in this IRFA on impacts estimate s for the proposed requirements for hydraulically fractured and re-fractured oil well c ompletions and well site fugitive emissions. We are able to do this because the base year activity counts for the impacts estimates (as described in the TSD) for this rule were based on detailed infor mation for 2012 in a dataset of U.S. wells. The proprietary DrillingInfo dataset contains a variety of information including oil, condensate, and natural gas production levels, geographic locations , as well as basin and formation information, and information about owners/operators of wells, am ong other data fields. 78 As described in the TSD sections on hydraulically fractured and re-frac tured oil well completions and fugitive emissions, we used the DrillingInfo dataset to iden tify and estimate all wells that were completed in 2012, as well as completions of hydraulically fr acture or re-fractured oil wells. 79 We used the field called “common operator” to identify the owne r/operator of all wells in this set of new or
modified 2012 wells.
While the IRFA does not incorporate potential impac ts from other provisions of the proposed NSPS, the completions and fugitive emissio ns provisions represent about 97 percent and 94 percent of the estimated compliance costs of the proposed NSPS in 2020 and 2025, respectively (Table 7-7). Note incorporating impact s from other provisions in this analysis is a limitation, but the EPA believes that detailed anal ysis of the two provisions impacts on small entities is illustrative of impacts on small entiti es from the proposed rule in its entirety.

78 DrillingInfo is a private company that provides in formation and analysis to the energy sector. More i nformation is available at: http://info.drillinginfo.com. 79 The TSD for this proposed rule provides informatio n on this dataset of U.S. wells. Additional details on the development of this dataset can also be found in th e following docketed memo: Memorandum to Mark de Figueiredo, EPA, from Casey MacQueen and Jessica Gr ay, ERG. “DrillingInfo Processing Methodology”. August 27, 2014.7-15

Table 7-7 Distribution of Estimated Compliance Cost s across Sources Annualized Costs (With Product Recovery, 2012$) 2020 2020 (%) 2025 2025 (%)
Hydraulically-fractured and Re-fractured Oil Well Completions and Recompletions $120,000,000 71% $120,000,000 29%

Fugitive Emissions at Well-sites 1 $43,000,000 25% $270,000,000 64% Other Sources $5,800,000 3% $30,000,000 7% Total Annualized Costs of Proposed NSPS $170,000,00 0 100% $420,000,000 100%

1 Estimates for fugitive emissions requirements base d on “high impact” case. Note: sums may not total due to independent roundin g. To identify potentially affected entities under the proposed NSPS, the EPA combined ownership information from the DrillingInfo dataset with information drawn from the Hoover’s Inc. online platform, which includes information ab out companies NAICS codes, employee counts, and sales information. 80 Note that this analysis assumes that the firms per forming potentially affected activities are also the firms performing activities in the future under the proposed NSPS. While likely true for many firms, th is will not be the case for all firms.
The EPA matched owner/operators from the DrillingIn fo dataset to companies in a database developed from a download of oil and gas c ompanies in Hoover’s online database. The EPA matched as many records as possible. In the ins tances where the DrillingInfo owner/operator was not the highest level or company ownership, we recorded the highest level of owner as was identifiable in Hoovers. Linking these two datasets yields information on the NAICS, employee levels, and revenues of the owner/o perators shown in the DrillingInfo dataset
to have new or modified wells in 2012.

The EPA then used the NAICS codes associated with t he matched owner/operators to determine which owner/operators should be considere d to be small entities for this analysis, based on the SBA size standards above. That said, m any DrillingInfo owner/operators had no match in Hoovers. Additionally, some Hoovers record s lacked the information (employees or revenues, depending on the NAICS) needed to make a size determination. We initially classified
these as an “unknown” size. See Table 7-8 for a sum mary of results of this matching exercise.

80 The Hoover’s Inc. online platform includes company records that can contain NAICS codes, number of employees, revenues, and assets. For more informati on, see: http://www.hoovers.com.7-16

Table 7-8 No. of Completions in 2012 by Preliminary Firm Size Number of Completions, 2012 Firm Size Performing Well Completions No. of Firms Hydraulically Fractured or Re-fractured Oil Wells All Completions Small 1,000 3,300 12,000 Not Small 67 10,000 21,000 Unknown 1,100 750 6,000 Total 2,200 14,000 39,000 Note: consistent with the cost and emissions analys is, these 2012 completion counts do not include com pletions in states where there are state rules with similar req uirements as the proposed rules. Counts slightly lo wer than totals included in impacts analysis base year estimates as some completions have no owner/operator recorded i n the dataset. Sums may not total due to independent roun ding.

Upon analysis of the firms of unknown size, the EPA observed that, on average, the firms of unknown size perform fewer well completions. For this reason, we made the observation that the firms of unknown size are more likely to be sma ll than not small. To proceed with the analysis, we reclassified these firms as small, res ulting in the distribution presented in the first
two columns of Table 7-9.
Table 7-9 No. of Completions in 2012 by Firm Size No. of Completions, 2012 Firm Size Performing Well Completions No. of Firms Hydraulically Fractured or Re-fractured Oil Wells All Completions Small 1,100 to 2,200 4,000 7,800 to 18,000 Not Small 66 to 67 10,000 15,000 to 21,000 Total 1,200 to 2,200 14,000 23,000 to 39,000 Note: consistent with the cost and emissions analys is, these 2012 completion counts do not include com pletions in states where there are state rules with similar req uirements as the proposed rules. Counts slightly lo wer than totals included in impacts analysis base year estimates as some completions have no owner/operator recorded i n the dataset. Sums may not total due to independent roun ding.

The proposed NSPS provides an exclusion for low pro ducing sites from the fugitive emissions requirements. 81 A low production site is defined by the average co mbined oil and natural gas production for the wells at the site be ing less than 15 barrels of oil equivalent (boe) per day. 82 While the EPA is proposing an exclusion from fugit ive emission requirements for low production well sites, there is uncertainty in how many well sites this exclusion might affect in the future. As a result, the analyses in this IRFA, like the RIA, presents a “low” impact case and

81 In the preamble to the proposed rule, EPA is solic iting comment on excluding low production sites fro m the fugitive emissions program. 82 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels o f crude oil equals 1000 cubic feet natural gas.7-17

“high” impact case for fugitive emissions requireme nts at well sites. The low impact case excludes an estimate low production sites, based on the first month of production data from wells newly completed or modified in 2012.The high impact case includes these well sites. Table 7-9 presents the number of wells completed in the base year of 2012, where the range of wells under the fugitive emissions requirements reflects the ra nge of the low and high impact cases. Note that while the number of firms potentially affected goes down substantially, the low production exclusion from fugitive emissions requirements does not affect the number of affected oil well completions.

7.3.4 Compliance Cost Impact Estimates

7.3.4.1 Methodology for Estimating Impacts on Small Entitie s This section describes how we project the 2012 base year estimates of incrementally affected facilities to 2020 and 2025 levels, how we estimate costs at the firm level from these activity estimates, and how we estimated sales for small entities when available data on sales are incomplete.

New and modified hydraulically fractured oil well c ompletions and well sites in this IRFA are based on the same growth rates used to pro ject future activities as described in the TSD and consistent with other analyses in this RIA. The se growth rates are consistent with the drilling activity in the 2014 Annual Energy Outlook. These g rowth rates are applied to the 2012 base year estimates for each firm in the database. Table 7-10 and Table 7-11 present future year estimates of incrementally affected new and modifie d sources, in the low and high impact cases, respectively.

Table 7-10 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, Low Impact Fugitive Emissions Case

No. of Incrementally Affected Sources,

2020 No. of Incrementally Affected Sources, 2025 Firm Size Performing Well Completions Hydraulically

Fractured or Refractured Oil Wells Gas Well

Sites Oil Wells

Sites Hydraulically

Fractured or Refractured Oil Wells Gas Well

Sites Oil Wells

Sites Small 4,100 980 3,400 4,200 6,900 20,000 Not Small 11,000 2,800 5,900 11,000 20,000 35,000 Total 15,100 3,780 9,300 15,200 26,900 55,000 Note: Sums may not total due to independent roundin g. Assumes well sites have two wells apiece.7-18

Table 7-11 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, High Impact Fugitive Emissions Case

No. of Incrementally Affected Sources,

2020 No. of Incrementally Affected Sources, 2025
Firm Size Performing Well Completions Hydraulically

Fractured or Re-fractured Oil Wells Gas Well

Sites Oil Wells

Sites Hydraulically

Fractured or Re-fractured Oil Wells Gas Well

Sites Oil Wells

Sites Small 4,100 1,900 7,900 4,200 13,000 48,000 Not Small 11,000 3,600 8,700 11,000 25,000 52,000 Total 15,100 5,500 16,600 15,200 38,000 100,000 Note: Sums may not total due to independent roundin g. Assumes well sites have two wells apiece. This approach assumes that no other firms perform p otentially affected activities and firms performing these activities in 2012 will cont inue to do so in 2020 and 2025. Again, the analysis in this IRFA is meant to be illustrative o f impacts on small entities. Exact predictions of future activities at the firm level is not possible

. Once the future year activities were estimated we a llocated compliance costs across small entities based upon the costs estimated in the TSD and consistently with other analyses in this
RIA. These cost estimates include estimates of reve nue from natural gas recovery at the assumed value of $4/Mcf in 2012 dollars, again consistent w ith other analyses in this RIA. For hydraulically fractured and re-fractured oil well c ompletions, we assumed each small entity is required to perform RECs/completions and completion s in the same proportions assumed in the TSD and RIA. We also assumed the same proportion wo uld be exploratory or delineation wells
as the TSD and RIA. Table 7-12 shows the distributi on of compliance costs estimates across firm size, year, and whether the low production exemptio n is in place.

Table 7-12 Distribution of Estimated Compliance Cos ts 1 across Firm Size Classes

Annualized Compliance Costs (2012$)

Low Impact Case Annualized Compliance Costs (2012$) High Impact Case Firm Size No. of Firms 2020 2025 No. of Firms 2020 2025 Small 1,100 43,000,000 88,000,000 2,200 54,000,000 160,000,000 Not Small 66 100,000,000 190,000,000 67 110,000,000 240,000,000 Total 1,200 150,000,000 280,000,000 2,200 170,000,0 00 390,000,000

1 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-f ractured oil well completions and well-site fugitive emissions. As described in Section 7.1.3, these provisions acc ount for the large majority of the rule’s potential impact in 20 20 and 2025. Note: sums may not total due to independent roundin g.7-19

In order to estimate the cost-to-sales ratio, we ag ain combined information from Hoovers and the DrillingInfo databases. The Hoovers databas e has sales information for some, but not all, small entities estimated in this IRFA analysis to h ave impacts. To supplement the sales information, we estimated 2012 sales by multiplying 2012 oil and natural gas production levels reported in the DrillingInfo database by assumed oi l and natural gas prices at the wellhead. For natural gas, we assumed the same $4/Mcf for natural gas. 83 For oil prices, we estimated revenues using two alternative prices, $70/bbl and $50/bbl. In the results, we call the case using $70/bbl the “primary scenario” and the case using the $50/b bl as the “low oil price scenario”. 84 In the instances where the 2012 production-derived revenue s exceeded the Hoovers revenues, we replaced the Hoovers estimate with the production-d erived estimate as more likely to be an
accurate estimate of sales for 2012.

7.3.4.2 Results

This section presents results of the cost-to-sales ratio analysis for both the primary scenario and the low oil price scenario. In additio n, we present both scenarios for the low and high impact cases with respect to the low productio n exemption from the well site fugitive emissions requirements.

83 The U.S. Energy Information Administration’s 2015 Annual Energy Outlook projects 2020 Henry Hub natur al gas prices to be $4.88/MMBtu in its reference case and $4.30/MMBtu in its “low oil” price case in 2013 dol lars. Available at: http://www.eia.gov/beta/aeo/#/?id=14- AEO2015. After adjusting to $/Mcf (using the conver sion of 1 MMBtu = 1.208 Mcf) in 2012 dollars (using the GDP -Implicit Price Deflator), these prices are $4.94/M cf in the reference case and $4.35/Mcf in the low oil pri ce case. Rounding down to $4/Mcf would likely under

estimated sales. 84 The 2015 Annual Energy Outlook projects wellhead o il prices to be $75.16/bbl in its reference case an d $54.10/bbl in its “low oil” price case in 2013 doll ars. Available at: http://www.eia.gov/beta/aeo/#/?i d=14- AEO2015. After adjusting to 2012 dollars (using the GDP-Implicit Price Deflator), these prices are $74 .00/bbl in the reference case and $53.27/bbl in the low oil pr ice case. Rounding down to $4/Mcf would likely unde restimated sales.7-20

Table 7-13 Compliance Costs-to-Sales 1 Ratios (Fugitive Emissions Requirements Low Impact Case) across Firm Size Classes for Primary S cenario and Low Oil Price Scenario 2 2020 (Primary Scenario) 2020 (Low Oil Price Scenari o)
No. of Small Entities % of Small

Entities No. of Small

Entities % of Small

Entities No. of Small Entities 1,200 - 1,200 - Greater than 1 percent 66 6% 77 7% Greater than 3 percent 22 2% 25 2%

2025 (Primary Scenario) 2025 (Low Oil Price Scenari o)
No. of Small Entities % of Small

Entities No. of Small

Entities % of Small

Entities No. of Small Entities 1,200 - 1,200 - Greater than 1 percent 130 11% 160 13% Greater than 3 percent 44 4% 53 5%

1 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-f ractured oil well completions and well-site fugitive emissions. These provisions account for the large majority of the rule’s potential impact in 2020 and 2025.
2 In the main case, the wellhead prices are assumed to be $4/Mcf for natural gas and $70/bbl for crude oil. In the low oil price case, the wellhead prices are assumed to be $4/Mcf for natural gas and $50/bbl for crude oil

.
Table 7-14 Compliance Costs-to-Sales 1 Ratios (Fugitive Emissions Requirements Low Impact Case) across Firm Size Classes for Primary S cenario and Low Oil Price Scenario 2 2020 (Primary Scenario) 2020 (Low Oil Price Scenari o)
No. of Small Entities % of Small

Entities No. of Small

Entities % of Small

Entities No. of Small Entities 2,100 - 2,100 - Greater than 1 percent 270 13% 320 15% Greater than 3 percent 120 6% 140 7%

2025 (Primary Scenario) 2025 (Low Oil Price Scenari o)
No. of Small Entities % of Small

Entities No. of Small

Entities % of Small

Entities No. of Small Entities 2,100 - 2,100 - Greater than 1 percent 710 33% 800 38% Greater than 3 percent 370 17% 410 20%

1 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-f ractured oil well completions and well-site fugitive emissions. As described in Section 7.1.3, these provisions acc ount for the large majority of the rule’s potential impact in 20 20 and 2025. 2 In the main case, the wellhead prices are assumed to be$4/Mcf for natural gas and $70/bbl for crude o il. In the low oil price case, the wellhead prices are assumed to be$4/Mcf for natural gas and $50/bbl for crude oil.

Comparing Table 7-13 with Table 7-14, about 900 few er small entities are estimated to be affected by the examined provision in the low im pact fugitive emissions requirements case.7-21

Cost-to-sales ratios exceeding 1 percent and 3 perc ent are also reduced from the high impact to low impact case without the exemption in place by a pproximately two-thirds. The percent impacted by greater than 3 percent is about double the percent affected by greater than 1 percent for each year of analysis in the primary and in the low oil price scenarios. Meanwhile, impacts greater than 1 percent and 3 percent increase in th e low oil price scenarios, as would be expected. Also as expected the cost-to-sales ratios with rati os greater than 1 percent and 3 percent increase
from 2020 to 2025 as affected sources accumulate un der the proposed NSPS.

7.3.5 Caveats and Limitations
The analysis above is subject to a number of caveat s and limitations, many of which we discussed in the presentation of methods and result s. It is useful, however, to present a complete
list of the caveats and limitation here.

• Because of data limitations, the analysis presented in the IRFA only examines impacts on requirements for hydraulically fractured and re- fractured oil well completions and well site fugitive emissions. While impacts from th ese requirements constitute a large proportion of the estimated impacts from the propos ed NSPS, the omission of the cost requirements of other requirements leads to a relat ive under-estimation of the impacts on small entities. Also, the impacts from other req uirements may affect firms that are not drilling wells, such as pipeline transmission f irms.

• Not all owner/operators listed in the DrillingInfo database could be identified in the Hoovers database. These owner/operators tend to hav e developed relatively few new or modified wells in 2012. As a result, we assumed these were small entities, whereas these entities may actually be subsidiaries of larg er enterprises. While the impacts estimates are not affected in the aggregate by this assumption, the assumption likely leads to an over-estimate of the impact on small en tities for the provisions examined.

• The analysis assumes the same population of entitie s completing wells in 2012 are also completing wells in 2020 and 2025, according to gro wth rates developed for the entire sector. In the future, many of these firms will com plete fewer or more wells, and other firms will complete wells. All of these firms combi ned may complete new or modified wells at higher or lower rates depending on economi cs and technological factors that are largely unpredictable.

• The approach used to estimate sales for the cost-to -sales might over-estimate or underestimate sales depending upon the accuracy of the i nformation in the underlying databases and the market prices ultimately faced in 2020 and 2025.

7.3.6 Projected Reporting, Recordkeeping and Other Compli ance Requirements The information to be collected for the proposed NS PS is based on notification,7-22

performance tests, recordkeeping and reporting requ irements which will be mandatory for all operators subject to the final standards. Recordkee ping and reporting requirements are specifically authorized by section 114 of the CAA ( 42 U.S.C. 7414). The information will be used by the delegated authority (state agency, or R egional Administrator if there is no delegated state agency) to ensure that the standards and othe r requirements are being achieved. Based on
review of the recorded information at the site and the reported information, the delegated permitting authority can identify facilities that m ay not be in compliance and decide which facilities, records, or processes may need inspecti on. All information submitted to the EPA pursuant to the recordkeeping and reporting require ments for which a claim of confidentiality is made is safeguarded according to Agency policies se t forth in 40 CFR part 2, subpart B.

Potential respondents under subpart OOOOa are owner s or operators of new, modified or reconstructed oil and natural gas affected faciliti es as defined under the rule. None of the facilities in the United States are owned or operat ed by state, local, tribal or the Federal government. All facilities are privately owned for- profit businesses. The requirements in this action result in industry recording keeping and rep orting burden associated with review of the requirements for all affected entities, gathering r elevant information, performing initial performance tests and repeat performance tests if n ecessary, writing and submitting the notifications and reports, developing systems for t he purpose of processing and maintaining information, and train personnel to be able to resp ond to the collection of information.

The estimated average annual burden (averaged over the first 3 years after the effective date of the standards) for the recordkeeping and re porting requirements in subpart OOOOa for the 2,552 owners and operators that are subject to the rule is 92,658 labor hours, with an annual average cost of $3,163,699. The annual public repor ting and recordkeeping burden for this collection of information is estimated to average 3 .9 hours per response. Respondents must monitor all specified criteria at each affected fac ility and maintain these records for 5 years. Burden is defined at 5 CFR 1320.3(b).

7.3.7 Related Federal Rules
The New Source Performance Standards (NSPS) issued in 2012 are currently reducing
VOC emissions from several sources in the oil and n atural gas industry In addition to the 20127-23

NSPS, there are two National Emission Standards for Hazardous Air Pollutants (NESHAP) rules that apply to certain equipment and processes in th e oil and natural gas sector. These rules, listed below, address air toxics, primarily benzene, tolue ne, ethylbenzene and xylenes (collectively referred to as BTEX) and n-hexane. These two rules, which were updated concurrently with the 2012 NSPS, were promulgated under section 112 of th e Clean Air Act and are codified in 40
CFR Part 63:

• Subpart HH – Crude Oil and Natural Gas Production ( including processing); and

• Subpart HHH – Natural Gas Transmission and Storage.
Additionally, 40 CFR Part 98 Subpart W is a greenho use gas reporting requirement that applies to petroleum and natural gas systems. Owner s or operators of facilities that contain petroleum and natural gas systems and emit 25,000 m etric tons or more of GHGs per year from process operations, stationary combustion, miscella neous use of carbonates, and other source categories are required to report emissions from al l source categories located at the facility for
which emission calculation methods are defined in t he rule. Owners or operators are required to collect emission data; calculate GHG emissions; and follow the specified procedures for quality assurance, missing data, recordkeeping, and reporti ng.

7.3.8 Regulatory Flexibility Alternatives

The Panel agrees that the EPA should explore regula tory alternatives and provide flexibility where appropriate. This flexibility can lessen impacts to small entities as well as
entities not classified as small.

7.3.8.1 Oil Well Exemptions
SERs encouraged the EPA to exempt stripper wells, l ow pressure oil wells, and any well that requires artificial lift. SERs recommended tha t the EPA establish an overall applicability threshold based on production, emissions, well dept h, well type (horizontal), well pressure, formation, or revenue to limit potential impact of future regulations on small entities.

The SERs offered several threshold alternatives to be applied to the oil well completion requirements which would significantly reduce compl iance costs and burden to small entities that the SERs asserted would not affect gas recovery ben efits. Some of these comments are described7-24

below. Advocacy believes the EPA had a greater oppo rtunity to advance the discussion by evaluating these alternatives through analysis of t he available data. Advocacy further believes that there is enough information to conduct analysi s of alternatives now. Advocacy notes that there are several types of thresholds that could be explored by the EPA, such as average production of nearby wells (by oil field, reservoir , or basin), well length or depth, and gas and water pressure characteristics. Advocacy encourages the EPA to do so in the future, in advance of proposal, to facilitate more informed and produc tive comments from the public which will lead to a better rulemaking.
The EPA has production and well characteristic data on thousands of oil wells through DrillingInfo, which aggregates all well data in the U.S. reported by operators to state agencies. In this database, the EPA could develop thresholds to target geographical areas or well characteristics with greater gas recovery potential than areas or characteristics where costs imposed would achieve little to no benefit. Advocac y believes the EPA should examine the data in DrillingInfo and the studies identified in the W hite paper for potential alternatives that minimize small entity costs, while achieving signif icant methane emission benefits. For example, Advocacy performed its own preliminary analysis of the DrillingInfo data, which led us to recommend a production threshold (see below). Advoc acy believes the EPA also should consider the peer review and public comments on the white pa per and reassess the size and diversity of the oil well completions in a more comprehensive fa shion. Advocacy believes the EPA should have provided additional analysis since the publica tion of the white paper.
The EPA believes that it has reasonably analyzed th e available data for this draft proposed rule, and sufficiently documented this ana lysis through the rule, the technical support document (TSD), and the SBREFA process. However, th e EPA notes information gaps and has requested additional data and information through t he public comment process.

Gas to Oil Ratio

Advocacy is concerned that the EPA estimate of ten tons of methane reduction per event for oil well completions may be significantly overe stimated, based on its analysis of the 2012 Drilling Info database and SER comments. The 2012 a nalysis includes hydraulically fractured oil7-25

well completions with GORs between 300 and 100,000, whereas the 2011 analysis was limited to GORs up to 12,500.
The Panel recommends that the EPA continue analyzin g current data, and assess the alternatives mentioned by SERs. In an effort to con tribute to the panel process, Advocacy analyzed the EPA data provided. Advocacy found that geographical patterns and well characteristics exist in the data to suggest common sense thresholds. While a 300 gas to oil ratio (GOR) threshold provides some relief for small enti ties, it is problematic because GOR is not known at time of fracturing when a completion takes place. Advocacy further recommends that the EPA develop a scheme based on the well characte ristics of nearby wells in the basin or reservoir to provide an estimate for the GOR parame ter. However, the location of the well, and the drill direction are known parameters that could be used. In concert with these other considerations, Advocacy recommends the EPA conside r a GOR cutoff closer to 900, as one SER suggested.
The EPA believes that a gas-to-oil ratio (GOR) of 3 00 scf of gas per barrel of oil produced is an appropriate threshold for facilities to be subject to the well completion provisions of the NSPS. The reason for the proposed threshold GOR of 300 is that separators typically do not operate at a GOR less than 300, which is based on industry experience rather than a vetted technical specification for separator performance 85 . Though, in theory, any amount of free gas could be separated from the liquid, the reality is that this is not practical given the design and operating parameters of separation units operating in the field. The EPA is soliciting comment on whether a GOR of 300 is the appropriate applicabili ty threshold. Additionally, the EPA
understands that GOR is not known at the time of we ll completion, and is soliciting comment on whether the GOR of nearby wells would be a reliable indicator in determining the GOR of a new
or modified well.

Low Production Wells

When mapping average daily associated gas of 90 Mcf or above (isolating stripper wells) using county level data, Advocacy found that most ( 85%) of these greater gas recovery oil well

85 On February 24, 2015, API submitted a comment to t he EPA stating that oil wells with GOR values less than 300 do not have sufficient gas to operate a separator.7-26

completions occur in about a third of the counties analyzed. Advocacy contends that there are potentially large areas that could be exempted from this requirement without forgoing significant methane emission reduction, or at least phased in t o allow time to design proper data collection. For example, PIOGA comments report an average gas v olume of only 74 MCFD in Pennsylvania stripper oil wells in contrast to Penn sylvania stripper gas wells averaging 532
MCFD.
The EPA understands that low production wells have inherently low emissions from well completions and many are owned and operated by smal l businesses. However, the EPA recognizes that identification of these wells prior to completion events is difficult, especially considering that drilling of a low production well may be unintentional and may be infrequent, but production may nevertheless proceed due to econ omic reasons. The EPA is soliciting
comment and information on emissions associated wit h low production wells, characteristics of these wells and supporting information that would h elp owners/operators and enforcement personnel identify these wells prior to completion.
Because of these preliminary findings about low pro duction and a lack of evidence that there will be sufficient gas recovery, the Panel re commends that the EPA further analyze and consider exempting low production wells (with an av erage daily production of less than 15 barrel equivalents) from a REC or combustion requirement d uring oil well completions.

Vertical Wells

According to a SER comment, vertical wells lack suf ficient wellhead pressure or quantity of gas to be separated during completion. Advocacy recommends that since the white papers laid the foundation to the materials prepared for the Pa nel, the EPA should revisit the information learned through this process, especially as it rela tes to the specific characteristics of vertical wells. Therefore, as a regulatory alternative, Advo cacy recommends the EPA consider exempting vertical wells from oil well completion r equirements.
The EPA clarifies that both the 2014 white paper an alysis of oil well completions and DrillingInfo data analysis include vertical wells t hat are hydraulically fractured. However, the EPA understands that there are certain physical wel l characteristics that may inhibit the operation of a separator, and notes that the rule does not re quire RECs where their use is not feasible.7-27

However, the EPA has not seen sufficient data to su pport the characterization that a separator will not be able to function for all or the majorit y of vertical wells that are hydraulically fractured. However, the EPA recommends soliciting c omment on the types of oil wells that will not be capable of performing a REC or combusting co mpletion emissions due to technical considerations such as low pressure or low gas cont ent, or other physical characteristics such as location, well depth, length of hydraulic fracturin g, or drilling direction (e.g., horizontal, vertica l, directional).

Low Pressure Oil Wells

Advocacy recommends that “low pressure wells” shoul d be categorically exempt and could be based on a threshold sales line/gathering line of approximately 250 psi or a simple water gradient formula of 0.465 psi/foot. The emiss ions associated with these types of wells are so low that even if a separator can be operated for some short period of time, the value of gas does not exceed the cost associated with bringing e quipment to the site. As the SERs indicated, these oil completion requirements can be very costl y on small firms, particularly with respect to small production wells. The expected gas recovery b enefits from oil well completions are expected to be a small fraction of the benefits obt ained by the gas wells under the current version
of the NSPS rule.
The EPA is aware that oil wells cannot perform a RE C if there is not sufficient well pressure or gas content during the well completion to operate the surface equipment required for a REC. In the 2012 NSPS the EPA did not require low pressure gas wells to perform REC, but operators were required to control those well compl etions using combustion. However, the EPA recommends soliciting comment on the types of oil w ells that will not be capable of performing a REC or combusting completion emissions due to techn ical considerations such as low pressure or low gas content, or other physical characteristi cs such as location, well depth, length of hydraulic fracturing, or drilling direction (e.g., horizontal, vertical, directional). The EPA defines low pressure wells as a well with reservoir pressur e and true vertical well depth such that 0.445 times the reservoir pressure (in psia) minus 0.038 times the vertical well depth (in feet) minus 67.578 psia is less than the flow line pressure at the sales meter. The EPA recommends soliciting comment on whether this definition is appropriate f or low pressure oil wells.7-28

Substitution of Combustion over Green Completion / REC Requirements

Advocacy recommends that the EPA substitute flaring for the green completion requirement (REC), in addition to the consideration of thresholds. This alternative is much more cost-effective, and particularly important for smal l firms to have a lower cost alternative that
achieves a 95% reduction. The PIOGA comments also s tated that the use of RECs would adversely impact the productivity and longevity of the stripper oil wells. Alternatively, the EPA could require larger firms to perform the RECs, whi le allowing smaller firms (using a firm
revenue cutoff or other small business size indicat or) to combust the remaining gas.
The EPA recommends that RECs be implemented on oil wells, except where their use is not feasible (e.g., technically infeasible for a se parator to function, availability of gathering lines). Compared to combustion alone, the EPA belie ves that the combination of REC and combustion will maximize the recovery of natural re sources and minimize venting to the atmosphere. However, the EPA notes that although th e flaring in lieu of RECs may be less costly, flaring contributes secondary environmental impacts, nuisance impacts to nearby communities and complicates compliance for owners/o perators.

Phase – In for Oil Well Completion Requirements

The Panel recommends that the EPA consider phasing in the well completion requirement over a period of years. The Panel agree s that the EPA solicit comment on whether the well completion provisions of the proposed rule can be implemented on the effective date of the rule in the event of potential shortage of REC equipment and, if not, how a phase in could be structured. The Panel agrees that a phased in appro ach could be structured to provide for control of the potentially highest emitting wells first, wi th other wells being included at a later date. The
Panel recommends that the EPA solicit comment on wh ether GOR of the well and production level of the well should be bases for the phasing o f requirements for RECs, and if so, what an appropriate threshold for phase-in should be.

7.3.8.2 Fugitives - Leak Detection Methods
SERs encouraged the EPA to allow a variety of leak detection technologies, including Method 21, AVO, and soap testing. The EPA asserts t hat use of OGI can reduce the amount of7-29

time necessary to conduct fugitive emissions monito ring since multiple fugitive emissions components can be surveyed simultaneously, reducing the cost of identifying fugitive emissions compared to alternative leak detection technologies that require a manual screening of each fugitive emissions component. Advocacy recommends t he EPA propose Method 21 or OGI as
allowable alternatives. The EPA contends that while Method 21 is lacking because it does not allow the detection of malfunctioning equipment tha t may not be the focus of the survey, and it is not as cost-effective as OGI, the Panel recommends the EPA solicits comment on whether to
allow EPA Method 21 as an alternative to OGI for mo nitoring, including the appropriate EPA Method 21 level repair threshold. The EPA notes tha t the proposed rule would allow the use either OGI or Method 21 for resurvey because the re survey would focus solely on ensuring repairs resolved the leak at the individual compone nt.

7.3.8.3 Fugitives – Survey Frequency
SERs recommended leak surveys be conducted no more than once per year. Advocacy has questions about the costs of repair and the emi ssion reductions that be achieved through increased survey frequency which Advocacy believes the EPA was unable to address satisfactorily. Advocacy urges the EPA to improve t he record basis for its emission reduction estimates and the cost of repairs for Method 21 and OGI, in order to permit more informed comment on the alternatives. Advocacy believes the EPA was unable to adequately explain the basis for the different repair costs vs. frequency for Method 21 and OGI 86 , or the basis for the 40/60/80% emission reductions based on increasing s urvey frequency from annual to quarterly. 87
The EPA determined that semiannual monitoring will result in identification and repair of significant fugitive emissions from components, and that using OGI, an operator can survey multiple fugitive emissions components simultaneous ly reducing the cost of identifying fugitive emissions. Additionally, if fugitive emissions are detected at less than one percent of the fugitive

6 At this time, the EPA shows annual repair costs tha t increase linearly with survey frequency for OGI, but are static for Method 21. For Method 21, the EPA applied the s ame repair costs whether the frequency was annual, semiannual or quarterly. For OGI, EPA used double the repair costs for semiannual, and four times the repair costs for quarterly. Advocacy believes this could l ead to a bias in an evaluation of one method vs. th e other. 87 Advocacy was also disappointed that EPA was unable to share with the SERs more information that would have help the SERs formulate their recommendations (incl uding some of the issues addressed above). The EPA believes the background documents created for the S ERs were thorough and accurate, and transparently presented the data and data sources used in the ana lysis for the proposed rule. The documents are addi tionally available for public review in the docket for the p roposed rule.7-30

emission components at a well site during two conse cutive semiannual monitoring surveys, the proposed rule allows for the monitoring survey freq uency for that well site to be reduced to annually. Advocacy had no information upon which to base a recommendation related to the proportion of leaking components, but supports anal ysis of such an approach. Advocacy also recommends that the EPA provide more analysis and f actual foundation for the record to allow commenters to provide more informed advice.
The Panel agrees that the EPA should solicit commen t on an alternate proposal option based on an initial annual survey frequency. The Pa nel recommends the EPA solicit comment on the appropriateness of semiannual monitoring freque ncy and the proposed provisions for increasing and decreasing the monitoring frequency.

7.3.8.4 Fugitive Emissions at Well Sites
The Panel recommends not requiring fugitive emissio n surveys at well production sites, unless there are potentially significant sources of emissions, such as storage tanks. The Panel further agrees that well sites with low production wells (i.e., a well with an average daily production of 15 barrel equivalents or less) should not require fugitive emission surveys.

7.3.8.5 Fugitive Emissions at Production and Processing Sit es, and Compressor Stations at Transmission and Storage Sites
Under Subpart W, gas production and processing site s and compressor stations at transmission and storage sites are required to annu ally monitor for fugitive emissions and to quantify such emissions. The only missing regulator y component to be considered is to add a requirement to repair detected leaks as appropriate . This is already covered by the May 2015 INGAA Directed Inspection and Maintenance voluntary Program for Transmission and Storage Compressor Stations. The EPA is already considering this program 88 in its recent request for comment on the voluntary methane reduction program for the oil and gas sector. Advocacy recommends that the EPA retain the annual requireme nt, as Advocacy believes this requirement is entirely duplicative of a fugitives survey requi rement, and consider the specific repair

88 US EPA. Natural Gas STAR Methane Challenge Program : Proposed Framework, slide 17 states, “EPA has received, and is considering, a proposal to structu re BMP coverage of natural gas transmission and sto rage compressor stations as a Directed Inspection and Ma intenance Program.”7-31

requirements for repair identification and repair d elay in the DI&M voluntary program as the components of a mandatory program. Furthermore, the EPA’s most recent evaluation of the survey cost-effectiveness shows that annual surveys are more cost-effective than semi-annual surveys. Therefore, the Panel recommends the EPA pr opose options based on semi-annual and annual monitoring. Advocacy recommends that the EPA should also consider allowing each facility to tailor the specific program to site-spe cific considerations, rather than apply the same requirements uniformly to each plant. The EPA recog nizes that Subpart W serves as an emissions inventory, while this rule’s intent is to minimize pollution. The EPA believes that the additional survey with semiannual OGI monitoring pr ovides additional leak detection, and costeffective emission reductions. The EPA recognizes t hat fugitive emissions may be underestimated based on emerging studies and will c ontinue to evaluate these studies. The Panel recommends the EPA propose an alternate option base d on an initial annual frequency for well
sites. The Panel recommends that the EPA continue t o consider the INGAA DI&M recommendations for leak repairs in the rulemaking.

7.3.8.6 Well Site Compressors
SERs encouraged the EPA to exempt well site compres sors as they are typically rental units and have irregular service time, and regulati on could be cost prohibitive. The Panel agrees that emissions from well site compressors were extr emely low and that cost of control of these compressors would not be reasonable. The Panel reco mmends that the EPA maintain the exemption for well site compressors.

7.3.8.7 Pneumatic Pumps
SERs encouraged the EPA to exempt pneumatic pumps i f controls were not already in place. The Panel agrees that combustion controls sh ould only be required if a control is required
for another source. The Panel recommends the EPA ex empt pneumatic pumps without a control device already located on site.

7.3.8.8 Reciprocating Compressors
The Panel supports the EPA proposal to require repl acement of rod packing every 26,000 hours or 3 years in lieu of monitoring hours. The P anel also supports the further consideration of the alternative developed in the Natural Gas Star P rogram for condition-based maintenance.7-32

Advocacy recommends the EPA should carefully study the INGAA recommendations for condition-based maintenance for rod packing as an a lternative to maintaining or replacing rod packing on a prescribed schedule. 89
The EPA recommends that the draft proposed rule ret ain the rod packing replacement options and the option to route the rod packing emi ssions to a process through a closed vent system under negative pressure.

7.3.8.9 Centrifugal Compressors
Advocacy recommends that the EPA reconsider the req uirement of requiring capture and combustion of gas emissions from wet seal compresso rs whose emissions don’t differ that much from dry seal compressors, according to INGAA. Advo cacy is concerned that requiring combustion at compressor stations would prove to be unpopular with the surrounding neighborhood. This requirement would convert an oth erwise unobtrusive structure in the neighborhood into a constant source of combustion a nd a source of air pollution.
The EPA recommends retaining the requirement for a 95% emissions reduction from wet seal compressors, which can be achieved by capturin g and routing the emissions utilizing a cover and closed vent system to a control device, or rout ing the captured emissions to a process. The EPA notes that dry seal compressors are not affecte d facilities in the draft proposed rule because of their inherently low emissions. The EPA also not es that many of these combustors are enclosed and will be innocuous to the surrounding n eighborhood. In addition, the gas liberated from the barrier fluid during degassing is very cle an natural gas, and the combustor is required under the NSPS to burn cleanly with no visible emis sions.

7.3.8.10 Pneumatic Controllers
The Panel agrees with the EPA’s recommendation that low-bleed pneumatic controllers be required in place of high-bleed controllers (i.e ., natural gas bleed rate not to exceed 6 scfh).
The Panel recommends the rule continue to treat low -bleed pneumatic controllers as not affected facilities except at natural gas processing plants, where zero bleed pneumatic controllers are
considered BSER.

89 See INGAA comment on 40 CFR 60 Part OOOO. EPA-HQ-O AR-2010-0505-41047-33

7.3.8.11 Recordkeeping and Reporting for High Bleed Controll ers The EPA recommends that owners and operators contin ue to be permitted to use high bleed controllers needed for specific functional pu rposes, but require recordkeeping to document the justification. The Panel agrees that recordkeep ing and reporting requirements should be minimized wherever possible. However, the Panel not es that a recordkeeping and reporting requirement that asks companies to justify and docu ment their need for continuous high bleed devices has caused many companies to reevaluate the ir need for and change out unnecessary high bleed pneumatic controllers.

7.3.8.12 Liquids Unloading

Based on the information and data available to the EPA during development of the 2012 NSPS, the Panel agrees that control of liquids unlo ading emissions is not appropriate at this time. However, the EPA believes that the emissions from l iquids unloading operations are significant,
and so the Panel recommends that the EPA continue t o study this issue and solicit information and data supporting demonstrated control technologi es or management practices for reducing
these emissions.

7.4 Employment Impact Analysis

In addition to addressing the costs and benefits of the proposed rule, the EPA has analyzed the impacts of this rulemaking on employme nt, which are presented in this section. 90 While a standalone analysis of employment impacts i s not included in a standard cost-benefit analysis, such an analysis is of particular concern in the current economic climate given continued interest in the employment impact of regu lations such as this proposed rule. Executive Order 13563, states, “Our regulatory system must pr otect public health, welfare, safety, and our environment while promoting economic growth, innova tion, competitiveness, and job creation.”

91 A discussion of compliance costs, including report ing and recordkeeping requirements, is included in Section 3of this RIA. This analysis use s detailed engineering information on labor

90 The employment analysis in this RIA is part of EPA ’s ongoing effort to “conduct continuing evaluation s of potential loss or shifts of employment which may re sult from the administration or enforcement of [the Act]” pursuant to CAA section 321(a). 91 Executive Order 13563 (January 21, 2011). Improving Regulation and Regulatory Review. Section 1. General Principles of Regulation , Federal Register, Vol. 76, Nr. 14, p. 3821.7-34

requirements for each of the control strategies ide ntified in this proposed rule in order to estimate partial employment impacts for affected entities in the oil and gas industry. These bottom-up, engineering-based estimates represent only one port ion of potential employment impacts within the regulated industry, and do not represent estima tes of the net employment impacts of this rule. First, this section presents an overview of the var ious ways that environmental regulation can affect employment. The EPA continues to explore the relevant theoretical and empirical literature and to seek public comments in order to ensure that the way the EPA characterizes the employment effects of its regulations is valid and informative. The section concludes with partial employment impact estimates that rely on engineerin g-based information for labor requirements for each of the control strategies identified by th e proposed rule.

7.4.1 Employment Impacts of Environmental Regulation

From an economic perspective labor is an input into producing goods and services; if a regulation requires that more labor be used to prod uce a given amount of output, that additional labor is reflected in an increase in the cost of pr oduction. Moreover, when the economy is at full employment, we would not expect an environmental re gulation to have an impact on overall employment because labor is being shifted from one sector to another. On the other hand, in periods of high unemployment, employment effects (b oth positive and negative) are possible.

For example, an increase in labor demand due to reg ulation may result in a short-term net increase in overall employment as workers are hired by the regulated sector to help meet new requirements (e.g., to install new equipment) or by the environmental protection sector to produce new abatement capital resulting in hiring p reviously unemployed workers. When significant numbers of workers are unemployed, the opportunity costs associated with displacing jobs in other sectors are likely to be higher. And, in general, if a regulation imposes high costs and does not increase the demand for labor, it may lead to a decrease in employment. The responsiveness of industry labor demand depends on how these forces all interact. Economic theory indicates that the responsiveness of industr y labor demand depends on a number of factors: price elasticity of demand for the product , substitutability of other factors of production, elasticity of supply of other factors of production , and labor’s share of total production costs. Berman and Bui (2001) put this theory in the contex t of environmental regulation, and suggest7-35

that, for example, if all firms in the industry are faced with the same compliance costs of regulation and product demand is inelastic, then in dustry output may not change much at all.

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 environmental regulations. When a regulation is promulgated, one typical response of industry is to order pollution control equipment and services in order t o comply with the regulation when it becomes effective. On the other hand, the closure of plants that choose not to comply – and any changes in production levels at plants choosing to comply and remain in operation - occur after the compliance date, or earlier in anticipation of the compliance obligation. Environmental regulation may increase revenue and employment in t he environmental technology industry. While these increases represent gains for that indu stry, they translate into costs to the regulated industries required to install the equipment.

Environmental regulations support employment in man y basic industries. Regulated firms either hire workers to design and build pollution c ontrols directly or purchase pollution control devices from a third party for installation. Once t he equipment is installed, regulated firms hire workers to operate and maintain the pollution contr ol equipment—much like they hire workers to produce more output. In addition to the increase in employment in the environmental protection industry (via increased orders for pollu tion control equipment), environmental regulations also support employment in industries t hat provide intermediate goods to the environmental protection industry. The equipment ma nufacturers, in turn, order steel, tanks, vessels, blowers, pumps, and chemicals to manufactu re and install the equipment. Currently in most cases there is no scientifically defensible wa y to generate sufficiently reliable estimates of the employment impacts in these intermediate goods sectors.

Berman and Bui (2001) demonstrate using standard ne oclassical microeconomics that environmental regulations have an ambiguous effect on employment in the regulated sector. The theoretical results imply that the effect of enviro nmental regulation on employment in the regulated sector is an empirical question and both sets of authors tested their models empirically using different methodologies. Berman and Bui (2001 ) developed an innovative approach to examine how an increase in local air quality regula tion that reduces nitrogen oxides (NO X )7-36

emissions affects manufacturing employment in the S outh Coast Air Quality Management District (SCAQMD), which incorporates Los Angeles a nd its suburbs. During the time frame of their study, 1979 to 1992, the SCAQMD enacted some of the country’s most stringent air quality regulations. Using SCAQMD’s local air quality regul ations, Berman and Bui identify the effect of environmental regulations on net employment in t he regulated industries. 92 The authors find that “while regulations do impose large costs, they have a limited effect on employment” (Berman and Bui, 2001, p. 269). Their conclusion is that local air quality regulation “probably increased labor demand slightly” but that “the empl oyment effects of both compliance and increased stringency are fairly precisely estimated zeros, even when exit and dissuaded entry effects are included” (Berman and Bui, 2001, p. 269 ). 93

While there is an extensive empirical, peer-reviewe d literature analyzing the effect of environmental regulations on various economic outco mes including productivity, investment, competitiveness as well as environmental performanc e, there are only a few papers that examine the impact of environmental regulation on employmen t, but this area of the literature has been growing. As stated previously in this RIA section, empirical results from Berman and Bui (2001) suggest that new or more stringent environmental re gulations do not have a substantial impact on net employment (either negative or positive) in the regulated sector. Similarly, Ferris, Shadbegian, and Wolverton (2014) also find that reg ulation-induced net employment impacts are close to zero in the regulated sector. Furthermore, Gray et al (2014) find that pulp mills that had to comply with both the air and water regulations i n the EPA’s 1998 “Cluster Rule” experienced relatively small and not always statistically signi ficant, decreases in employment. Nevertheless, other empirical research suggests that more highly regulated counties may generate fewer jobs than less regulated ones (Greenstone 2002, Walker 2 011). However, the methodology used in these two studies cannot estimate whether aggregate employment is lower or higher due to more stringent environmental regulation, it can only imp ly that relative employment growth in some sectors differs between more and less regulated are as. List et al. (2003) find some evidence that this type of geographic relocation, from more regul ated areas to less regulated areas may be occurring. Overall, the peer-reviewed literature do es not contain evidence that environmental

92 Berman and Bui include over 40 4-digit SIC industr ies in their sample. 93 Including the employment effect of exiting plants and plants dissuaded from opening will increase the estimated impact of regulation on employment.7-37

regulation has a large impact on net employment (ei ther negative or positive) in the long run across the whole economy.

While the theoretical framework laid out by Berman and Bui (2001) still holds for the industries affected under these emission guidelines , important differences in the markets and regulatory settings analyzed in their study and the setting presented here lead us to conclude that it is inappropriate to utilize their quantitative e stimates to estimate the employment impacts from this proposed regulation. In particular, the indust ries used in these two studies as well as the timeframe (late 1970’s to early 1990’s) are quite d ifferent than those in this proposed NSPS. Furthermore, the control strategies analyzed for th is RIA include implementing RECs, reducing fugitive emissions, and reducing emissions from pne umatic controllers, pumps, and reciprocating and centrifugal compressors, which are very differe nt than the control strategies examined by
Berman and Bui. 94 For these reasons we conclude there are too many u ncertainties as to the transferability of the quantitative estimates from Berman and Bui to apply their estimates to quantify the employment impacts within the regulate d sectors for this regulation, though these studies have usefulness for qualitative assessment of employment impacts.

The preceding sections have outlined the challenges associated with estimating net employment effects in the regulated sector and in t he environmental protection sector. These challenges make it very difficult to accurately pro duce net employment estimates for the whole economy that would appropriately capture the way in which costs, compliance spending, and environmental benefits propagate through the macro- economy. Given the difficulty with estimating national impacts of regulations, the EPA has not generally estimated economy-wide employment impacts of its regulations in its benefi t-cost analyses. However, in its continuing effort to advance the evaluation of costs, benefits , and economic impacts associated with environmental regulation, the EPA has formed a pane l of experts as part of the EPA’s Science Advisory Board (SAB) to advise the EPA on the techn ical merits and challenges of using economy-wide economic models to evaluate the impact s of its regulations, including the impact on net national employment. 95 Once the EPA receives guidance from this panel it will carefully

94 More detail on how emission reductions expected fr om compliance with this rule can be obtained can be found in Section 3 of this RIA. 95 For further information see: http://yosemite.epa.gov/sab/sabproduct.nsf/0/07E67C F77B54734285257BB0004F87ED?OpenDocument7-38

consider this input and then decide if and how to p roceed on economy-wide modeling of employment impacts of its regulations.

7.4.2 Labor Estimates Associated with Proposed Requiremen ts

Section 2 of the RIA, in Tables 2-17 and 2-18, pres ents background information on employment and wages in the oil and natural gas ind ustry. As well as producing much of the U.S. energy supply, the oil and natural gas industr y directly employs a significant number of people. Table 2-17 shows employment in six oil and natural gas-related NAICS codes from 1990
to 2013. 96 The overall trend shows a decline in total industr y employment throughout the 1990s, hitting a low of 314,000 in 1999, but rebounding to a 2013 peak of 620,000. Crude Petroleum and Natural Gas Extraction (NAICS 211111) and Suppo rt Activities for Oil and Gas Operations (NAICS 213112) employ the majority of workers in th e industry. From 1990 to 2013, average wages for the oil and natural gas industry have inc reased. Table 2-18 shows real wages (in 2012 dollars) from 1990 to 2013 for the NAICS codes asso ciated with the oil and natural gas industry.

The focus of this part of the analysis is on labor requirements related to the compliance actions for the proposed rule, of the affected enti ties within the oil and natural gas sector. We do not estimate any potential changes in labor outside of the affected sector, and, due to data and methodology limitations, we do not estimate net emp loyment impacts for the affected sector, apart from the partial estimate of the labor requir ements related to control strategies. This analysis estimates the labor required to the instal l, operate, and maintain control equipment and activities, as well as to perform new reporting and recordkeeping requirements.

It is important to highlight that unlike the typica l case where to reduce output negative production externality (i.e., emissions) a firm oft en has to reduce production, many of the emission controls required by the proposed NSPS wil l simultaneously increase production and reduce negative externalities. That is, these contr ols jointly produce environmental improvements and increase output in the regulated s ector. New labor associated with implementing these controls to comply with the new regulations can also be viewed as additional labor increasing output while reducing undesirable emissions. To the extent, however, that these

96 NAICS 211111, 21112, 213111, 213112, 486110, and 4 86210.7-39

rules may require unprofitable investments for some operators, there is a possibility that these producers decrease output in response and create do wnward pressure on labor demand, both in the regulated sector and on those sectors using nat ural gas as an input. This RIA does not include quantified estimates of these potential adverse eff ects on the labor market due to data and theoretical challenges, as described above.

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 the EPA does not currently have this information. The labor requirem ents analysis uses a bottom-up engineeringbased methodology to estimate employment impacts. T he engineering cost analysis summarized in Chapter 3 of this RIA includes estimates of the labor requirements associated with implementing the regulations. Each of these labor c hanges may either be required as part of an initial effort to comply with the new regulation or required as a continuous or annual effort to maintain compliance. We estimate up-front and conti nual, annual labor requirements by estimating hours of labor required and converting t his number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks). We note that this type of FTE estimate cannot be used to make assumptions about t he specific number of people involved or whether new jobs are created for new employees.

The results of this employment analysis of the prop osed NSPS are presented in Tables 7- 16 through Table 7-19 for 2020 and 2025 for individ ual sources regulated under this proposal. Table 7-20 presents summary-level labor impacts for all sources. The tables break 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. The labor information is based upon the cost analys is presented in the TSD that supports this proposal, based upon analysis presented in the RIA developed for the 2012 NSPS and NESHAP Amendments for the Oil and Natural Gas Sector (U.S. EPA, 2012). In addition, for the proposed NSPS, reporting and recordkeeping requirements were estimated for the entire rule rather than by anticipated control requirements; the reporting and recordkeeping estimates are consistent with estimates the EPA submitted as part of its Informat ion Collection Request (ICR), the estimated costs of which are included in the cost estimates p resented in Chapter 3.7-40

Table 7-15 presents estimates labor requirements fo r hydraulically fractured oil well completions. The REC and completion combustion requ irements are associated with certain new and existing oil well completions. While individual completions occur over a short period of time (days to a few weeks), new wells and other exi sting wells are completed annually. Because of these reasons, we assume the REC-related labor r equirements are annual.

The per-unit estimates of one-time labor requiremen ts associated with implementing RECs and completion combustion are drawn from the l abor requirements estimated for implementing RECs on hydraulically fractured well c ompletions in EPA (2012). However, the labor requirements in that report were based upon a completion that is assumed to last seven days (218 hours per completion for a REC or 22 hours lab or per completion for completion combustion). In this analysis, completion events fo r hydraulically fractured oil wells are assumed to last three days, so we multiply the seven-day re quirements by 3/7 (93 hours per completion for a REC or 9 hours labor per completion for completio n combustion).7-41

Table 7-15 Estimates of Labor Required to Comply wi th Proposed NSPS for Hydraulically Fractured Oil Well Completions, 2020 and 2025

Emissions Source Emissions

Control Projected

No. of Incr. Affected Units Per-unit

Onetime Labor Est. (hrs) Per-unit

Annual Labor Est. (hrs) Total

OneTime Labor Estimate (hrs) Total

Annual Labor Estimate (hrs) Onetime FTE Annual

FTE 2020 Hydraulically Fractured and Re-fractured Oil Well Completions Development Oil Wells Reduced

Emission Completion 6,903 0 93 0 644,937 0 310

Wildcat and Delineation Oil Wells Completion

Combustion 7,773 0 9 0 73,289 0 35

Total 14,676 N/A N/A 0 718,227 0 345

2025 Hydraulically Fractured and Re-fractured Oil Well Completions Development Oil Wells Reduced

Emission Completion 6,901 0 93 0 644,751 0 310

Wildcat and Delineation Oil Wells Completion

Combustion 8,066 0 9 0 76,055 0 37

Total 14,967 N/A N/A 0 720,806 0 347 Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per-unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals ma y not sum due to independent rounding. Table 7-16 and Table 7-17 present estimates of labo r requirements for the low and the high impacts cases for fugitive emissions. Consiste nt with the cost estimates for fugitive emissions presented in the TSD, we estimate labor a ssociated with company-level activities and activities at field sites. Company-level activities include one time activities such as planning the company’s fugitive emissions program and annual req uirements such as reporting and recordkeeping. Field-level activities include semia nnual inspection and repair of leaks as proposed. It is important to note, however, that th e compliance costs estimates for leak inspection were based upon an estimate of the costs to hire a contractor to provide the inspection service, but the source providing this information does not have a breakdown of the labor component of the rental cost. As a result, the labo r requirements for the fugitives program are likely underestimates.7-42

Table 7-16 Estimates of Labor Required to Comply wi th Proposed NSPS for Fugitive Emissions, Low Impact Case, 2020 and 2025

Emissions Source/ Emissions Control Projected

No. of Incr. Affected Units Per-unit

Onetime Labor (hrs) Per-unit

Annual Labor (hrs) Total

OneTime Labor (hrs) Total

Annual Labor (hrs) Onetime FTE Annual

FTE 2020 Well Sites Company-level Activities Semiannual

Monitoring/ Maintenance 605 118.0 0.0 71,352 0 34 0
Site-level Activities 13,303 0.0 14.1 0 187,717 0 9 0 Gathering and Boosting Stations Company-level Activities Semiannual

Monitoring/ Maintenance 259 118.0 0.0 30,562 0 15 0
Site-level Activities 259 0.0 108.7 0 28,141 0 14 Transmission Compressor Stations Company-level Activities Semiannual

Monitoring/ Maintenance 6 118.0 0.0 708 0 0 0

Site-level Activities 6 0.0 108.7 0 652 0 0 Storage Compressor Stations Company-level Activities Semiannual

Monitoring/ Maintenance 15 118.0 0.0 1,770 0 1 0
Site-level Activities 15 0.0 212.9 0 3,193 0 2
Total 13,583 N/A N/A 104,392 219,702 50 106 2025 Well Sites Company-level Activities Semiannual

Monitoring/ Maintenance 1,004 118.0 0.0 118,429 0 57 0
Site-level Activities 139,108 5.4 14.1 0 1,962,940 0 944 Gathering and Boosting Stations Company-level Activities Semiannual

Monitoring/ Maintenance 259 118.0 0.0 30,562 0 15 0
Site-level Activities 1,554 0.0 108.7 0 168,844 0 8 1 Transmission Compressor Stations Company-level Activities Semiannual

Monitoring/ Maintenance 6 118.0 0.0 708 0 0 0
Site-level Activities 36 0.0 108.7 0 3,911 0 2 Storage Compressor Stations Company-level Activities Semiannual

Monitoring/ Maintenance 15 118.0 0.0 1,770 0 1 0
Site-level Activities 90 0.0 212.9 0 19,160 0 9
Total 140,788 N/A N/A 151,469 2,154,855 73 1,036 Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals ma y not sum due to independent rounding.7-43

Table 7-17 Estimates of Labor Required to Comply wi th Proposed NSPS for Fugitive Emissions, High Impact Case, 2020 and 2025

Emissions Source/ Emissions Control Projected

No. of Incr. Affected Units Per-unit

Onetime Labor (hrs) Per-unit

Annual Labor (hrs) Total

OneTime Labor (hrs) Total

Annual Labor (hrs) Onetime FTE Annual

FTE 2020 Well Sites Company-level Activities Semiannual

Monitoring/ Maintenance 1,004 118.0 0.0 118,429 0 57 0
Site-level Activities 22,080 0.0 14.1 0 311,569 0 1 50 Gathering and Boosting Stations Company-level Activities Semiannual

Monitoring/ Maintenance 259 118.0 0.0 30,562 0 15 0
Site-level Activities 259 0.0 108.7 0 28,141 0 14 Transmission Compressor Stations Company-level Activities Semiannual

Monitoring/ Maintenance 6 118.0 0.0 708 0 0 0

Site-level Activities 6 0.0 108.7 0 652 0 0 Storage Compressor Stations Company-level Activities Semiannual

Monitoring/ Maintenance 15 118.0 0.0 1,770 0 1 0
Site-level Activities 15 0.0 212.9 0 3,193 0 2
Total 22,360 N/A N/A 151,469 343,555 73 165 2025 Well Sites Company-level Activities Semiannual

Monitoring/ Maintenance 1,004 118.0 0.0 118,429 0 57 0
Site-level Activities 139,108 5.4 14.1 0 1,962,940 0 944 Gathering and Boosting Stations Company-level Activities Semiannual

Monitoring/ Maintenance 259 118.0 0.0 30,562 0 15 0
Site-level Activities 1,554 0.0 108.7 0 168,844 0 8 1 Transmission Compressor Stations Company-level Activities Semiannual

Monitoring/ Maintenance 6 118.0 0.0 708 0 0 0
Site-level Activities 36 0.0 108.7 0 3,911 0 2 Storage Compressor Stations Company-level Activities Semiannual

Monitoring/ Maintenance 15 118.0 0.0 1,770 0 1 0
Site-level Activities 90 0.0 212.9 0 19,160 0 9
Total 140,788 N/A N/A 151,469 2,154,855 73 1,036 Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals ma y not sum due to independent rounding.7-44

Most labor required for fugitive emissions is neede d at well sites in the field, which number in the thousands. Note that the labor requir ements estimates increase from 2020 to 2025 as the number of sites regulated under the proposed NSPS accumulates.

Table 7-18 presents labor requirement estimates for reciprocating and centrifugal compressors. Like the estimates for completions, th e per unit labor estimates were based on EPA (2012). As relatively little labor is required for reciprocating compressors and relatively few affected centrifugal compressors are expected in th e future, the estimates of both one-time and on-going labor requirements for compressor requirem ents are minimal.

Table 7-18 Estimates of Labor Required to Comply wi th Proposed NSPS for Reciprocating and Centrifugal Compressors, 2020 and 2025

Emissions Source Emissions Control Projected

No. of Incr. Affected Units Per-unit

Onetime Labor Est. (hrs) Per-unit

Annual Labor Est. (hrs) Total

OneTime Labor Estimate (hrs) Total

Annual Labor Estimate (hrs) Onetime FTE Annual

FTE

2020 Compressors
Reciprocating Monitoring and Maintenance 67 1 1 67 67 0.0 0.0

Centrifugal Route to

Control 1 355 0 355 0 0.2 0.0
Total 68 N/A N/A 422 67 0.2 0.0

2025 Compressors
Reciprocating Monitoring and Maintenance 402 1 1 67 402 0.0 0.2

Centrifugal Route to

Control 6 355 0 355 0 0.2 0.0
Total 408 N/A N/A 422 402 0.2 0.2 Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals ma y not sum due to independent rounding. Table 7-19 presents the labor requirement estimates for requirements applying to pneumatic controllers and pneumatic pumps. Note tha t pneumatic controllers have no one-time or continuing labor requirements. While the control s do require labor for installation, operation, and maintenance, the required labor is less than th at of the controllers that would be used absent7-45

the regulation (U.S. EPA, 2012). In this instance, we assume the incremental labor requirements are zero. Meanwhile, we are currently unable to est imate the labor associated with pneumatic pump control activities.

Table 7-19 Estimates of Labor Required to Comply wi th Proposed NSPS for Pneumatic Controllers and Pumps, 2020 and 2025

Emissions Source Emissions

Control Projected

No. of Incr. Affected Units Per-unit

Onetime Labor Est. (hrs) Per-unit

Annual Labor Est. (hrs) Total

OneTime Labor Estimate (hrs) Total

Annual Labor Estimate (hrs) Onetime FTE Annual

FTE

2020 Pneumatic Controllers Emissions

Limit 210 0 0 0 0 0 0

Pneumatic Pumps Route to

Control 2,962 N/A N/A N/A N/A N/A N/A

2025
Pneumatic Controllers Emissions

Limit 1,260 0 0 0 0 0 0

Pneumatic Pumps Route to

Control 17,772 N/A N/A N/A N/A N/A N/A
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals ma y not sum due to independent rounding. Table 7-20 presents the labor estimates across all emissions sources. Two main categories contain the majority of the labor requirements for the proposed NSPS: implementing reduced emissions completions (REC) at hydraulically fractu re oil well completions and fugitive emissions detection and repair at well sites. The u p-front labor requirement to comply with the proposed NSPS is estimated at 73 FTEs in 2020 and i n 2025. The annual labor requirement to comply with proposed NSPS is estimated at about 530 FTEs in 2020 and 1,400 FTEs in 2025. We note that this type of FTE estimate cannot be us ed to identify the specific number of people involved or whether new jobs are created for new em ployees, versus displacing jobs from other sectors of the economy.7-46

Table 7-20 Estimates of Labor Required to Comply wi th Proposed NSPS, 2020 and 2025

Emissions Source Projected No. of Incrementally Affected Units (2020) Total OneTime Labor Estimate (hours) Total

Annual Labor Estimate (hours) One-time

FTE Annual

FTE

2020Hydraulically Fractured and Refractured Oil Well Completions 15,000 0 720,000 0 350
Fugitive Emissions 14,000 to 22,000 100,000 to

150,000 220,000 to

340,000 50 to 73 110 to 170
Pneumatic Controllers 210 0 0 0 0 Pneumatic Pumps 3,000 N/A N/A N/A N/A Reciprocating Compressors 67 67 67 0 0 Centrifugal Compressors 1 360 0 0 0 Reporting and Recordkeeping Requirements All 0 40,000 0 19 Total 31,000 to 40,000 100,000 to

150,000 980,000 to

1,100,000 50 to 73 470 to 530

2025Hydraulically Fractured and Refractured Oil Well Completions 15,000 0 720,000 0 350
Fugitive Emissions 86,000 to 140,000 100,000 to

150,000 1,400,000 to

2,200,000 50 to 73 660 to 1,000 Pneumatic Controllers 1,300 0 0 0 0 Pneumatic Pumps 18,000 N/A N/A N/A N/A Reciprocating Compressors 400 67 400 0 0 Centrifugal Compressors 6 360 0 0 0 Reporting and Recordkeeping Requirements All 0 120,000 0 58 Total 120,000 to 180,000 100,000 to

150,000 2,200,000 to

3,000,000 50 to 73 1,100 to 1,400 Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Rounded t o two significant digits. Totals may not sum due to indep endent rounding.

7.5 References
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Gray, W.B., R.J. Shadbegian, C. Wang, and M. Meral. 2014. “Do EPA Regulations Affect Labor Demand? Evidence from the Pulp and Paper Industry.” Journal of Environmental Economics and Management : 68, 188-202.
Greenstone, M. 2002. “The Impacts of Environmental Regulations on Industrial Activity: Evidence from the 1970 and 1977 Clean Air Act Amend ments and the Census of Manufactures.” Journal of Political Economy 110(6): 1175-1219.
List, J. A., D. L. Millimet, P. G. Fredriksson, and W. W. McHone. 2003. “Effects of Environmental Regulations on Manufacturing Plant Bi rths: Evidence from a Propensity Score Matching Estimator.” The Review of Economics and Statistics 85(4): 944-952.

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U.S. Environmental Protection Agency (U.S. EPA). 20 12. Regulatory Impact Analysis: Final New Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry. <http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natur al_gas_final_neshap_nsps_ria.pdf> Accessed December 19, 2014.U.S. Small Business Admi nistration (U.S. SBA), Office of Advocacy. 2010. A Guide for Government Agencies, How to Comply with the Regulatory Flexibility Act, Implementing the President’s Small Business Agenda and Executive Order 13272

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Environmental Protection Agency Office of Air Quality Planning and Standards Health and Environmental Impacts Division Research Triangle Park, NC Publication No. EPA-452/R-15-002 August 2015