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EO12866 _O&GNSPS 2060 AS30 RIA_ 20150 803 619



# Regulatory Impact Analysis of the Proposed

Emission Standards for New and Modified Sources in the Oil and Natural Gas Sector

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ii [ This page intentionally left blank]

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iii EPA

- 452/R

- 15

- 002

, August July 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 27711

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iv CONTACT INFORMATION

This document has been prepared by staff from the Office 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 Air and Radiation , personnel from the U.S. EPA
Office of Policy

, EC/R Incorporated

, and ICF International contributed data and anal ysis to this
document.

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v TABLE OF CONTENTS

T ABLE OF 

### C ONTENTS



### ................................ ................................ ................................ ..................... V


### L IST OF 

### T ABLES



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


### L IST OF 

### F IGURE S



### ................................ ................................ ................................ ............................ X


### 1 E XECUTIVE 

### S UMMARY


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

- 1

1.1 B ACKGROUND

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

- 1 1.2 M ARKET F AILURE

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

- 3 1.3 S UMMARY OF R ESULTS

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

- 3 1.4 O RGANIZATION OF THIS R EPORT

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

- 8


### 2 I NDUSTRY 

### P ROFILE


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

- 1

2.1 I NTRODUCTION

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

- 1 2.2 P RODUC TS 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 Natura l 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

- 25 2.4.5 Forecasts

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

- 27 2.5 I NDUSTRY C OSTS

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

- 31

2.5.1 Finding Costs

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

- 31 2.5.2 Lifting Costs

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

- 33 2.5.3 Operating and Equipment Costs

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

- 34 2.6 F IRM C HARACTERISTICS

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

- 36

2.6.1 Ownership

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

- 37 2.6.2 Size Distribution of Firms in Affected NAICS

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

- 37 2.6.3 Trends in National Employment and Wages

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

- 38 2.6.4 Horizontal and Vertical Integration

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

- 40 2.6.5 Firm

- level Information

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

- 42 2.6.6 Financial Performance and Condition

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

- 46 2.7 R EFERENCES

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

- 50


### 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

- 6

3.4.1 Control Options

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

- 6 3.4.2 Projection of Incrementally Affected Facilities

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

- 9

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vi 3.4.3 Emissions Reductions

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

- 11 3.4.4 Product Recovery

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

- 11 3.4.5 Engineering Compliance Costs

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

- 13 3.4.6 Cost

- Effectiveness

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

- 14 3. 4.7 Comparison of Regulatory Alternatives

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

- 18 3.5 C OMPLIANCE C OSTS E STIMATED USING 3 AND 7 P ERCENT D ISCOUNT R ATES

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

- 21 3.6 D ETAILED I MPACTS T ABLES

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

- 21


### 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

- 6

4.3.1 Methane climate effects and valuation

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

- 6 4.4 VOC AS A PM 2.5 PRECURSOR

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

- 18

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

- 33 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

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

- 2 5.4 U NFUNDED M ANDATES R EFORM A CT

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

- 2 5.5 E XECUTIVE O RDER 13132: F EDERALISM

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

- 2 5.6 E XECUTIVE O RDER 13175: C ONSULTATION AND C OORDINATION WITH I NDIAN T RIBAL G OVERNMENTS

.... 5

- 3 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

- 4 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

- 4 5.9 N ATIONAL T ECHNOLOGY T RANSFER AND A DVANCEMENT A CT

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

- 6 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 OPULATI ONS

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

- 6


### 6 C OMPARISON OF 

### B ENEFITS AND 

### C OSTS



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

- 1

7 E CONOMIC 

### I MPACT 

### A NALYSIS AND 

### D ISTRIBUTIONAL 

### A SSESSMENTS



### ............................... 7

- 1

7.1 I NTRODUCTION

................................ ................................ ................................ ................................ ............ 7

- 1 7.2 E NERGY S YSTEM I MPACTS A NALYSIS

................................ ................................ ................................ .......... 7

- 1

7.2.1 Description of the Department of Energy National Energy Modeling System

................................ .. 7

- 2 7.2.2 Inputs to National Energy Modeling System

................................ ................................ ..................... 7

- 3

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vii 7.2.2.1 Compliance Costs for Oil and Gas Exploration and Production

................................ .............. 7

- 4 7.2.2.2 Adding Averted Methane Emissions into Natural Gas Production

................................ .......... 7

- 6 7.2.3 Energy System Impacts

................................ ................................ ................................ ..................... 7

- 7 7.3 S MALL E NTITY A NALYSIS

................................ ................................ ................................ .......................... 7

- 10 7.4 E MPLOYMENT I MPACT A NALYSIS

................................ ................................ ................................ .............. 7

- 10

7.4.1 Employment Impacts of Environmental Regulation

................................ ................................ ........ 7

- 11 7.4.2 Labor Estimates Associated with Proposed Requirements

................................ .............................. 7

- 15 7.5 R EFERENCES

................................ ................................ ................................ ................................ .............. 7

- 22

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viii LIST OF TABLES

Table 1

- 1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed Option in 2020 and 2025 (2012$) 1

- 6 Table 1

- 2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Less Stringent Option in 2020

a nd 2025 (2012$)

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

- 7 Table 1

- 3 Summary of the Monetized Benefits, Costs, and Net Benefits for the More Stringent Option in 2020 and 2025 (2012$)

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

- 8 Table 2

- 1 Technically Recoverable Crude Oil and Natural Gas Resource

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

- 10 Table 2

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

- 2013

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

- 11 Table 2

- 3 Crude Oil and Dry Natural Gas Proved Reserves by State, 2013

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

- 13 Table 2

- 4 Crude Oil Domestic Production, Wells, Well Productivity, 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 Development Wells and Average Depth, 1990

- 2010 2

- 17 Table 2

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

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

- 18 Table 2

- 8 U.S. Oil and Natur al Gas Pipeline Mileage, 2010

- 2013

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

- 20 Table 2

- 9 Crude Oil Consumption by Sector, 1990

- 2012

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

- 22 Table 2

- 10 Natural Gas Consumption by Sector, 1990

- 2012

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

- 24 Table 2

- 11 Total Crude Oil and Petroleum Products Trade (Million Bbl),

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

- 26 Table 2

- 12 Natural Gas I mports and Exports, 1990

- 2013

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

- 27 Table 2

- 13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010

- 2040

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

- 28 Table 2

- 14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2011

- 2040

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

- 29 Table 2

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

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

- 31 Table 2

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

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

- 38 Table 2

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

- 2013

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

- 39 Table 2

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

- 2013 (2012 dollars)

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

- 40 Table 2

- 19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012

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

- 44 Table 2

- 20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009

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

- 45 Table 2

- 21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2012

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

- 46 Table 2

- 22 Selected Financial Items from Income Statements (Billion 2008 Dollars)

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

- 48 Table 2

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

. 2

- 49 Table 2

- 24 Income and Production Taxes, 1990

- 2009 (Million 2008 Dollars)

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

- 50 Table 3

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

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

- 8 Table 3

- 2 Number of Incrementally Affected Sources for the N SPS, All Options

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

- 10 Table 3

- 3 Emissions Reductions from Proposed NSPS, 2020 and 2025

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

- 11 Table 3

- 4 Estimated Natural Gas Recovery (Mcf) in 2020 and 2025

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

- 13 Table 3

- 5 Engineering Compliance Cost Estimates in 2020 and 2025

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

- 14 Table 3

- 6 Engineering Compliance Cost

- Effectiveness Estimates in 2020 and 2025, Single Pollutant Approach 3

- 17 Table 3

- 7 Engineering Compliance Cost

- Ef fectiveness Estimates in 2020 and 2025, Multipollutant Approach 3

- 18 Table 3

- 8 Comparison of Regulatory Alternatives

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

- 19 Table 3

- 9 Annualized Costs using 3 and 7 Percent Discount Rates for the Proposed NSPS in 2020 and 2025

.. 3

- 21 Table 3

- 10 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020

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

- 22 Table 3

- 11 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025

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

- 25 Table 3

- 12 Incrementally Affected Units, Emissions Reductions and Costs, Selected Option 2, 2020

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

- 28 Table 3

- 13 Incrementally Affected Units, Emissions Reductions and Costs, Selected Option 2, 2025

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

- 31 Table 3

- 14 Incrementally Aff ected Units, Emissions Reductions and Costs, Option 3, 2020

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

- 33 Table 3

- 15 Incrementally Affected Units, Emissions Reductions an d Costs, Option 3, 2025

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

- 35 Table 4

- 1 Climate and Human Health Effects of Emission Reductions from this Proposal

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

- 2 Table 4

- 2 Direct Emission Reductions from the Proposed NSPS 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.

, 2015 b ) 4

- 14

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ix Table 4

- 4 Estimated Global Benefits of Methane Reductions* (in 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 year)

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

- 36 Table 4

- 7 Summary

- level Secondary Air Pollutant Impacts Associated with Controls, across Regulatory Options (short tons per year)

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

- 37 Table 4

- 8 Summary of Emissions Changes (short tons per year, except where noted)

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

- 38 Table 6

- 1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed NSPS in 2020 and 2025 6

- 1 Table 6

- 2 Summary of the Monetized Benefit s, Costs, and Net Benefits for the Less Stringent Option for the NSPS in 2020 and 2025 (2012$)

................................ ................................ ................................ ............................... 6

- 2 Table 6

- 3 Summary of the Monet ized Benefits, Costs, and Net Benefits for the More Stringent Option for the NSPS in 2020 and 2025 (2012$)

................................ ................................ ................................ ............................... 6

- 3 Table 6

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

................................ ................................ ................................ ................................ ............. 6

- 4 Table 7

- 2 Successful Oil and Gas Wells Drilled (Onshore, Lower 48 States)

................................ ................... 7

- 8 Table 7

- 3 Annual Domestic Natural Gas and Crude Oil Production (Onshore, Lower 48 States)

.................... 7

- 8 Table 7

- 4 Average Natural Gas and Crude Oil Wellhead Price (Onshore, Lower 48 States, 2012$)

................ 7

- 9 Table 7

- 5 Net Imports of Natural Gas and Crude Oil

................................ ................................ ...................... 7

- 10 Table 7

- 6 Estimates of Labor Required to Comply with Proposed NSPS for Hydraulically Fractured Oil Well Completions, 2020 and 2025

................................ ................................ ................................ ................................ ... 7

- 18 Table 7

- 7 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, 2020 and 2025 7

- 19 Table 7

- 8 Estimates of Labor Required to Comply with Proposed NSPS for Reciprocating and Centrifugal Compressors, 2020 and 2025

................................ ................................ ................................ ................................ ... 7

- 20 Table 7

- 9 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic Controllers and Pumps, 2020 and 2025 7

- 21 Table 7

- 10 Estimates of Labor Required to Comply with Proposed NSPS, 2020 and 2025

.............................. 7

- 22

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x LIST OF FIGURES

Figure 2

- 1 A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990

- 2013. B) Domestic Natural Gas Proved Reserves and Cumulative Production, 1990

- 2013

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

- 12 Figure 2

- 2 A) Total Producing Crude Oil Wells and Average Well Productiv ity, 1990

- 2011. B) Total Producing Natural Gas Wells and Average Well Productivity, 1990

- 2013.

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

- 16 Figure 2

- 3 U.S. Produced Wat er Volume by Management Practice, 2007

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

- 19 Figure 2

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

- 2011

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

- 23 Figure 2

- 5 Forecast of Domestic Crude Oil Production and Net Imports, 2010

- 2040

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

- 30 Figure 2

- 6 Costs of Crude Oil and Natural Gas Wells Drilled, 1981

- 2008

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

- 32 Figure 2

- 7 Finding Costs for FRS Companies, 1981

- 2009

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

- 33 Figure 2

- 8 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981

- 2009 (3

- year Running Average) 2

- 34 Figure 2

- 9 Crude Oil Operating Costs and Equ ipment Costs Indices (1976=100) and Crude Oil Price (in 1976 dollars), 1976

- 2009

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

- 35 Figure 2

- 10 Natural Operating Costs and Equi pment Costs Indices (1976=100) and Natural Gas Price, 1976

- 2009 2

- 36 Figure 4

- 1 Path from GHG Emissions to Monetized Damages

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

- 11 Figure 4

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

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

- 28 Figure 4

- 3 2005 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk from HAP Exposure f rom All Outdoor Sources based on the 2005 National Toxics Inventory

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

- 29

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1

- 1 1 EXECUTIVE SUMMARY

1.1 Background

The action analyzed in this regulatory impact analysis (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 compounds (VOC) for certain equipment, processes and activities across this source category

.

The Environmental Protection Agency ( EPA ) is including requirements for methane emissions in this proposal because methane is a greenhouse gas (GHG)

, and the oil and natural gas category is currently one of the country's largest emitters of methane

. I n 2009 , the EPA found that by causing or contributing to climate change, GHGs endanger both the public health and the 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. Specifically, we are proposing both methane and VOC standards for several emission sources not currently covered by the NSPS (i.e., hydraulically fractured oil well completions

, fugitive emis sions from well sites and compressor stations

, pneumatic pumps ). In addition, we are proposing methane standards for certain emission sources that are currently regulated for VOC (i.e., hydraulically fractured gas well completions, equipment leaks at natural gas processing 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 across the source category, the current

NS PS regulates only a subset of these equipment (pneumatic controllers, centrifugal compressors, reciprocating compressors ). The proposed amendents would establish methane standards for these equipment across the source category and extend the current VOC st andards to the remaining unregulated equipment. Lastly, amendments to the current NSPS are being proposed that improve several aspects of the current standards related to implementation. These improvements result from reconsideration of certain issues rais ed in petitions for reconsideration that were received by the Administrator on the August 16, 2012, final NSPS for the oil and

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1

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

As part of the regulatory process, EPA is required to develop a regulatory impact analysis
(RIA) for rules that have costs or benefits that exceed $10 0 million annually

. EPA estimates the proposed NSPS will have costs that exceed $100 million, so the Agency has prepared an RIA.

This RIA includes a n economic impact analysis and an analysis of the climate, health, and

welfare impacts anticipated from the proposed NSPS. 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 (NEMS). The engineering compliance costs are annualized using 3 and 7 p ercent discount rate s

.

This analysis estimates regulatory impacts for the analysis year s of 2020 and 2025

. The

anal ysis of 2020 is assumed to represent the first year the full suite of proposed standards is in effect and thus represents a single year of potential impacts. We estimate impacts in 2025 to

illustrate how new and modified sources accumulate over time under the pr o posed NSPS. The regulatory impact estimates for 2025 include sources newly affected in 2025 as well as the

accumulation of affected sources from 2020 to 2024 that are also assumed to be in continued operation in 2025, thus incurr ing compliance costs and emissions reductions in 2025.

Several emission controls for the NSPS , such as reduced emissions completions (RECs)

of hydraulically

- f ractured oil wells, capture methane and VOC emissions that otherwise would be vented to the atmosphere. T he averted methane emissions can be directed into natural gas production streams and sold. The revenues derived from n at ural gas recovery are expected to

offset a portion of the engineering costs of implementing the NSPS

. In this RIA , we present

results that include the ad ditional product recovery and the revenues we expect producers to gain from the additional product recovery.

The baseline used for the impacts analysis of our NSPS takes into account emissions

reductions conducted pursuant to s tate regulations covering the relevant operations

. More

detailed discussion on the derivation of t he baseline is presented in Section 3 of this RIA.

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1

- 3 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 inter nalize 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 reflected in th e market price of the goods prod uced through the polluting process. For this regulatory action the goods produced

, processed, transported, or stored are crude oil, natural gas, and other hy drocarbon products

. These social costs associated with the cli mate, health

, and welfare impacts are referred to as negative exter nalities. If an oil and natural gas firm pollutes the atmosphere while extracting, processing, tran s porting

, or storing the commodities, this cost will be borne not by the polluting

firm bu t by society as a whole. The market price of the products will fail to incorporate the full opportunity cost to s ociety of producing the products . All else equal, given this external ity, the quantity of oil and natural gas produced in a free market will no t be at the socially optimal level. More oil and natural gas will be produced than would occur if the power producers had to account for the full opportunity cost of production incl uding the negative externality. Consequently, absent a regulation on emissi ons, the marginal social cost of the last unit s of oil and natural gas produced will exceed its marginal social benefit.

1.3 Summary of Results

For the proposed NSPS, the key results of the RIA follow and are summarized in Table

1

- 1

. Note all dollar estimates are in 2012 dollars :

• Emissions Analysis: The proposed NSPS is anticipated to prevent significant new emissions, in cluding 1 8 0,000 tons of methane , 12 0,000 tons of VOCs and 40 0 tons of hazardous air pollutants (HAP) in 2020, increasing to 40 0,000 tons of methane, 180,000 tons of VOCs , and 2,5 00 tons of HAP prevented in 2025

. 1 

### The CO 2 

### - equivalent (CO 2 

### Eq.) methane emission reductions are 4.0 million metric tons in 2020 and 9.0 million metric
tons in 2025.

1 Estimates are presented in short tons.

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1

- 4 • Benefits Analysis: The monetized benefits in this RIA include those f rom reducing methane emissions, which are valued using the social cost of methane (SC

- CH 4 

### ). 2 

### The EPA estimates that, in 2020, the proposal will yield monetized climate benefits of $93 million to approximately $550 million; the mean SC

- CH 4 

### at the 3% discount rate results in an estimate of about $ 660 210 million in 2020. In 2025, the EPA estimates monetized climate benefits of $250 million to approximately $1.4 billion; the mean SC

- CH4 at the 3% discount rate results in an estimate of about $550 million in 2025 3 

### While we expect that the avoided emissions will result in improvements in ambient air qu ality and reductions in health effects associated with exposure to HAP, ozone, and particulate matter (PM), we have determined that quantification of those benefits cannot be accomplished for this rule

. 4 

### This is not to imply that there are no health benefi ts anticipated from the proposed rule ; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. In addition to health improvement s, there will be improvements in visibility effects, ecosystem effects, 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: EPA estimates the total capital cost of the proposed NSPS will be $1 80 60 million in 2020 and $ 330 24 0 million in 2025

. T he estimate of total annualized engineering costs of the proposed NSPS is $2 0 0 million in 2020 and $ 500 48 0 million in 2025 when using a 7 percent discount rate

. When estimated revenues from additional natu ral gas are included, the annualized engineering costs of the proposed NSPS are estimated to be $170 million in 2020 and $ 420 41 0 million in 2025 , assuming a wellhead natural gas price of $4/thousand cubic feet (Mcf)

. T he estimated engineering compliance costs that include the product recovery are sensitive to the assumption about the price of the recovered product. There is also geographic variability in wellhead prices, whic h can also influence estimated engineering costs. For example, $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $ 8.2 million in 2020 and $19 million in 2025 , given EPA estimates that about 8.2 million M cf in 2020 and 19 million Mcf of natural gas will be recovered by imple menting the NSPS

. When using a 3 percent discount rate, t he estimate of total annualized engineering costs of the proposed NSPS is $20 0 million in 2020 and $ 490 48 0 million in 2025, or $170

2 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.

3 T he range of estimates reflects four SC

- CH 4 estimates are associated with different discount rates (model average at 2.5, 3 and 5 percent; 95 th percentile at 3 percent). See S ection 4.3 for a complete discussion.

4 Previous studies have estimated the monetized benefits

- per

- ton of reducing VOC emissions associated with the effect that those emissions have on ambient PM 2.5 levels and the health effects associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009). While these ranges of benefit

- per

- ton estimates provide useful context, the geographic distribution of VOC emissions from the oil and gas sector are not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition, th e benefit

- per

- ton estimates for VOC emission reductions in that study are derived from total VOC emissions across all sectors. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 and the highly localized nature of a ir quality responses associated with VOC reductions, these factors lead us to conclude that the available VOC benefit

- per

- ton estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding exercise.

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- 5 million in 2020 and $ 420 41 0 million in 2025, when estimated revenues from additional natural gas are included. 5



### • Energy System Impacts Analysis: The EPA used the National Energy Modeling System (NEMS) to estimate the impacts of th e proposed rule on the United States energy system

. We estimate that natural gas and crude oil production levels remains essentially unchanged in 2020, while slight declines are estimated for 2020 for both natural gas (about 4 billion cubic feet (bcf) or a bout 0.01 percent) and crude oil production (about 2,000 barrels per day or 0.03 percent). Wellhead natural 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 i n 2025. Meanwhile, well crude oil prices for onshore lower 48 production are not estimated to change, 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 change in 2020 and increase by about 1,000 barrels per day (or 0.02 percent) in 2025.

• Small Entity Analyses: [ Placeholder for summary of Initi al Regulatory Flexibility Analysis ]

• Employment Impacts Analysis: 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 estimate d one

time and continual, annual labor requirements by estimating hours of labor required for compliance and converting this number to full

- time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks). The one

- time labor requirement to comply with th e proposed NSPS is estimated at about 70 FTEs in 2020 and in 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 used
to identify the specific number of people involved or whether new jobs are created for new employ e es , versus displacing jobs from other sectors of the economy

.

In the RIA, we examine three broad regulatory options (see Chapter 3 for a detailed
discussion). Table 6

- 1 presents the summary results for the proposed option, Table 6

- 2 presents summary results for the less stringent regulatory option, and Table 6

- 4 presents su mmary results for the more stringent regulatory option.

5 T he c hoice of discou nt rate has a small effect on nationwide annualized costs. The compliance costs related to oil well completions and fugitive emissions surveys occur in each year, so the interest rate has little impact on annualized costs for these sources. The annualized costs for pneumatic pumps, compresso rs, and pneumatic controllers are sensitive to interest rate, but these constitute a relatively small part of the total compliance cost estimates for the proposal.

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- 6 Table 1

- 1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed Option in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits 1 $21 0 million $55 0 million

Total Costs 2 $170 million $ 420 41 0 million
Net Benefits 3 $ 35 38 million $ 120 14 0 million

Non

- monetized Benefits Non

- monetized climate benefits Health effects of PM 2.5 and ozone
exposure from 12 0,000 tons of VOC reduced Non

- monetized climate benefits Health effects of PM 2.5 and ozone
exposure from 180,000 tons of VOC reduced Health effects of HAP exposure from 400 tons of HAP reduced Health effects of ozone exposure

from 180,000 tons of methane Health effects of HAP ex posure from 2,500 tons of HAP reduce d Health effects of ozone exposure

from 400,000 tons of methane Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC

- CH4) (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95 th percentile at 3 percent). For purposes of this table, we show the benefits associated with the model average a 3 percent discount rate. However, we emphasize the importance and value of considering the benefits calculated using all four SC

- CH4 estimates; the additional benefit estimates range from $93 million to $550 million in 2020 and $250 million to $1,400 mi llion in 2025 for the proposed option , as shown in Section 4.3

. The CO 2 - equivalent (CO 2 Eq.) methane emission reductions are 4.0 million metric tons in 2020 and 9.0 million metric tons in 2025

. Also, t he specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefi ts. See Section 4.7 for details.

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

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- 7 Table 1

- 2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Less Stringent Option in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits 1 $190 million $450 million
Total Costs 2 $80 million $ 240 220 million
Net Benefits $110 million $ 210 230 million

Non

- monetized Benefits Non

- monetized climate benefits Non

- monetized climate 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 160,000 tons of VOC reduced Health effects of HAP exposure from 290 tons of HAP reduced Health effects of HAP exposure from 1,800 tons of HAP reduced Health effects of ozone exposure from 170,000 tons of methane Health effects of ozone exposure from 330,000 tons of methane Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC

- CH4) (model average at 2.5 percent discount rate, 3 percent, 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. H owever we emphasize the importance and value of considering the benefits calculated using all four SC

- CH4 estimates; the additional benefit estimates range from $87 million to $52 0 million in 2020 and $21 0 million to $1,2 00 million in 2025 for this less stringent option , as shown in Section 4.3. The CO 2 - equivalent (CO 2 Eq.) methane emission reductions are 3.7 million metric tons in 2020 and 7.4 million metric tons in 2025

. Also, t he specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.

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

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- 8 Table 1

- 3 Summary of the Monetized Benefits, Costs, and Net Benefits for the More Stringent Option in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits 1 $220 million $640 million
Total Costs 2 $210 million $6 8 6 0 million
Net Benefits 3 $ 7.6 10 million

- $ 35 20 million

Non

- monetized Benefits Non

- monetized climate benefits Non

- monetized climate 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 5 1 0 0 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 different estimates of the social cost of methane (SC

- CH 4 ) (model average at 2.5 percent discount rate, 3 percent, 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. However we emphasize the importance an d value of considering the benefits calculated using all four SC

- CH 4 estimates; the additional benefit estimates range from $ 99 million to $5 9 0 million in 2020 and $30 0 million to $1, 7 00 million in 2025 for this more stringent option , as shown in Section 4.3. The CO 2 - equivalent (CO 2 Eq.) met hane emission reductions are 4.2 million metric tons in 2020 and 1 1 0.6 million metric tons in 2025

. Also, t he specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefi ts

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



### 1.4 Organization of this Report

The remainder of this repo rt details the methodo logy and the results of the RIA. S ection 2 presents the industry profile of the oil and natural gas industry. Section 3 describe s the emissions

and engineering cost analysis. Section 4 presents the benefits analysis

. Section 5 present s statutory and executive order analyses. Section 6 presents a comparison of benefits and costs. Section 7 presents energy system impact, employment impact, and small entity impact analyses.

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- 1 2 INDUSTRY PROFILE

2.1 Introduction

The oil and natural gas industry i ncludes the following five segments : drilling and extraction, processing, transportation, refining

, and marketing. T he Oil and Natural Gas NSPS require controls for the oil and natural gas products and processes of the drilling and extraction

of crude oil and natural gas, natural gas processing, and natur al gas transportation segments.

Most crude oil and natural gas production facilities are classified under NAICS 211 : Crude Petroleum and Natural Gas Extraction (211111) and Natural Gas Liquid Extraction
( 211112). The drilling of oil and natural gas wells is included in NAICS 213111. Most natural gas transmission and storage facilities are classified under NAICS 486210

— Pipeline Transportation of Natural Gas. While other NAICS ( 221210

— Natural Gas Distributio n,
486110

— Pipeline Transportation of Crude Oil, and 541360

— Geophysical Surveying and Mapping Services) are often included in the oil and natural gas sector, these are not discussed in detail in the Industry Profile because they are not directly affected by the proposed NSPS

.

The outputs of the oil and natural gas ind ustry are inputs for larger production processes of gas, energy, and petroleum products. As of 20 13 , the Energy Information Administration
( EIA ) estimates that about 490,000 producing natural ga s wells oper ated 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 production was 2 4.3 trillion cubic feet (tcf) in 2013

, the highest annual product ion level in U.S. history

. The leading five natural gas producing states
are Texas, Pennsylvania, Louisiana, Oklahoma, and Wyoming

. Dom estic crude oil production in

2013 was 2

, 716 million barrels ( bbl ) , the highest annual level in the U.S. since 1991

. The leading five crude oil producing states are Texas, North Dakota, 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 purp ose is to give the reader a genera l understanding of the geophysical, engineering, and economic aspects of the industry that are addressed in subsequent economic analysis in this RIA

. The Industry Profile relies heavily on background material from the U.S. EPA ’s “ Economic Analysis of Air Pollution Regulations: Oil

and Natural Gas Production ” (1996), the U.S. EPA ’s “ Sector Notebook Project : Profile of the Oil

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- 2 and Gas Extraction Industry ” (2000) , and the U.S . EPA’s “Regulatory Impact Analysis: Final

New Sourc e Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry” (2012).

2.2 Products of the Crude Oil and Natural Gas Industry

Each producing crude oil and natural gas field has its own unique properties. The composition of the crude oil and natural gas and reservoir characteristics are likely to be different from that of any other reservoir.

2.2.1 Crude Oil

Crude oil can be broadly classified as paraffinic, naphthenic (or asphalt

- based), or
intermediate. Generally, paraffinic crudes are used in the manufacture of lube oils and kerosene

. Paraffinic crudes have a high concentration of straight chain hydrocarbons and are relatively low in sulfur compounds. Naphthenic crudes are generally used in the manufacture of gasolines and asphalt and have a high concentration of olefin and aromatic hydrocarbons. Naphthenic crudes may contain a high concentration of sulfur compounds. Intermediate crudes are those that are not

classified in either of the a bove categories.

Another classification measure of crude oil and other hydrocarbons is by API gravity. API gravity is a weight per unit volume measure of a hydrocarbon liquid as determined by a method recommended by the American Petroleum Institute (API). A heavy or paraffinic cru de oil is typically one with API gravity of 20 o 

### or less, while a light or naphthenic crude oil, which typically flows freely at atmosph eric conditions, usually has API gravity in the range of the high

30's to the low 40's.

Crude o ils recovered in the production phase may be referred to as live crudes. Live crudes contain entrained or dissolved gases which may be released during processing or storage

. D ead crudes are those that have gone through various separation and storage phases and contain little, if any, entrained or dissolved gases.

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- 3 2.2.2 Natural Gas

Natural gas is a mixture of hydrocarbons and varying quantities of non

- hydrocarbons that exists in a gaseous phase or in solution with crude oil or other hydrocarbon liquids in natural underground reservoirs. Natural gas may contain contaminants, such as hydrogen sulfide (H 2 

### S),

CO 2 

### , mercaptans, and entrained solids.

Natural gas may be classified as wet gas or dry gas. Wet gas is unprocessed or partially processed natural gas produced fr om a reservoir that contains condensable hydrocarbons. Dry gas is either natural gas whose water content has been re duced through dehydration or natural gas that contains little or no recoverable liquid hydrocarbons.

Natural gas streams that contain thresh old concentrations of H 2 

### S are classified as sour

gases. Those with threshold concentrations of CO 2 

### are classified as acid gases. The process by which these two contaminants are removed from the natural gas stream is called sweetening. The

most common sweet ening method is amine treating. Sour gas contains a H 2 

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



### . Concentrations of H 2 

### S and CO 2 

### , along with organic sulfur compounds, vary widely among sour

gases. A majority of total onshore natural gas production and nearly all offshore natural gas production is classified as sweet.

2.2.3 Condensates

Condensates are hydrocarbons in a gaseous state under reservoir conditions, but become liquid in either the wellbore or th e production process. Condensates, including volatile oils, typically have an API gra vity of 40 o 

### or more. In addition, condensates may include hydrocarbon liquids recovered from gaseous streams from various oil and natural gas production or natural
gas tra nsmission and storage processes and operations.

2.2.4 Other Recovered Hydrocarbons

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

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- 4 2.2.5 Produced Water

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

oper ations

.

2.3 Oil and Natur al Gas Production Processes

2.3.1 Ex ploration and Drilling

Exploration involves the search for rock formations associated w ith oil or natural gas deposits and involves geophysical prospecting and/or exploratory drilling. Well development occurs after exploration has located an economically recoverable field and involves the construction of one or more wells from the beginning (called spudding) to either aba ndonment if no hydrocarbons are found or to well completion if hydrocarbons are found in sufficient quantities.

After the site of a well has been located, drilling commences. A well bore is created by using a rotary drill to drill into the ground. As the w ell bore gets deeper sections of drill pipe are

added. A mix of fluids called drilling mud is released down into the drill pipe then up the walls

of the we ll bore, which removes drill cuttings by taking them to the surface. The weight of the mud prevents h igh

- pressure reservoir fluid s from pushing their way out (“ blow ing out ” ). The well bore is cased in with telescoping steel piping during drilling to avoid its collapse and to prevent water infiltration into the well and to prevent crude oil and natural gas from contaminating the water table. The steel pipe is cemented by filling the gap between the steel casing and the wellbore with cement

.

Horizontal drilling technology has been available since the 1950s. Horizontal drilling

facilitates the construction o f 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 usefu l in unconventional gas extraction where the gas is not concentrated in a reservoir

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

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- 5 s urface without stopping the drill to switch directions and allowing for a more controlled and precise drilling trajectory.

Hydraulic fracturing (also referred to as “fracking”) has been performed since the 1940s
(U.S. DOE, 2013 )

. Hydraulic fracturing involves pumping fluids into the well under very high pressures in order to fracture the formation containing the resource. Proppant is a mix of sand and other materials that is pumped down to hold the fractures open to secure gas flow from the

formation (U.S. EPA, 2004)

.

2.3.2 Production

Productio n is the process of extracting the hydrocarbons and separating the mixture of liquid hydrocarbons, gas, water, and solids, removing the constituents that are non

- saleable, and selling the liquid hydrocarbons and gas. The major activities of crude oil and n atural gas production are bringing the fluid to the surface, separating the liquid and gas components, and removing impurities.

Oil and natural gas are found in the pores of rock s and sand (Hyne, 2001)

. I n a conventional source, the oil and natural gas ha ve been pus hed out of these pores by water and

moved until an impermeable surface had been reached. Because the oil and natural gas can travel no further, the liquids and gases accumulate in a reservoir. Where oil and gas are associated, a gas cap forms ab ove the oil. Natural gas is extracted from a well either because it is associated with oil in an oil well or from a pure natural gas reservoir. Once a well has been drilled to reach
the reservoir, the oil and gas can be extracted in different ways d ependin g on the well pressure (Hyne, 2001)

.

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

.

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- 6 Well pressure is required to move the resource up f rom the well to the surface. During primary e xtraction , p ressure from the well itself drives the resource out of the well directly. Well pressure depletes during this process. Typically

, about 30 to 35 percent of the resource in the reservoir is extracted this way (Hyne, 2001)

. The amount extracted depends on the specific well characteristics (such as permeability and oil viscosity). Lacking enough pressure for the

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

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

.

In contrast to conventional sources, unconventional oil and gas are trapped in rock or sand or, in the case of oil, are found in rock as a chemical substance that req uires a further

chemical transformation to become oil (U.S. DOE, 2013 )

. Ther e fore, the resource does not move

into a reservoir a s in the case with a co nventional source. M ining, induced pressure, or heat is required t o release the resource. The specific ty pe of extraction method needed depends on the type of formation where the resource is located. Unconventional oil and natural gas resource
types relevant for this rule inclu de:

• Shale Oil and Natural Gas: Shale natural gas comes from sediments of clay mixed with organic matter. These sediments f orm low permeability shale rock formations that do not allow the gas to move. To release the gas, the rock must be fragmented, making the

extraction pro cess more complex than it is for conventional gas extraction. Sha le gas can be extracted by drilling either vertically or horizontally, and breaking the rock using hydrau lic fracturing (U.S. DOE, 2013 ).

• Tight Sands Natural Gas: Reservoirs are composed of low

- porosity sandstones and carbonate into which natural gas has m igrated f rom other sources. Extraction of the natural gas from tight gas reservoirs is often performed using horizontal wells. Hydraulic fracturing is often used in tight sands (U.S. DOE, 2013 ).

• Coalbed Methane: Natural gas is present in a coal bed due to the activity of microbes in the coal or from alterations of the coal through temperature changes. Horizontal drilling

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- 7 is used but given that coalbed methane reservoirs are frequently associated with underground water reservoirs, hydraulic fracturing is oft en 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 transportation systems and used by final consumers. Conditioning is not always required. Natural gas from some formations emerges from the well sufficiently pure that it can be sent directly to the pipeline. As the natural gas is separated from the liquid components, it may contain impurities that pose potential hazards o r other problems.

The most significant impurity is H 2 

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

H 2 

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

It is therefore desirable to remove H 2 

### S as soon as possible in the conditioning process.

Another concern is that posed by water vapor. At high pressures, water can react with components in the gas to form gas hydrates, which are solids that can clog pipes, valves, and gauges, especially at cold temperatures (Manning and Thompson, 1991)

. Nitrogen and other gases may also be mixed with the natural gas in the subsurface. These other gases must be separated from the methane prior to sale. High vapor pressure hydrocarbons that are liquids at

surface t emperature and pressure (benzene, toluene, ethylbenzene, and xylene, or BTEX) are removed and processed separately.

Dehydration removes water from the gas stream. Three main approaches toward dehydration are the use of a liquid or solid desiccant, and refr igeration. When using a liquid desiccant, the gas is exposed to a glycol that absorbs the water. The water can be evaporated from the glycol by a process called heat regeneration. The glycol can then be reused. Solid
desiccants, often materials called mole cular sieves, are crystals with high surface areas that

attract the water molecules. The solids can be regenerated simply by heating them above the boiling point of water. Finally, particularly for gas extracted from deep, hot wells, simply cooling the gas to a temperature below the condensation point of water can remove enough water to transport the gas. Of the three approaches mentioned above, glycol dehydration is the most

common when processing at or near the well.

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- 8 Sweetening is the procedure in which H 2 

### S and sometimes CO 2 

### are removed from the gas

stream. The most common method is amine treatment. In this 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 solu tion is then heated, thereby separating the gases and regenerating the amine. The sulfur gas may be disposed of by flaring, incinerating, or when a market exists, sending it to

a sulfur

- recovery facility to generate elemental sulfur as a salable product.

2.3.4 Natural Gas Trans mission and Distribution

After processing, natural gas enters a network of compressor stations, high

- pressure transmission pipelines, and often

- underground storage sites. Compressor stations are any facility which supplies energy to move n atural gas at increased pressure in transmission pipelines or into underground storage. Typically, compressor stations are located at intervals along a transmission pipeline to maintain desired pressure for natural gas transport. These stations will use ei ther large internal combustion engines or gas turbines as prime movers to provide the necessary horsepower to maintain system pressure. Underground storage facilities are subsurface facilities utilized for storing natural gas which has been transferred fro m its original location for the primary purpose of load balancing, which is the process of equalizing the receipt and delivery of natural gas. Processes and operations that may be located at underground storage facilities include compression and dehydratio n.

2.4 Reserves and Markets

Crude oil and natural gas have historically served two separate and distinct mar kets. Oil

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

interna tional commodity

. The following subsections provide historical and forecast data on the

U.S. reserves, production, consumption, and foreign trade of crude oil and natural gas

.

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- 9 2.4.1 Domestic Proved Reserves

Table 2

- 1 shows crude oil and dry natural gas proved reserves, unproved reserves, and total technically recoverable resources as of 200 9

. According to EIA 6 

### , these concepts are defined

as:

• Proved reserves : e stimated quantities of energy sources that analysis of geologic and engineering data demonstrates with reasonable certain ty are recoverable under existing economic and operating conditions.

• Unproved resources : additional volumes estimated to be technically recoverable without consideration of economics or operating conditions, based on the application of current technology

.

• T otal t echnically recoverable resources : resources that are producible using current technology without reference to the economic viability of production.

According to EIA, dry natural gas is consumer

- grade natural gas

. Th e dry natural gas volumes
report ed in Table 2

- 1 reflect the amount of gas remaining after liquefiable portion has been removed from the natural gas, as well as any non

- hydrocarbon gases that render the natural gas

unmarketable have been removed. The sum of proved reserves and unproved re serves equal the total technically recoverable resources. As seen in Table 2

- 1 , as of 200 9 , proved domestic crude

oil reserves accounted for about 1 0 percent of t he totally technically recoverable crude oil

resources.

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

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- 10 Table 2

- 1 Technically Recoverable Crude Oil and Natural Gas Resource Estimates, 200 9

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, S hale Gas and Coalbed Methane 167.1 1,026.7 1,193.8

Total U.S. 272.5 1,930.7 2,203.3

Source: U.S. Energy Information Administration, Annual Energy Review 201 2

. Totals may not sum due to independent rounding

. 1/ Includes associated

- dissolved natural gas that occurs in crude oil reservoirs either as free gas (associated) or as gas in solution with crude oil (dissolved gas).



### Proved natural gas reserves accounted for about 1 2 percent of t he total technically recoverable natural gas resources. Significant proportions of these reserves exist in Alaska and offshore

areas. While the dry natural gas proved reserves in 200 9 were estimated at 27 2

. 5 tcf, wet natural gas reserves were estimated at 2 83

. 9 tcf. Of the 2 83

. 9 tcf, 25 0

. 5 tcf (about 8 8 percent) is

considered to be wet non

- associated natural gas, while 3 3

. 3 tcf (about 1 2 percent) is considered

to be wet associated

- dissolved natural gas. Associated

- dissolved natural gas, according to EIA, is natural gas which occurs in crude oil reservoirs as free natural gas or in solution with crude oil.

Table 2

- 2 and Figure 2

- 1 show trends in crude oil and natural gas p roduction and reserves

from 1990 to 20 13. In Table 2

- 2 , proved ultimate recovery equals the sum of cumulative production and proved reserves. While cr ude oil and natural gas are nonrenewable resources, the table shows that proved ultimate recovery rises over time as new discoveries become

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- 11 economically accessible. R eser ves growth and decline is also partly a function of exploration
activities, which are correlated with oil and natural gas prices. For example, w hen oil prices are high there is more of an incentive to use secondary and tertiary recovery, as well as to develop

unconventional sources.

Table 2

- 2 Crude Oil and Natural Gas Cumulat ive Domestic Production, Proved Reserves, and Proved Ultimate Recovery, 1977

- 2 013

Crude Oil and Lease Condensate (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 1,000,745
1996 173,197 22,017 195,214 854,453 166,474 1,020,927
1997 175,552 22,546 198,098 873,355 167,223 1,040,578
1998 177,834 21,034 198,868 892,379 164,041 1,056,420
1999 179,981 21,765 201,746 911,211 167,406 1,078,617
2000 182,112 22,045 204,157 930,393 177,427 1,107,820
2001 184,229 22,446 206,675 950,009 183,460 1,133,469
2002 186,326 22,677 209,003 968,937 186,946 1,155,883
2003 188,388 21,891 210,279 988,036 189,044 1,177,080
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 proved reserves has declined over time for both

crude oi l and natural gas, from above 11 percent in the early 1990s to 8 to 10 percent over the

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- 12 period from 2006 to 20 13 for crude oil and from above 11 percent during the 1990s to between 7

and 9 percent from 200 6 to 20 13 for natural gas.

Figure 2

- 1 A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990

- 2013. B) Domestic Natural Gas Proved Reserves and Cumulative Production, 1990

- 2013

Table 2

- 3 presents the U.S. proved reserves o f crude oil and natural gas by state or producing area as of 20 13. Five areas currently account f or 8 1 percent of the U.S. total proved

reserves of crude oi l, 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 6 5 percent of the U.S. total proved reserves o f 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 Reserves

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- 13 Table 2

- 3 Crude Oil and Dry Natural Gas Proved Reserves by State, 2 013

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. Total may not sum due to independent rounding. * New York crude oil reserves are included in miscellaneous states

.


### 2.4.2 Domestic Production

Domes tic oil production was in a state of decline that began in 1970 and continued to a low point in 2008

. Since 2008, domestic oil production has recovered to the highest levels since

1991. Table 2

- 4 shows U.S. production in 20 13 at 2,716 million bbl per yea r

.

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- 14 Table 2

- 4 Crude Oil Domestic Production, Wells, Well 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 at the lease or wellhead at which domestic crude is purchased. Prices adjusted using GDP Implicit Price Deflator.



### A verag e well productivity has also generally decreased since 1990 ( Table 2

- 4 and Figure 2

- 2 ).

These production and productivity decreases are in spite of the fact that average first purchase price s have shown a generally increasing tr end

.

Annual production of natural gas from natural gas well s has increased more than 8 000

bcf from the 1990 to 20 1 3 ( Table 2

- 5 )

. The number of wells producing natural ga s has nearly

doubled between 1990 and 20 11 ( Figure 2

- 2 )

. While the number of producing wells has

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

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- 15 Table 2

- 5 Natural Gas Production and Well Productivity, 1990

- 20 1 3

Natural Gas Gross Withdrawals (Billion Cubic Feet) Natural Gas Well Productivity

Total Dry Gas Production 1 Producing Wells Avg. Well Productivity Million Cubic

Feet/Y ear) 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 49.9

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- 16 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, 1990

- 2013.

Domestic e xploration and development for oil has continued during the last two decades.

From 2002 to 20 10 , crude oil well drilling showed significant increases, although the 1992

- 200 4 period showed relatively low levels of crude drilling activity compared to periods before and
after ( Table 2

- 6 ). The drop in 2009 showed a departu re from this trend, likely due to the

recession experienced in the U.S.

Meanwhile, natural gas drilling has increased significantly during the 1990

- 20 1 0 period

. Like crude oil drilling, 2009 and 2010 saw a relatively low level of natural gas drillings. The success rate of wells (producing wells versus dry wells) has also increa sed gradually over time

from 75 percent in 1990

, to 86 percent in 2000, to a peak of 90 percent in 2009 ( Table 2

- 6 )

. The increasing success rate reflects improvements in exploration 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 Wells

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- 17 improvements in well drilling and completion. Similarly, w ell average depth has also in creased by during this period ( Table 2

- 6 )

.

Table 2

- 6 Crude Oil and Natural Gas Explor atory and Develop ment Wells and Average Depth, 1990

- 20 10

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 produced water can be costly and challenging. Texas, California, Wyoming

, Oklahoma , and Kansas were the top five states in terms of produced water volumes in 2007 ( Table 2

- 7 ). These estimates do not include estimates of flowback water from hydraulic fracturing activities ( ANL 2009 )

.

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- 18 Table 2

- 7 U.S. Onshore and Offsh ore Oil, Gas, and Produced Water Generation, 2007

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

.


### A s can be seen in Table 2

- 7
, the amount of water produced is not necessarily correlated

with the ratio of water produced to the volume of oil or natural gas produced. Texas, Alaska and

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- 19 Wyoming were the three largest pro ducers in barrels of oil equivalent (boe) terms , but had relatively low rates of water production compared to more Midwestern states such as Illinois

, Missouri, Indiana, and Kansas

. Figure 2

- 3 s hows the distribution of produced water management practices in 2007.

Figure 2

- 3 U.S. Produced Water Volume by Management Practice, 2007

More than half of the water produced (51 percent) was re

- injected to enhance resource recov ery through maintaining reservoir pressure or hydraulically pushing oil from the reservoir. Another

third (34 percent) was injected, typically into wells whose primary purpose is to sequester produced water. A small percentage (three percent) is discharged into surface water when it meets water quality criteria. The destination of the remaining produced water ( 11 percent, the difference between the total managed and total generated ) is uncertain (ANL, 2009)

.

The movement of crude oil and natural gas primarily takes place via pipelines. Total crude oil pipeline mileage has decreased during the 1990

- 20 11 period ( Table 2

- 8 ), appearing to

follow the d ownward supply trend shown in Table 2

- 4

. While exh ibiting some variation, pipeline mileage transporting refined products remained relatively constant. 51%

34% 3% 11%

Injection for Enhanced Recovery

Injection or Disposal

Surface Discharge

Unknown

Source: Argonne National Laboratory

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- 20 Table 2

- 8 U.S. Oil and Na tural Gas Pipeline Mileage, 2010

- 20 1 3 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, Office 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 types: distribution mains, distribution
service, transmission pipelines, and gathering lines. Gathering lines are low

- volume pipelines that gather natural gas from production sites to deliver directly to gas processing plants or compression stations that connect numerous gathering lines to transport gas primarily to processing plants. Transmission pipelines move large volumes of gas to or from processing plants to distribution points. From these distribution points, the gas enters a distribution system that delivers the gas to final consumers.

2.4.3 Domestic Consumption

Historical crude oil sector

- level consumption trends for 1990 through 20 12 are shown in

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- 21 Table 2

- 9 and Figure 2

- 4

. Total consumption rose gradually until 2008 when consumption dropped as a result of the economic recession. The share of residential, commercial, industrial, and electric pow er on a percentage basis declined during this period, while the share of total consumption by the tra nsportation sector rose from 64 percent in 1990 to 7 1 percent in

20 12

.

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- 22 Table 2

- 9 Crude Oil Consumption by Sector, 1990

- 20 1 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 2.6 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.

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- 23 Figure 2

- 4 Crud e Oil Consumption by Sector (Percent of Total Consumption), 1990

- 20 11

Natural gas consumption has increased over the last twenty years. From 1990 to 20 12

, total U.S. consumption increased by an average of about 1 percent per year ( Table 2

- 10 and Figure 2

- 5 ). Over the same period, industrial consumption of natural gas declined

, whereas electric power generation increased its consumption quite dramatically , an important trend in the

ind ustry as many utilities increasingly use natural gas for peak generation or switch from coal

based to natural gas

- based electricity generation

. The residential, commercial

, and transportation sectors maintained their consumption levels at more or less constant levels during this time period. 0% 10% 20% 30% 40% 50% 60% 70% 80%Consumption (% of total)

Residential and Commercial Industrial

Transportation Sector Electric Power

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- 24 Table 2

- 10 Natural Gas Consumption by Sector, 1990

- 20 1 2

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.

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

- 20 1 2

2.4.4 International Trade
Until 2006, net trade of crude o il and refined petroleum products increased , showing increased substitution of imports for domestic production, as well as imports satisfying growing

consumer demand in the U.S

. ( Table 2

- 11 )

. Since then, how ever, imports have been declining while exports have been rising, leading to significant 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 Transportation

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- 26 Table 2

- 11 Total Crude Oi l and Petroleum Products Trade (Million Bbl), 1990

- 20 1 3
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 1990 to 2007 in volume and percentage
terms ( Table 2

- 12 ). The years 2007 through 20 12 saw imported natural gas constituting a lower percentage of domestic natural gas consumption

. Until recent years, industry analysts forecast that LNG imports wou ld continue to grow as a percentage of U.S

. consumption. However, it is possible that increasingly accessible domestic unconventional gas resources, such as shale gas and coalbed methane, might reduce the need for the U.S. to import natural gas, either via pipeline or shipped LNG.

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- 27 Table 2

- 12 Natural Gas Imports and Exports, 1990

- 20 1 3 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 drilling activity and crude oil and natural gas domestic production, imports, and prices. The forecasts are from the 201 4 Annual Energy

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

discussed in detail in Section 7 , to analyze the impacts of the proposed NSPS on the national energy economy, we use the National Energy Modeling System ( NEMS ) t hat was used to produce the 201 4 Annual Energy Outlook

.

Table 2

- 13 present fo recasts of successful wells drilled in the U.S. from 2010 to 20 40

. Crude oil well forecasts for the lower 48 states show a rise up to the year 2025 then a gradual

decline until 20 40

.

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- 28 Table 2

- 13 Forecast of T otal Successful Wells Drilled, Lower 48 States, 2010

- 20 40

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 p resents forecasts of domestic crude oil production, reserves, im ports and 6 depicts these trends graphically

.

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- 29 Table 2

- 14 Forecast of Crude Oil Supply, Res erves, and We llhead Prices, 2011

- 20 40
Domestic Production (million bbls)

Total Domestic Lower 48 Onshore Lower 48 Offshore Alaska Other Crude Supply Net Imports Total Crude Supply (million barrels) 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 12,938 137.63 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 20 40 , an increase of 2 5 percent overall. This increment is larger than t he forecast increase in production from the lower 48 states during this period, 1 2

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- 30 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 20 40 , from
$ 7 6

. 78 per barrel to $ 160.38 per barrel in 20 11 dollar terms.

Figure 2

- 5 Forecast of Domestic Crude Oil Production and Net Imports, 2010

- 20 40

Table 2

- 15 shows domestic natural gas production is fo recast to increase until 20 40

. Meanwhi le, imports of natural gas via pipeline are expected to be eliminated dur ing the forecast

pe riod, from 1.68 tcf in 2011 to

- 2.43 in 20 40 tcf. Import s of LNG are also eliminated during the forecast period, from 0. 28 tcf in 2011 to

- 3.37 tcf in 20 40

. Total suppl y, then, increases about 33 percent, from 22.55 tcf in 2011 to 37.54 tcf in 20 40

. 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
Alaska

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- 31 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 have increased significantly over the past

two decades , particularly in recent years

. Cost per well has increas ed 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, Annual Energy Outlook, 2014

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- 32 about 15 percent , and cost per foot has increased on average of about 13 percent per year ( Figure

2

- 6 ).

Figure 2

- 6 Costs of Crude Oil and Natural Gas Wells Drilled, 1981

- 2008

The average finding costs compiled and published by EIA add an additional level of detail to drilling costs, in that finding costs incorporate the costs more broadly associated with adding proved reserves of crude oil and natural gas. These costs include exploration and development costs, as well as costs associated with the purchase or leasing of real property. EIA publishes finding costs as running three

- year averages, in order to better compare these costs, which oc cur over several years, with annual average lifting costs

. Figure 2

- 7 shows average domestic onshore

and offshore and foreign finding costs for the sam ple of U.S. firms in EIA’s Financial Reporting System (FRS) database from 1981 to 200 9

. The costs are reported in 200 9 dollars on a barrel of oil equivalent basis for crude oil and natural gas combined. The average domestic finding costs dropped from 1981 until the mid

- 1990s. Interestingly, in the mid

- 1990s, domestic onshore and offshore and foreign finding costs converged for a few years. After this period, offshore finding costs rose faster than domestic onshore and foreign costs. 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)

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- 33 Figure 2

- 7 Finding Costs for FRS Companies, 1981

- 200 9

After 2000, average finding costs rose sharply, with the finding costs for domestic onshore and offshore and foreign proved reserves diverging onto different trajectories. Note the drilling costs

in Figure 2

- 6 and finding costs in Figure 2

- 7 present similar trends overall.

2.5.2 Lifting Costs

Lifting costs are the costs to produce crude oil or natural gas once the resource has been

found and accessed. EIA’s definition of lifting costs includes costs of operating and maintaining wells and associated production equipment. Direct lifting costs exclude production taxes or royalties, while total lif t ing costs includes taxes and royalties. Like finding costs, EIA reports average lifting costs for FRS fir m s in 200 9 dollars on a barrel of oil equivalent basis

. Total lifting costs are the sum of direct lifting costs and production taxes. Figure 2

- 8 de p icts direct lifting cost

trends from 1981 to 200 9 for domestic and foreign production. 0 10 20 30 40 50 60 70 80$2008/boe

U.S. Onshore U.S. Offshore Foreign

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- 34 Figure 2

- 8 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981

- 200 9 (3

- year Running Average)

Direct lifting costs (excludes taxes and royalties ) for domestic production r ose a little more than $2 per barrels of oil equivalent from 1981 to 1985, t hen declined almost $5 per barrel of oil equivalent from 1985 until 2000. From 2000 to 200 9 , domestic lifting costs inc reased 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 lower than domestic costs during this period. Foreign and domestic lifting cost s followed a similar track until they again diverged in 2004, with domestic lifting again becoming more expensive. Combined with finding costs, the tota l finding and lifting costs rose significantly in from 2000 to 200 9

.

2.5.3 Operating and Equipment Costs

The E IA report, “ Oil and Gas Lease Equi pment and Operating Costs 1994 t hrough

2009 ” 7 

### , 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

7 U.S. Energy Information Administration. “ Oil and Gas Lease Equi pment and Operating Costs 1994 t hrough 2009 .” September 28, 2010.

< http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/curren t/coststudy.html > Accessed February 2, 20 11. 0 2 4 6 8 10 12 14$2008/boe

Domestic Foreign

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- 35 Mountains) with producing depths ranging from 2000 to 16,000 feet and low to high productio n rates (for example, 50,000 to 1 million cubic feet per day for natural gas).

Figure 2

- 9 depicts c ru de oil operating costs and equipment costs i ndic es for 1976 to
2009, as well as the crud e oil price in 1976 dollars

. The indices show that crude oil operating and equipment costs track the price of oil over this time period, while operating costs have risen more quickly than equipment costs. Operating a nd equipment costs and oil prices rose steeply in the late 1970s, but generally decreased from about 1980 until the late 19 9 0s.

Figure 2

- 9 Cru de Oil Operating Costs and Equipment Costs Indices (1976=100) an d Crude Oil Price (in 1976 dollars) , 1976

- 2009 8



### Oil costs and prices again generally rose between 2000 to present, with a peak in 2008. The 2009 index values for crude oil operating and equipment costs are 154 and 107, respectively.

8 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)

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- 36 Figure 2

- 10 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natu ral Gas Price , 1976

- 2009

Figure 2

- 10 depicts natural gas operating and equipment costs indices, as well as natural gas prices. Similar to the cost trends for crude oil, n atural gas operating and equipment costs track the price of natural gas over this time period, while operating costs have risen more quickly than equipment costs. Operating and equipment costs and gas prices also rose steeply in the late 1970s, but generally decreased from about 1980 until the mid

- 1990s

. The 200 9 index values for natural gas operating and equipment costs are 137 and 112, respectively.

2.6 Firm Characteristics

A regulatory action to reduce pollutant discharges from facilities producing crude oil and natural gas will potentially affect the business ent ities that own the regulated facilities. In the oil and natural gas production industry, facilities comprise those sites where plant and equ ipment

extract, process , and transport extracted streams recovered from the raw crude oil and natural gas

resources

. Companies that own these facilities are legal business entities that have the capacity to

conduct business transactions and make business decisions that affect the facility. 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)

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- 37 2.6.1 Ownership

Enterprises in t he oil and natural gas industry may be divided into dif ferent groups that

include p roducers, transporters, and distributors. The producer segment may be further divided between major and independent producers. Major producers include large oil and gas companies

that are involved in each of th e five industry se gments : drilling and exploration, production, transportation, refining, and marketing. Independent producers include smaller firms that are

involved in some but not all of the five activities.

According to the Independent Petroleum Association of America (IPAA) , independent companies produce approximately 68 percent of domestic crude oil production of our oil, 85 percent of domestic natural gas, and drill almost 90 percent of the wells in the U.S (IPAA, 2009 ). Through the mid

- 1980s, natural gas was a seco ndary fuel for many producers. However, now it is of primar y importance to many producers. IPAA reports tha t about 50 percent of its members’ spending in 2007 was directed toward natural gas produ ction, largely toward production of unconventional gas ( IPAA , 2009 ). Meanwhile, t ransporters are compr ised of the pipeline companies, while distributors are comprised of the local distribution companies.

2.6.2 Size Distribution of Firms in Affected NAICS

As of 20 1 4, there were 6,659 firms within the 211 111 and 211112 NAI CS codes, of
which 6,535 (98 percent ) were considered small entiti es ( Table 2

- 16 ). Within NAICS 2111 11

and 211112 , large firms compose about 2 percent of the firms, but account for about 60 percent

o f employment listed under the se NAICS.

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- 38 Table 2

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

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

Number of Firms by Firm Size

211111 Crude Petroleum and Natural Gas Extraction 500 6,436 87 6,523 211112 Natural Gas Liquid Extraction 500 99 37 136 213111 Drilling Oil and Gas Wells 500 1,993 48 2,041 213112 Support Activities for Oil and Gas Operations $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 500 45,641 63,313 108,954 211112 Natural Gas Liquid Extraction 500 1,733 8,272 10,005 213111 Drilling Oil and Gas Wells 500 36,663 57,843 94,506 213112 Support Activities for Oil and Gas Operations $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 of Advocacy. 2014.
Firm Size Data. <Available at https://www.sba.gov/advocacy/firm

- size

- data> Accessed January 5, 2015. Note: "N/A" indicates where national counts of small and large firms could not be performed.



### The small and large firms within NAICS 21311 are similarly distributed, with large firms accounting for about 2 percent of firms, but 61 percent of employment

. Because there are relatively few firms within NAICS 486210, the Census Bureau cannot release breakdowns of firms by size in sufficient detail to perform similar calculation.

2.6.3 Trends in National Employment and Wages

As well as producing much of the U.S. energy supply, the oil and natural g as industry directly employ s a significant number of people. Table 2

- 17 shows em ployment in oil and natural gas

- related NAICS codes from 1990 to 20 13. 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

20 13 peak of 620,000

. Crude Petroleum and Natural Gas Extraction (NAICS 211111) and Support Activities for Oil and Ga s Operations ( NAICS 213112) employ the majority of workers in the industry.

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- 39 Table 2

- 17 Oil and Natural Gas In dustry Employment by NAICS, 1990

- 201 3
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 20 13 , average wages for the oil and natural gas industry have increased.

Table 2

- 18 show s real wages (in 2012 dollars) from 1990 to 20 13 for the NAICS codes associated with the oil and natural ga s industry.

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- 40 Table 2

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

- 20 13 (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 62,245 1991 75,980 69,993 45,593 49,578 72,277 68,228 63,886 1992 80,222 72,285 45,683 51,355 77,941 70,472 67,435 1993 81,214 72,237 47,486 52,649 76,445 70,777 67,734 1994 82,976 74,277 46,717 52,565 79,790 71,804 68,058 1995 85,341 70,873 48,462 53,294 82,717 75,418 69,634 1996 88,319 72,256 51,256 55,400 80,589 80,103 71,727 1997 94,309 83,369 54,754 58,343 82,305 86,858 75,355 1998 97,870 94,427 55,692 60,445 83,028 88,367 77,393 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 90,990 2001 116,417 116,513 64,792 64,298 87,363 128,243 89,416 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 96,693 104,055 100,084 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 Censu s of Employment and Wages, 2013

, annual wages per employee <http://www.bls.gov/cew/>



### Employ ees in the NAICS 211 codes earn the highest average 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 the highest variation.

2.6.4 Horizontal and Vertical Integration

Because of the existence of major compani es, the industry possesses a wide dispersion of vertical and horizontal integration. The vertical aspects of a firm’s size reflect the extent to which goods and services that can be bought from outside are produced in house, while the horizontal

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- 41 aspect of a firm’s size refers to the scale of production in a single

- product firm or its scope in a multiproduct one. Vertical integration is a potentially important dimension in analyzing firm

level impacts because the regulation could affect a vertically integrat ed 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 ultim ately produce final petroleum products, such as motor gasoline, jet fuel, or kerosene. This firm would be considered vertically integrated because it is involved in more than one level of requiring crude oil and natural gas and finished petroleum products. A regulation that increases the cost of oil and natural gas production will ultimately affect the cost of producing final petroleum products.

Horizontal integration is also a potentially important dimension in firm

- level analyses for any of the following reasons

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

In addition to the vertical and horizontal integration that exists among the large firms in

the industry, many major producers often diversify within the energy industry and produce a wide array of products unrelated to oil and gas production. As a result, some of the effects of regulation of oil and gas production can be mitigated if demand for othe r 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 individua l firms, although processing is increasing performed by the integrated major companies. Several natural gas firms operate multiple facilities. However, natural gas wells are not exclusive to natural gas firms only. Typically wells produce both oil and gas and can be owned by a natural gas firm or an oil company.

Unlike the large integrated firms that have several profit centers such as refining, marketing, and transportation, most independents have to rely only on profits generated at the

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- 42 wellhead from the sale of oil and natural gas or the provision of oil and gas production

- related engineering or financial services. Overall, independent producers typically sell their output to refineries or natural gas pipeline companies and are not vertically integrated. Independents may also own relatively few facilities, indicating limited horizontal 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 companie s with domestic reser ves and headquarters in the U.S

. In the past, the survey reported information on the top 300 companies, now the top 150. In 201 2 , 13 4 public companies are listed ; in 2011 there were 145 firms

. 9 

### Th e
2012 list contains four companies that were not on the list in the previous year. Also, 10 other companies listed in 2011 do not appear on the 2012 list as a result of mergers, bankruptcies, or

other reasons. Table 2

- 19 lists selected statistics for the top 20 companies in 201 2 . The results presented in the table reflect a decline in U.S. natural gas and natural gas liquids prices, weak energy demand growth, and increased capital and operating costs in 2012

.

Net income for the top 13 4 companies fell between 20 11 and 20 12 from $1 14.5 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 exploratory spending for the companies in 2012 totaled $206.5 billion, up 17.1 from 2011.

The total worldwide liquids production for the 13 4 firms increased 6.85 pe rcent to 2.8 79 billion bbl, while total worldwide gas production increased 2.4 percent to a total of 1 7

. 4 tcf ( Oil

and Gas Journal , September 2 , 201 3 ). Meanwhile, the 13 4 firms on the OGJ list increased both oil and natural gas production and reserves from 20 11 to 20 12

. Domestic production of liquids

increased about 19.8 percent from 2011 to 1. 437 billion bbl , and natural gas production was up about 6.3 percent

. For context, the OGJ150 domestic crude production represents about 49 percent of tot al dom estic production ( 2.06 billion bbl, according to EIA). The OGJ 150 natural gas production represents about 69 percent of total domestic production ( 2 8. 5 tcf, according to

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

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- 43 EIA).

The OGJ also releases a period report entitled “Worldwide Gas Processing Survey”,

whic h provides a wide range of information on existing processing facilities. We used a recent list of U.S. gas processing facilities ( Oil and Gas Journal , June 7, 2010) and other resources, such as the American Business Directory and company websites, to best identify the parent company of the facilities. As of 2009, there are 579 gas processing facilities in the U.S., with a processing capacity of 73,767 million cubic feet per day and throughout of 45,472 million cubic feet per day ( Table 2

- 20 ). The overall trend in U.S. gas processing capacity is showing fewer, but larger facilities. For example, in 1995, there were 727 facilities with a capacity of 60,53 3 million cubic feet per day (U.S. DOE, 2006).

Trends in gas processing facility ownership are also showing a degree of concentration, as large firms own multiple facilities, which also tend to be relatively large facilities ( Table

2

- 20 ). While we estimate 142 companies own the 579 facilities, the top 20 companies (in terms of total throughput) own 264 or 46 percent of the facilities. That larger compan ies tend to own larger facilities is indicated by these top 20 firms owning 86 percent of the total capacity and 88 percent of actual throughput.

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- 44 Table 2

- 19 Top 20 Oil and Natural Gas Companies (Based on Total Assets) , 201 2

Worldwide Production US Production Rank by

Total Assets Company Employees Total Assets ($Million) Total Revenue ($Million) Net Income ($Million) Liquids (Million

bbl) Natural Gas (Bcf) Liquids (Million

bbl) Natural Gas (Bcf) Net Wells Drilled
1 ExxonMobil Corp. 76,900 333,795 482,295 47,681 625 2,992 166 1,518 1

, 411 2 Chevron Corp. 17,418 232,982 241,909 26,336 536 1,737 151 1,129 1

, 272 3 ConocoPhillips 16,900 117,144 62,004 8,498 271 1,539 120 916 1

, 163 4 Occidental Petroleum Corp. 12,300 64,210 24,253 4,598 201 1129 100 752 1

, 016 5 Apache Corp. 5,976 60,737 17,078 2,001 145 938 84 685 958 6 Anadarko Petroleum Corp. 5,200 52,589 13,411 2,445 115 916 75 565 951 7 Hess Corp. 14,775 43,441 38,373 2,063 110 839 61 440 826 8 Devon Energy Corp. 5,700 43,326 9,502

- 206 103 565 57 407 769 9 Chesapeake Energy Corp. 12,000 41,611 12,316

- 594 93 557 49 380 751 10 Marathon Oil Corp. 3,367 35,306 16,221 1582 78 470 45 380 699 11 EOG Resources Inc. 2,650 27,337 11,683 570 49 416 39 313 513 12 Noble Energy Inc. 2,190 17,554 4,223 1027 42 380 34 300 492 13 Murphy Oil Corp. 9,185 17,523 28,626 971 41 322 26 259 468 14 Plains Exploration and Production Co 906 17,298 2,565 343 34 284 25 253 439 15 Pioneer Natural Resources Co. 3,667 13,069 3,228 243 26 259 24 249 367 16 Linn Energy LLC 1,136 11,451 1,774

- 387 25 253 24 249 334 17 Denbury Resources Inc. 1,432 11,139 2,456 525 24 249 24 183 315 18 Sandridge Energy Inc. 2,510 9,791 2,731 247 24 249 20 161 297 19 WPX Energy Inc. 1,200 9,456 3,189

- 211 22 244 18 160 271 20 Continental Resources Inc. 753 9,140 2,573 416 20 183 18 156 263 Source: Oil and Gas Journal. “OGJ150 Earnings Down as US Production Climbs.” September 2, 2013. The annual Oil and Gas Journal (OGJ) survey, the OGJ150, reports financial and operating results for public oil and natural gas companies with domestic reserves and headquart ers in the U.S. Notes: The source for employment figures is Hoovers, a D&B Company.

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- 45 Table 2

- 20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009

Rank Company Processing Plants (No.) Natural Gas Capacity (MMcf/day) Natural Gas Throughput (MMcf/day)
1 BP PLC 19 13,378 11,420 2 DCP Midstream Inc. 64 9,292 5,586 3 Enterprise Products Operating LP

— 23 10,883 5,347 4 Targa Resources 16 4,501 2,565 5 Enbridge Energy Partners LP

— 19 3,646 2,444 6 Williams Cos. 10 4,826 2,347 7 Martin Midstream Partners 16 3,384 2,092 8 Chevron Corp. 23 1,492 1,041 9 Devon Gas Services LP 6 1,038 846 10 ExxonMobil Corp. 6 1,238 766 11 Occidental Petroleum Corp 7 776 750 12 Kinder Morgan Energy Partners 9 1,318 743 13 Enogex Products Corp. 8 863 666 14 Hess Corp. 3 1,060 613 15 Norcen Explorer 1 600 500 16 Copano Energy 1 700 495 17 Anadarko 18 816 489 18 Oneok Field Services 10 1,751 472 19 Shell 4 801 446 20 DTE Energy 1 800 400 TOTAL FOR TOP 20 264 63,163 40,028 TOTAL FOR ALL COMPANIES 579 73,767 45,472
Source: Oil and Gas Journal . “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010 , with additional analysis to determine ultimate ownership of plants

.



### The OGJ also issues a periodic report on the economics of the U.S. pipeline industry. This report examines the economic status of all major and non

- major natural gas pipeline

c ompanies, which amounts to 16 2 companies in 201 1 ( Oil and Gas Journal

, Septem ber 2 , 201 3 )

. Table 2

- 21 presents the pipeline mileage, volumes of natural gas transported, operating revenue, and net income for the top 20 U.S. natural gas pipeli ne companies in 20 12

. Ownership of gas pipelines is mostly independent from ownership of oil and gas production companies, as is seen from the lack of overlap between the OGJ list of pipeline companies and the OGJ150. This observation shows that the pipeli ne industry is still largely based upon firms serving regional

market.

The top 20 companies maintain about 6 1 percent of the total pipeline mileage and transport about 5 6 percent of the volume of the industry ( Table 2

- 21 )

. Operating revenues of t he

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- 46 top 2 0 companies equaled $ 1 2

. 1 billion, representing 59 percent of the total operating revenues

f or major and non

- major companies. The top 20 companies also account for 59 percent of the net income of the industry.

Table 2

- 21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income) , 20 12

Rank Company Transmission (miles) Vol. trans for others (MMcf) Operating Revenue ($000s) Net Income ($000s)

1 Dominion Transmission Inc. 3,687 653,272 903,404 256,010 2 Texas Eastern Transmission LP 9,563 1,747,856 956,536 242,277 3 Florida Gas Transmission Co. LLC 5,336 979,857 775,375 204,968 4 Transcontinental Gas Pipe Line Co. LLC 9,378 3,274,209 1,254,154 194,573 5 Tennessee Gas Pipeline Co. 13,780 2,626,030 1,015,928 190,970 6 Columbia Gas Transmission LLC 9,708 1,305,728 813,185 186,594 7 Natural Gas Pipeline Co of America 8,911 1,511,844 687,366 176,447 8 Southern Natural Gas Co. 7,079 1,005,151 584,828 162,275 9 ETC Tiger Pipeline LLC 196 546,137 279,572 134,934 10 Northern Natural Gas Co. 14,949 928,977 587,768 134,715 11 Panhandle Eastern Pipe Line Co., LP 6,406 581,926 338,787 123,392 12 Texas Gas Transmission LLC 5,880 1,052,070 417,809 106,994 13 Kern River Gas Transmission Co. 1,718 928,206 383,393 105,447 14 Rockies Express Pipeline LLC 1,698 822,587 786,225 103,427 15 CenterPoint Energy Gas Transmission Co., LLC 5,954 1,143,552 437,836 103,290 16 Colorado Interstate Gas Co. 4,253 788,905 397,292 100,902 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 87,119
TOTAL FOR TOP 20 120,430 22,761,932 12,119,828 2,895,109
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 Financial Reporting Syste m (FRS) collects financial and operating information from a subset of the U.S. major energy producing companies and reports summary information in the publication “The Performance Profiles of Major Energy

Producers”

. 10 

### This information is used in annual report to Congress, as well as is released to the

10 The “Performance Profiles of Major Energy Producers 2009” released on February 25, 2011 is the most recent

release of this report.

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- 47 public in aggregate form. While the co mpanies that report information to FRS each year changes,

EIA makes an effort to r etain sufficient consistency such that trends can be evaluated. For 200 9

, there are 30 companies in the FRS 11 

### that accounted for 4 3 percent of total U.S. crude oil and

NGL pro duction, 43 percent of natural gas production, 7 8 percent of U.S. refining capacity , and

0. 3 percent of U.S. electricity net generation ( U.S. EIA, 201 1 ). Table 2

- 22 shows a series of

financial trends in 2008 dollars selected and aggregated from FRS firms’ financial statement s

. The table shows operating revenues and expenses rising significantly from 1990 to 2008, with operating income (the difference between operating revenues and expenses) rising until dropping off significantly in 2009

. Interest expenses remained relatively flat during this period. Meanwhile, recent years have shown that other income and income taxes have played a more significant r ole for the industry. Net income has risen as well, although 2008 and 2009 saw a decline from previous periods, as oil and natural gas prices declined significantly during the

latter half of 2008.

11 Alenco, Alon USA, Anadarko Petroleum Corporation, Apache Corporation, BP America, Inc., Chalmette, Chesapeake Energy Corpo ration, Chevron Corporation, CITGO Petroleum Corporation, ConocoPhillips, Devon Energy Corporation, El Paso Corporation, EOG Resources, Inc., Equitable Resources, Inc., Exxon Mobil Corporation, Hess Corporation, Hovensa, Lyondell Chemical Corporation, Mara thon Oil Corporation, Motiva Enterprises, L.L.C., Occidental Petroleum Corporation, Shell Oil Company, Sunoco, Inc., Tesoro Petroleum Corporation, The Williams Companies, Inc., Total Holdings USA, Inc., Valero Energy Corp., Western Refining, WRB Refining L LC, and XTO Energy, Inc.

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- 48 Table 2

- 22 Selected Financial Items from Income Statements (Billion 2008 Dollars)

Year Operating Revenues Operating Expenses Operating Income Interest Expense Other Income* Income Taxes Net Income 1990 766.9 706.4 60.5 16.8 13.6 24.8 32.5 1991 673.4 635.7 37.7 14.4 13.4 15.4 21.3 1992 670.2 637.2 33.0 12.7

- 5.6 12.2 2.5 1993 621.4 586.6 34.8 11.0 10.3 12.7 21.5 1994 606.5 565.6 40.9 10.8 6.8 14.4 22.5 1995 640.8 597.5 43.3 11.1 12.9 17.0 28.1 1996 706.8 643.3 63.6 9.1 13.4 26.1 41.8 1997 673.6 613.8 59.9 8.2 13.4 23.9 41.2 1998 614.2 594.1 20.1 9.2 11.0 6.0 15.9 1999 722.9 682.6 40.3 10.9 12.7 13.6 28.6 2000 1,114.3 1,011.8 102.5 12.9 18.4 42.9 65.1 2001 961.8 880.3 81.5 10.8 7.6 33.1 45.2 2002 823.0 776.9 46.2 12.7 7.9 17.2 24.3 2003 966.9 872.9 94.0 10.1 19.5 37.2 66.2 2004 1,188.5 1,051.1 137.4 12.4 20.1 54.2 90.9 2005 1,447.3 1,263.8 183.5 11.6 34.6 77.1 129.3 2006 1,459.0 1,255.0 204.0 12.4 41.2 94.8 138.0 2007 1,475.0 1,297.7 177.3 11.1 47.5 86.3 127.4 2008 1,818.1 1,654.0 164.1 11.4 32.6 98.5 86.9 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 interest expense), discontinued operations, extraordinary items, and accounting changes. Totals may not sum due to independent 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 FRS companies. For U.S. petroleum

- related business activities, oil and natural g as production was the most profitable line of business relative to refining/marketing and pipelines, sustaining 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 production in 2008 and 2009

. Electric power generation and sales emerged in 2008 as a highly profitable line of business for the FRS companies and declined significantly in 2009

.

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- 49 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/net investment in place. * The downstream natural gas and electric power lines of business were added to the EIA

- 28 survey form beginning with the 2003 reporting year.



### The oil a nd natural gas industry also produces significant tax revenues for local, state,

and federal authorities. Table 2

- 24 shows income and production tax t rends from 1990 to 200 9 for FRS companies

. The column with U

. S . federal, state, and local taxes paid or a ccrued includes deductions for the U.S. Federal Investment Tax Credit ($198 million in 2008) 12 

### and the effect of

the Alter n ative Minimum Tax ($34 millio n 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. authorities.

12 Data was withheld in 2009 to avoid disclosure.

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- 50 Table 2

- 24 Income and Production Taxes, 1990

- 200 9 (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 Credit and U.S. State and Local Income Taxes were withheld 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 countries. As can be seen in Table 2

- 24 , foreign taxes paid far exceeds domestic taxes paid. Other non

- income production taxes p aid , which have risen

almost three

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

- related taxes.

2.7 References

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

. Congressional Research Servic e

. R40894

. Argonne National Laboratory. 2009. Produced Water Volumes and Management Practices in the United States. ANL/EVS/R

- 09/1

. Hyne, N.J. 2001. Nontechnical Guide to Petroleum Geology, Exploration, Drilling and Production

. Tulsa, OK: Penwell Books.

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- 51 Independent Petroleum Association of America. 2009. Profile of Independent Producers.

< http://www.ipaa.org/ wp

content/uploads/downloads/2011/12/2009ProfileOfIndependentProducers.pdf > Accessed March 30, 2011.

Manning , F.S. and R.E. Thompson. 1991. Oil Field Processing of Petrol eum

– Volume 3: Produced and Injection Waters . Tulsa, OK: Penn Well Books.

Oil and Gas Journal . “ US Pipeline Operators Sink Revenue Growth into Expansion .” Septe mber 2 , 201 3

.

Oil and Gas Journal . “OGJ150 Earnings Down as US Production Climbs .” September 2

, 201 3

.

Oil and Gas Journal . “Special Report: Worldwide Gas Processing: New Plants, Data Push Global Gas Processing Capacity Ahead in 2009.” June 7, 2010.

U.S. Energy Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial Link betw een Natural Gas Production and It s Transportation to Market

. < http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2006/ngprocess/ngproc ess.pdf > Accessed February 2, 2011.

U.S. Department of Energy. 2013

. Modern Shale Gas Development in the Unit ed States: An Update . < http://www.netl.doe.gov/File20Library/Research/Oil

- Gas/shale

- gas

- primer

update

- 2013.pdf > Accessed December 19, 2014

.
U.S. Energy Information Administration (U.S. EIA). 201 2 . Annual Energy Rev iew 2011 (AER).

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

U.S. Energy Information Administration (U.S. EIA). 2010. Oil and Gas Lease Equi pment and Operating Costs 1994 t hrough 2009

< http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/cost_i ndices_equipment_ production/current/coststudy.html > Accessed March 30, 2011.

U.S. Energy Information Administration (U.S. EIA). 201 3

. Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Pro ved Reserves 20 11

. < http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_re serves/cr.html > Accessed September 15 , 201 3

.
U.S. Energy Information Administration (U.S. EIA). 201 1

. Performance Profiles of Major Energy Producers 200 9

. < http://www.eia. gov/finance/performanceprofiles > Accessed September 15 , 201 3

. U.S. Energy Information Administration (U.S. EIA). 201 4

. Annual Energy Outlook 201 4

. < http://www.eia.gov/forecasts/aeo/ > Accessed March 17, 2014

.

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- 52 U.S. Environmental Protection Agency (U.S. EPA)

, Office of Air Quality Planning and Standards. 1996. Economic Analysis of Air Pollution Regulations: Oil and Natural Gas Production

. < http://www.epa.gov/ttnecas1/regdata/IPs/Oil20and20NG20Production20and20NG20Tra nsmission_IP.pdf > Accessed December 19, 201 4

.
U.S. Environmental Protection Agency (U.S. EPA). 2000. EPA Office of Compliance Sector Notebook Project: Profile of the Oil and Gas E xtraction Industry

. EPA/310

- R

- 99

- 006.

< http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks /oil gas.pdf > Accessed December 19, 2014.

U.S. Environmental Protection Agency (U.S. EPA) . 2004. Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. EPA/816

- R

- 04

- 003

.

U.S. Environmental Protectio n Agency (U.S. EPA). 2012

. 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/oi l_natural_gas_final_neshap_nsps_ria.pdf > Accessed December 19, 2014.

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- 1 3 EMISSIONS AND ENGINE ERING COSTS

3.1 Introduction

This chapter describes the emissions and engineering cost analysis for the proposed NSPS. The first section discusses the emissions points and control options. The following section describes each step in the emissions and engineering cost analysis and presents overview results. Detailed tables describing the impacts for each source and option can be found at the end of the chapter. We provide r eference to the more

- detailed Technical Support Document (TSD) prepared by the U.S. EPA for the reader interested in a greater level of detail. 13



### 3.2 Sector Emissions Overview

Before going into detail on emissions points and pollution controls, it is useful to provide estimates of overall emissions from the crude oil and natural gas industry to provide context for

estimated reductions as a result of the proposed rule

. Crude oil and natural gas production sector
VOC emission s are approximately 2.8 million tons , a ccording to the 2011 U.S. EPA National Emissions Inventory (NEI)

. The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

- 2013 (published April 2015) estimates 201 4 3 methane emissions from Petroleum and Natural Gas Systems (not including petroleum r efineries and petroleum transportation) to be 182 MMt

CO 2 

### Eq

. The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

- 2012 (published April 2014) estimates 2012 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refine ries and petro leum transportation) to be 192 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, 2015 ).

In 2012, total methane emissions from the oil and gas industry represented nearly 29

pe rcent 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 petroleum and natural gas systems being the second largest

13 U.S. EPA. 2015. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas

Production, Transmission and Distribution . Background Technical Support Document for the Proposed Amendments to the New Source Performance Standards.

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- 2 contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2014).

The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

- 2013 (published April 2015) estimates 2014 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries and petroleum transportation) to be 182 MMt CO 2 

### E q. 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 ga s systems being the largest contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2015 ).

It is important to note that the 2013 GHG emissions estimates do not include methane

emissions from hydraulically fractured and re

- fractured oil well complet ions due to lack of available data when the 2013 GHG Inventory estimate was developed. The estimate in this proposed rule includes an adjustment for hydraulically fractured oil wells, and such an adjustment is also being considered as a planned improvement in the 2014 Inventory (to be published April 2016). This adjustment would increase 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 hydraulically 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 part of the NSPS review. This section provides a basic description of emissions sources and the controls evaluated for each source to facilitate the reader’s understanding of the economic impact and benefit analyses. The reader who is interested in more technical detail on the engineering and cost basis of the analysis is referred to the relevant chapters within the TSD.

Completions of Hydraulically Fractured and Re

- fractured Oil Wells : Well completion activities include multiple steps after the well bore hole has reached the target depth. The highest emi ssions are from venting of natural gas to the atmosphere during flowback.

Flowback emissions are short

- term in nature and occur as a specific event during completion of a new well or during activities that involve re

- drilling or re

- fracturing an existing w ell. The TSD

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- 3 separately considers developmental wells and exploratory wells. Developmental wells are wells drilled within known boundaries of a proven oil or gas field, while exploratory or “wildcat” wells are wells drilled in areas of new or unknown poten tial.

The EPA considered the same two techniques that have been proven to reduce emissions

from w ell completions : reduced emissions completions (RECs) and completion combustion. The use of a REC not only reduces emissions but delivers natural gas product t hat would typically be

vented to the sales meter. Completion combustion destroys 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 emissions throughout the oil and natural gas sector. Fugitive emissions occur when connection points are not fitted properly or when seals and gaskets start to deteriorate. Changes in pr essure 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

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

The TSD considers fugitive e missions from production well sites, gathering line and boosting stations, and natural gas transmission/storage compressor stations. There are two options for reducing methane and VOC emissions from leaking components: a leak monitoring program based on in dividual component monitoring using EPA Method 21 for leak detection combined with a leak correction, and a leak monitoring program based on the use of OGI leak detection combined with leak correction. The former option was evaluated during NSPS subpart

OO OO and was not found to be cost

- effective. Therefore, the second option of reducing fugitive emissions using a leak monitoring plan based on OGI for leak detection combined with leak correction was evaluated to determine the potential emission reductions a nd the cost of control. In addition, alternative frequencies for fugitive emissions surveys were considered: annual, semiannual, and quarterly.

Pneumatic controllers : Pneumatic controllers are automated instruments used for

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- 4 maintaining a process condition such as liquid level, pressure, pressure differential, and temperature. In many situations across all segments of the oil and natural gas industry, pneumatic controllers make use of the available high

- pressure natural gas to operate 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 powe r other than pressurized natural gas. Examples include solar, electric, and instrument air. At oil and gas
locations with electrical service, non

- gas

- driven controllers are typically used. Continuous bled pneumatic controllers can be classified into two ty pes based on their emissions rates: (1) high

bleed controllers and (2) low

- bleed controllers. A controller is considered to be high

- bleed when the continuous bleed emissions are in excess of 6 standard cubic feet per hour (scfh), while low

bleed devices bl eed at a rate less than or equal to 6 scfh. EPA evaluated 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 r eadily available (GRI/EPA, 1996 ) and can be a significant source of methane and VOC emissions. Pneumatic chemical and methanol injection pumps are generally used to pump fairly small volumes of chemicals or methanol into well

bores, surface equipment, and pipelines. Typically, these pumps include plunger pumps w ith a diaphragm or large piston on the gas end and a smaller piston on the liquid end to enable a high discharge pressure with a varied but much lower pneumatic supply gas pressure. They are typically used semi

- continuously with some seasonal variation. Pn eumatic 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 chemical and methanol injection pumps. The usage of these pumps is episodic includin g transferring bulk 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 when 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 pressure of the pneumatic supply gas, the number of

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- 5 pressure ratio’s between the pneumatic supply gas pressure and the fluid d ischarge pressure, and the mechanical inefficiency of the pump. As discussed in the white papers, we identified several options for reducing methane and VOC emissions: replace natural gas

- assisted pump with instrument air pump, replace natural gas

- assisted pump with solar

- charged direct current pump (solar pumps), replace natural gas

- assisted pump with electric pump, and route pneumatic pump

emissions to a control device. EPA evaluated the impact of routing pump emissions to a pre

existing on

- site control d evice.

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 the consumer. The types of compressors that are used by the oil and gas industry as prime movers are reciprocating and centrifugal compressors. Centrifugal compressors use either wet or dry seals.

Emissions from compressors occur when natural gas leaks around moving parts in the compressor. In a reciprocating compressor, emissions occur when natural gas leaks around the piston rod when pressurized natural gas is in the cylinder. 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. The potential control options reviewed for reducing emissions from reciprocating compressors include 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 the type of seal used: either “wet”,

which use oil circulated at hi gh pressure, or “dry”, which use a thin gap of high pressure gas. The use of dry gas seals substantially reduces emissions. In addition, they significantly reduce operating costs and enhance compressor efficiency. L imiting 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.

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- 6 3.4 Engineering Cost Anal ysis

In this section, we provide an overview of the engineering cost analysis used to estimate the additional private expenditures industry may make to comply with the proposed NSPS. A detailed discussion of the methodology used to estimate cost impacts is presented in the TSD,

which is published in the Docket

The following sections describe each step in the engineering cost analysis. First, representative facilities are established for each source category, including baseline emissions and control options . The regulatory alternatives include different variations of regulatory requirements considered for inclusion in the proposed 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 year. In addition to emissions reductions, some control optio ns result in natural gas recovery , which ca n then be combusted for useful processes or sold. The national cost estimates include estimated revenue from product recovery where applicable. Finally, national

- level cost

- effectiveness is calculated.

3.4.1 Control Options

For each emissions source, point, and control option, the TSD develops a representative facility. The characteristics of this facility include typical equipment, operating characteristics, and representative factors including baseline emissions and the costs, emissions reductions, and product recovery resulting from each control option.

Table 3

- 1 shows the emissions sources, points, and controls analyzed in three NSPS regulatory options, which we term Option 1, Option 2, and Option 3. Option 2 was selected for proposal. The proposed Option 2 co ntains reduced emission completion (REC) and completion combustion requirements for a subset of newly completed drilled oil wells that are hydraulically

fractured or refractured

. Option 2 also requires fugitive emissions survey and repair programs be perfo rmed at newly drilled or refractured oil and natural gas well sites, new or modified gathering and boosting stations, and new or modified transmission and storage compressor stations. Option 2 also requires reductions from centrifugal compressors, reciproc ating

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- 7 compressors, pneumatic controllers, and pneumatic pumps throughout the oil and natural gas
source category.

Formatted: 05 BodyText

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- 8 Table 3

- 1 Emissions Sources and Controls Evaluated at Propo sal for the NSPS

Emissions Sources Emissions Control Option 1 Option 2 (proposed) Option 3
Well Completions
Hydraulically Fractured Development Oil Wells REC or Combustion Com

bustion REC/ Com

bustion REC/ Com

bustion 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 Annual Semiannual Quarterly

Transmission Compressor Stations Monitoring and Maintenance Annual 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 unselected Options 1 and 3 differ from the selected Option 2 with respect to the requirements for hydraulically fractured oil well completions and fugitive emissions at well sites. While Option 2 requires that development oil well completions use RECs in all feasible circumstances, Option 1 requires flaring only. Flaring completion emissions is less costly than
RECs, but results in m ore combustion

- related secondary emissions and does not recover the

natura l gas. Option 1 requires less frequent fugitive emissions surveys at well sites

– on an annual schedule as opposed to the semiannual schedule in the selected option, while Option 3 requires quarterly monitoring. More frequent surveys result in higher costs , higher emissions reductions, and increased natural gas recovery

.

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- 9 3.4.2 Projection of Incrementally Affected Facilities

The second step in estimating national costs and emissions impacts of the proposed rule is projecting the number of incrementally affected fa cilities. Incrementally affected facilities are facilities that would be expected to change their emissions control activities as a result of the proposal. Facilities in states with similar state

- level requirements are not included within incrementally aff ected facilities.

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

facilities are facilities which are new or modified si nce the effective year of the proposal. I n 2020 affected facilities are those which are newly established or modified in 2020. Over time more facilities are newly established or modified in each year, and to the extent the facilities remain in operation in future years, the total number of facilities subject to the NSPS accumulates. In 2025, affected facilities include facilities newly established or modified in 2025, but also facilities which were newly established or modified from 2020 through 2024 and ar e still operating in

2025.

The EPA has projected affected facilities using a combination 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). Th e EPA derived typical counts for new compressors, pneumatic controllers, and pneumatic pumps by averaging the year

- to

- year increases over the past ten years in the Inventory. New hydraulically fractured oil well completions and well sites are based on proj ections and growth rates consistent with the drilling activity in the 2014 Annual Energy Outlook. If recent decreases in oil prices lead to lower oil drilling activity in the United States, then the costs and emissions reductions resulting from the

rule wo uld also be reduced. [Placeholder for qualitative language about AEO2015.]

We also reviewed state regulations , which require mitigation measures for many emission sources in the oil and natural gas sector. State regulations in Colorado and Wyoming both req uire RECs for hydraulically fractured oil and gas wells. Colorado , Wyoming, Utah, and Ohio also require fugitive emissions monitoring at well sites and compressor stations. Applicable facilities

in these states are not included in the estimates of incremen tally affected facilities presented in

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- 10 the RIA, as those states already have similar requirements to the federal standards. A m ore
detailed 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 proposed NSPS requirements because of a gas

- to

- oil ratio (GOR) of 300 or below.

.

Table 3

- 2 Number of Incremen tally Affected Sources for the NSPS, All Options

Emissions Sources Incrementally Affected Sources

2020 2025 * Hydraulically Fractured and Re

- fractured Oil Well Completions 15,000 14,676 15,000 14,967 Fugitive Emissions 22,000 22,360 140,000 140,788 Pneumatic Pumps 3,000 2,962 18,000 17,772 Compressors 68 68 410 408
Pneumatic Controllers 210 210 1,300 1,260
Total 40,000 40,276 180,000 175,195 * In addition to newly affected sources in 2025, incrementally 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.



### Table 3

- 2 presents the estimates of the number of incrementally affected sources for this proposal after accoun ting for state regulations as described above. Note t hat 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 completions being a one

- time activity in a given year, while other sources are affected and remain affected as they continue to operate, thus these

sources accumulate over time. The estimates for that hydraulically fractured and re

- fractured oil well completions and fugitive emissions at well sites (a l arge fraction of the incrementally affected sources under the proposed rule fugitive emissions provisions) include both new and modified sources. The estimates for other sources are based upon projections of new sources
alone. While some of these sources, particularly pneumatic pumps and controller s , are likely to be predominantly new sources, the impact estimates may be under

- estimated by the under

represented modified sources . In the preamble to the proposed rule, t he EPA solicits comments

on these projection methods as well as solicits information that would improve our est imate of

the turnover rates or rates of modification of relevant sources. Formatted: 05 BodyText, Indent: First line: 0", Space After: 0 pt, Line spacing: single

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- 11 3.4.3 Emissions Reductions

Table 3

- 3 summarizes the national emissions reductions for the evaluated NSPS

emissi ons sources and points for 2020 and 2025

. These 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

T able 3

- 2 summarizes the affected facilities, aggregating 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 provided in the TSD. Please note that all results have been rounded to two significant digits minor differences in values occur between the TSD and

this RIA due to independent rounding of intermediate values

.

Table 3

- 3 Emissions Reductions from Proposed NSPS, 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 3,100,000 Fugitive Emissions 33,000 8,700 330 750,000 Pneumatic Pumps 5,400 1,500 57 120,000 Compressors 1,600 43 1 36,000 Pneumatic Controllers 590 16 0 13,000
Total 180,000 120,000 400 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 210,000 57,000 2,200 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 400,000 180,000 2,500 9,000,000



### 3.4.4 Product Recovery

The annualize d cost estimates presented below include revenue from additional natural gas recovery in the production and processing segments. Several emission controls for the NSPS Formatted Table

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- 12 capture methane and VOC emissions that otherwise would be vented to the atmosphere. A large proportion of the averted me thane 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 emissions on an estimate of the amount of natu ral gas that would not be emitted during one year for the control.

The standards that result in natural gas recovery are: RECs at hydraulically fractured oil wells, fugitive emissions monitoring and repair, rod packing replacement in reciprocating

compress ors, and low

- bleed pneumatic devices. The proposed requirements for completions at exploration and delineation wells, pneumatic pumps, and centrifugal compress ors do not result in natural gas recovery . In some of these cases, alternative control strategies do result in natural gas

recovery , but these alternative controls were not assumed 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 revenue included in annualized cost calculations. When including the additional natural gas recovery in the cost analysis, we assume that producers are paid $4 per thousan d 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 reflect the AEO estimate but simultaneously be conservatively low.

Natural gas recovery at any point in the system provide benefits to the energy syste m and to the public. However, due to contractual arrangements, transmission a nd storage companies do not always benefit from lowering the leak rate of their operations because they do not necessarily own the gas, and fixed loss rates are included in long

- term contracts. As a result , EPA exclude s
revenue from natural gas recovery in estimating compliance costs for the transmission and storage segment. This approach likely overestimates the long

- term compliance cost of the

controls.

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- 13 Table 3

- 4 Estimated Natural Gas Recovery (Mcf) in 2020 and 2025

Source/Emissions Point 2020 2025 Gas recovery (Mcf) Revenue from
recovery (2012$) Gas recovery (Mcf) Revenue from
recovery (2012$) Oil Well Completions 6,200,000 6,207, 606 $25,000,000 $24,830, 422 6,200,000 6,205,80 7 $25,000,000 $24,823, 228 Fugitive Emissions 1,900,000 1,901, 907 $7,300,000 $7,254,71 6 12,000,000 12,361, 199 $47,000,000 $47,327, 319 Pneumatic Pumps 0 0 $0 $0 0 0 $0 $0 Compressors 76,000 75,548 $0 $0 450,000 453,285 $0 $0 Pneumatic Controllers 30,000 30,295 $0 $0 180,000 181,768 $0 $0

Total 8,200,000 8,215, 355 $32,000,000 $32,085, 138 19,000,000 19,202, 060 $72,000,000 $72,150, 548



### A s natural gas prices can increase or decrease rapidly, the estimated engineering compliance costs can vary when revenue from additional natural gas recovery is included. There is also geographic variability in wellhead prices, which can also influence estimated engineering

costs. For the proposed option, a $1/Mcf change in the wellhead price causes a change in estimated engineeri ng compliance cost s of about $8. 2 million in 2020 and $19 million in 2025,

in 2012 dollars.

3.4.5 Engineering Compliance Costs

Ta ble 3

- 6 summarizes the capital and annualized costs for the evaluated emissions sources and points. The detailed description of costs estimates is provided in TSD

. To estimate total annualized engineering compliance costs, we added the annualized costs of each item without accounting for different expected lifetimes. This approach is mathematically equiv alent 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.

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- 14 Table 3

- 5 Engineering Compliance Cost Estimates in 2020 and 2025

Source/Emissions Point Compliance Costs, 2020 Compliance Costs, 2025

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

Costs (2012$)
Oil Well Completions and Recompletions $150,000,000 $120,000,000 $150,000,000 $120,000,000 Fugitive Emissions $22,000,000 $47,000,000 $140,000,000 $290,000,000 Pneumatic Pumps $5,900,000 $840,000 $36,000,000 $5,100,000 Compressors $540,000 $250,000 $3,200,000 $1,500,000 Pneumatic Controllers $48,000 $5,200 $290,000 $31,000 Reporting and Recordkeeping $0 $1,400,000 $0 $4,100,000
Total $180,000,000 $170,000,000 $330,000,000 $420,000,000



### Engineering capital costs were annualized using a 7 percent interest rate. Section 3. 4 provides a comparison to using a 3 percent interest rate. D ifferent emissions control options were annualized using expected lifetimes that were determined to be most appropriate for individual options. For control option s evaluated for the NSPS, the following lifetimes were used:

• Reduced emissions completions and combustion devices: 1 year (more discussion of the selection of a one

- year lifetime follows in this section)

• Fugitive emissions monitoring program design: 8 year s

• Reciprocating compressors rod packing: 3.8

– 4.4 years

• Centrifugal compressors, pneumatic controllers, and pneumatic pumps: 10 year s
Reporting and recordkeeping costs were drawn from t he information collection requirements
(ICR) in this proposed rule that have been submitted 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 year 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 the proposed standards for each source

in 2020 and 2025. The proposed NSPS includes standards for both methane and VOC reductions. Formatted Table

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- 15 As discussed in the preamble to this action, c ost

- effectiveness analysis allows comparisons of relative costs and outcomes (effects) of two or more options. In general, co st

- 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 cost

effectiveness analysis is not intended to constitute or approximate a cost

- benefits analysis but rather provides a metric of the relative cost to reduction ratios of various control options.

The estimation and interpretation of cost

- effectiveness values is relatively straightforward when an abatement measure controls a single pollutant. Increasingly, however, air pollution reduction programs require reductions in emissions of multiple pollutants, and in such pro grams multipollutant controls may be employed. Consequently, there is a need for determining cost

effectiveness for a control option across multiple pollutants (or classes of multiple pollutants). This is the case for the current proposal where EPA is prop osing to directly regulate both

methane and VOC

.

To assign the entire annualized cost to the reduction in emissions of a single pollutant reduced by the multipollutant control option is appropriate when reductions of the other pollutants are considered to cobenefits with no cost. However, u nder the current proposal, methane and VOCs are both directly regulated ; therefore, reductions of each pollutant must be properly considered benefits, not co

- benefits , and consideration of only one of the regulated pollu tants is not appropriate.

Alternatively, all annualized costs can be allocated 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 em ission reduction is assessed based on the

full cost of the control. However, this approach

, which is often used for assessing single

pollutant controls, evaluates emission reduction of each pollutant separately, assuming that each
bears the entire cost, an d thus inflates the control cost in the multiple of the number of additional pollutants being reduced. This approach therefore over

- 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 control option. Another approach allocates the

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- 16 annualized cost to the sum of the individual pollutant emission reductions addressed by the multipollutant control option. The multipollutant cost

- effectiv eness 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 health and environmental impacts , and

therefore s umming the pollutants to derive the denominator of the cost

- effectiveness equation (i.e., assuming a ton of methane is equivalent in its impacts to a ton of VOC) is inappropriate.

For purposes of this proposal, we have identified and are proposing to use two approaches for considering the cost of reducing emissions 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 reasonable for reducing any of the targeted emissions alone, the cost of such control is clearly 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 t o only a portion of the emission reduction, it does not overstate the cost. It also does not require unreasonable assumptions 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 approach 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 for reducing a ll 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 proporti on to the relative percentage reduction of each pollutant controlled by mass . For example, in this proposal both methane and VOC emissions are reduced in equal proportion by the multipollutant control option. As a result, half of the control costs are allo cated to methane,

the other half to VOC. This approach similarly does not inflate the control cost nor requires unreasonable assumptions about the equivalency of the impacts between a ton of methane and

VOC emission reduction.

We believe that both approac hes discussed above are appropriate for assessing the reasonableness of the multipollutant controls considered in this action. As such, in our analyses

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- 17 below, if a device is cost effective under either of these two approaches, we find it to be cost

effecti ve. The EPA recognize, however, not all situations where multipollutant controls are applied are the same, and that other approaches , including those described above as inappropriate
for this action, might be appropriate in other instances.

Under the sing le pollutant cost

- effectiveness approach , the total national compliance costs are divided by the emissions reductions for methane and VOC separately (Table 3

- 6) . This approach does not account for the combined emissions reductions of both pollutants.

Tabl e 3

- 6 Engineering Compliance Cost

- Effectiveness Estimates in 2020 and 2025, Single Pollutant Approach

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 $906 $1,100 $1,081 $40 $40 $900 $896 $1,100 $1,070 $39 $39

Fugitive Emissions $1,400 $1,337 $5,300 $5,044 $62 $59 $1,400 $1,283 $5,100 $4,823 $60 $57 Pneumatic Pumps $160 $156 $560 $561 $7 $7 $160 $156 $560 $561 $7 $7 Compressors $160 $156 $5,600 $5,641 $7 $7 $160 $156 $5,600 $5,641 $7 $7

Pneumatic Controllers $9 $9 $320 $323 $0 $0 $9 $9 $320 $323 $0 $0

Total $980 $962 $1,400 $1,368 $43 $42 $1,100 $1,029 $2,300 $2,249 $47 $45



### For the multipollutant cost

- effectiveness approach, costs are allocated proportionally to methane and VOC reductions based on the percent reduction achieved in each pollutant (Table 3

- 7) . Because the relevant oil and gas controls reduce methane and VOC in equal proportion, 50 percent of costs are allocated to each emission

. Formatted Table

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- 18 Table 3

- 7 Engineering Compliance Cost

- Effectiveness Estimates in 2020 and 2025 , Multipollutant Approach

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 $453 $540 $541 $20 $20 $450 $448 $530 $535 $20 $20

Fugitive Emissions $710 $668 $2,700 $2,522 $31 $29 $680 $642 $2,500 $2,412 $30 $28 Pneumatic Pumps $78 $78 $280 $281 $3 $3 $78 $78 $280 $281 $3 $3 Compressors $78 $78 $2,800 $2,821 $3 $3 $78 $78 $2,800 $2,821 $3 $3
Pneumatic Controllers $5 $4 $160 $162 $0 $0 $5 $4 $160 $162 $0 $0

Total $490 $481 $690 $684 $22 $21 $530 $515 $1,200 $1,124 $24 $23



### 3.4.7 Comparison of Regulatory Alternatives

Table 3

- 8 presents a comparison of the regulatory alternatives through each step of the emissions analysis in 2020 and 2025. All three options would affect the same number of sources. The differences in methane and VOC reductions between the options result from dif ferences in required fugitive emissions survey frequency. Options 1, 2, and 3 include requirements for annual, semiannual, and quarterly fugitive emissions surveys, which are assumed to respective reductions in emissions of 40 percent, 60 percent, and 80 p ercent. Natural gas recovery also

varies as a result of survey frequency. Option 1 results in lower natural gas recovery and capital costs than the other options because of the requirement to flare oil well completions, as opposed to using REC when feasibl e in the proposed option. Variation between the options in capital costs are also due to oil well completions, because REC and flare costs are classified as capital

costs. Formatted Table

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- 19 Table 3

- 8 Comparison of Regulatory Alternatives Regulatory Alternative

Option 1 Option 2 (proposed) Option 3 Impacts in 2020
Affected Sources 40,000 40,276 40,000 40,276 40,000 40,276 Emissions Reductions Methane Emissions Reduction (short tons/year) 170,000 165,072 180,000 176,072 190,000 187,073 VOC Emissions Reduction (short tons/year) 120,000 120,870 120,000 123,786 130,000 126,701 Natural Gas Recovery (Mcf) 1,400,000 1,373,780 8,200,000 8,215,355 8,800,000 8,849,324 Compliance Costs Capital Costs (2012$) $83,000,000 $69,564, 346 $180,000,000 $162,47 1,823 $180,000,000 $162,47 1,823 Annualized Costs (2012$) $85,000,000 $82,139, 790 $170,000,000 $169,30 6,553 $210,000,000 $209,88 2,613 Cost

- Effectiveness (Single Pollutant Approach) Methane (2012$ / short ton) $510 $498 $980 $962 $1,100 $1,122 VOC (2012$ / short ton) $700 $680 $1,400 $1,368 $1,700 $1,657 Cost

- Effectiveness (Multipollutant Approach) Methane (2012$ / short ton) $260 $249 $490 $481 $570 $561 VOC (2012$ / short ton) $350 $340 $690 $684 $840 $828

Impacts in 2025
Affected Sources 180,000 175,195 180,000 175,195 180,000 175,195
Emissions Reductions Methane Emissions Reduction (short tons/year) 330,000 326,499 400,000 397,963 470,000 469,427

VOC Emissions Reduction (short tons/year) 160,000 163,129 180,000 182,141 200,000 201,153

Natural Gas Recovery (Mcf) 8,900,000 8,875,853 19,000,000 19,202,06 0 23,000,000 23,322,45 9 Compliance Costs Capital Costs (2012$) $230,000,000 $147,32 9,291 $330,000,000 $240,20 9,850 $330,000,000 $240,20 9,850

Annualized Costs (2012$) $240,000,000 $222,27 2,269 $420,000,000 $409,56 0,079 $680,000,000 $663,66 0,618 Cost

- Effectiveness (Allocated Cost Approach) Methane (2012$ / short ton) $730 $681 $1,100 $1,029 $1,400 $1,414 VOC (2012$ / short ton) $1,500 $1,363 $2,300 $2,249 $3,400 $3,299 Cost

- Effectiveness (Multipollutant Approach) Methane (2012$ / short ton) $360 $340 $530 $515 $720 $707 VOC (2012$ / short ton) $730 $681 $1,200 $1,124 $1,700 $1,650 Formatted Table

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- 21 3.5 Compliance Costs Estimated using 3 and 7 Percent Discount Rate s

Ta ble 3

- 9 shows that the choice of discount rate has very minor effect on the nationwide

annualized costs of the proposed option

.

Table 3

- 9 Annualized Costs using 3 and 7 Percent Discount s Rate s for the Proposed NSPS in 2020 and 2025
Nationwide Annualized Costs, 2020 (2012$) Nationwide Annualized Costs, 2025 (2012$)

7 percent 3 percent 7 percent 3 percent Oil Well Completions $120,000,000 $122, 716,272 $120,000,000 $122, 716,272 $120,000,000 $123, 781,169 $120,000,000 $123, 781,169 Fugitive Emissions $47,000,000 $44,11 5,186 $46,000,000 $43,90 4,722 $290,000,000 $275, 101,961 $290,000,000 $273, 787,783 Pneumatic Pumps $840,000 $843,444 $690,000 $694,474 $5,100,000 $5,060, 666 $4,200,000 $4,166, 841 Compressors $250,000 $245,387 $230,000 $231,437 $1,500,000 $1,472, 323 $1,400,000 $1,388, 621 Pneumatic Controllers $5,200 $5,240 $4,000 $3,993 $31,000 $31,437 $24,000 $23,959 Reporting and Recordkeeping $1,400,000 $1,381, 023 $1,400,000 $1,381, 023 $4,100,000 $4,112, 522 $4,100,000 $4,112, 522

Total $170,000,000 $169, 306,553 $170,000,000 $168, 931,920 $420,000,000 $409, 560,079 $420,000,000 $407, 260,895



### T he c hoice of discount rate has a small effect on nationwide annualized costs. The compliance costs related to oil well completions and fugitive emissions surveys occur in each

year, so the interest rate has little impact on annualized costs for these sources. The annualized costs for pneumatic pumps, compresso rs, and pneumatic controllers are sensitive to interest rate,

bu t 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 2020 and 2025.

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- 22 Table 3

- 10 Incrementally Affected Units, Emissions Reductions and Costs , Option 1, 2020

Source/Emissions Point Incrementally Incr ementally Affected Units Nationwide Emissions Reductions National Costs (2012$)

Methane (short

tons /year ) VOC (short ton s s/year ) HAP (short tons /year ) Methane (metric tons CO 2 Eq.) Capital Costs Ann. Costs With Addl. Revenues Well Completions Hydraulically Fractured Development Oil Wells 14,000 13,806 130,000 127,477 110,000 106,749 13 13 2,900,000 2,891,131 $51,000,000 $51,400, 207 $51,000,000 $51,400,207
Hydraulically Fractured Wildcat and Delineation Oil Wells 870 870 8,000 8,033 6,700 6,727 1 1 180,000 182,186 $3,200,000 $3,239,01 0 $3,200,000 $3,239,010

Fugitive Emissions

Well Pads 22,000 22,080 17,000 17,224 4,800 4,788 180 181 390,000 390,624 $18,000,000 $6,844,8 00 $25,000,000 $23,495,148
Gathering and Boosting Stations 260 259 3,600 3,641 1,000 1,012 38 38 83,000 82,565 $4,200,000 $1,452,21 3 $1,800,000 $1,303,984

Transmission Compressor Stations 21 21 1,100 1,136 31 31 1 1 26,000 25,768 $340,000 $117,747 $260,000 $226,353
Pneumatic Pumps

Well Pads 3,000 2,962 5,400 5,407 1,500 1,503 57 57 120,000 122,618 $5,900,000 $5,924,00 0 $840,000 $843,444
Gathering and Boosting Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0
Transmission and Storage Compressor Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0

Pneumatic Controllers

- Natural Gas Transmission and Storage Stations 67 67 1,500 1,459 40 40 1 1 33,000 33,096 $470,000 $466,916 $130,000 $131,242
Reciprocating Compressors

Natural Gas Transmission and Storage Stations 1 1 110 111 3 3 0 0 2,500 2,519 $72,000 $71,783 $110,000 $114,146
Centrifugal Compressors

Natural Gas Transmission and Storage Stations 210 210 590 585 16 16 0 0 13,000 13,272 $48,000 $47,670 $5,200 $5,234

Reporting and Recordkeeping All 0 0 0 0 $0 $1,400,000 $1,381,023

TOTAL 40,000 40,276 170,000 165,072 120,000 120,870 290 292 3,700,000 3,743,778 $83,000,000 $69,564, 346 $85,000,000 $82,139,790 Formatted

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- 23

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- 25 Table 3

- 11 Incrementally Affected Units, Emissions Reductions and Costs , Option 1, 2025

Source/Emissions Point Incrementally Affected Units Nationwide Emissions Reductions National Costs (2012$)
Methane

(short tons) Methane (short tons/year) VOC (short tons) VOC

(short tons/year) HAP (short tons) HAP (short

tons/year) Methane (metric tons CO 2 Eq.) Methane (metric tons CO 2 Eq.) Capital Costs Ann. Costs With Addl. Revenues Well Completions Hydraulically Fractured Development Oil Wells 14,000 13,801 130,000 127,43 4 110,000 106,71 3 13 13 2,900,000 2,890,153 $51,000,000 $51,382,821 $51,000,000 $51,382,8 21 Hydraulically Fractured Wildcat and Delineation Oil Wells 1,200 1,166 11,000 10,766 9,000 9,016 1 1 240,000 244,171 $4,300,000 $4,341,018 $4,300,000 $4,341,018

Fugitive Emissions
Well Pads 140,000 139,108 110,000 114,26 7 32,000 31,763 1,200 1,200 2,600,000 2,591,535 $110,000,000 $43,123,480 $160,000,000 $146,68 9,498 Gathering and Boosting Stations 1,600 1,554 22,000 21,843 6,100 6,072 230 229 500,000 495,391 $25,000,000 $8,713,278 $11,000,000 $7,823,90 2 Transmission Compressor Stations 130 126 6,800 6,817 190 189 6 6 150,000 154,606 $2,100,000 $706,482 $1,600,000 $1,358,117
Pneumatic Pumps
Well Pads 18,000 17,772 32,000 32,439 9,000 9,018 340 341 740,000 735,707 $36,000,000 $35,544,000 $5,100,000 $5,060,666
Gathering and Boosting Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0
Transmission and Storage Compressor Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0

Pneumatic Controllers

- Natural Gas Transmission and Storage Stations 400 402 8,800 8,756 240 243 7 7 200,000 198,578 $2,800,000 $2,801,495 $790,000 $787,449

Reciprocating Compressor s s

Natural Gas Transmission and Storage Stations 6 6 670 666 18 18 1 1 15,000 15,112 $430,000 $430,697 $680,000 $684,874

Centrifugal Compressors
Natural Gas Transmission and Storage Stations 1,300 1,260 3,500 3,511 97 97 3 3 80,000 79,630 $290,000 $286,020 $31,000 $31,403 Formatted: Font: 9 pt

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- 26 Reporting and Recordkeeping All 0 0 0 0 $0 $4,100,00 0 0 $4,112,522

TOTAL 180,000 175,195 330,000 326,49 9 160,000 163,12 9 1,800 1,800 7,400,000 7,404,883 $230,000,000 $147,329,29 1 $240,000,000 $222,27 2,269 Formatted: Font: 9 pt

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- 27

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- 28 Table 3

- 12 Incrementally Affected Units, Emissions Reductions and Costs , Selected Option 2, 2020

Source/Emissions Point Incrementally Affected

Units Nationwide Emissions Reductions National Costs (2012$)
Methane

(short tons) Methane (short tons/year) VOC (short tons) VOC

(short tons/year) HAP (short tons) HAP

(short tons/year) Methane (metric tons CO 2 Eq.) Methane (metric tons CO 2 Eq.) Capital Costs Ann. Costs With Addl. Revenues Well Completions Hydraulically Fractured Development Oil Wells 14,000 13,806 130,000 127,477 110,000 106,749 13 13 2,900,000 2,891,131 $140,000,000 $144,307,684 $120,000,000 $119,477,262
Hydraulically Fractured Wildcat and Delineation Oil Wells 870 870 8,000 8,033 6,700 6,727 1 1 180,000 182,186 $3,200,000 $3,239,010 $3,200,000 $3,239,010

Fugitive Emissions

Well Pads 22,000 22,080 26,000 25,835 7,200 7,182 270 271 590,000 585,936 $18,000,000 $6,844,800 $43,000,000 $41,348,780 Gathering and Boosting Stations 260 259 5,500 5,461 1,500 1,518 57 57 120,000 123,848 $4,200,000 $1,452,213 $2,800,000 $2,367,398

Transmission Compressor Stations 21 21 1,700 1,704 47 47 1 1 39,000 38,652 $340,000 $117,747 $440,000 $399,009
Pneumatic Pumps

Well Pads 3,000 2,962 5,400 5,407 1,500 1,503 57 57 120,000 122,618 $5,900,000 $5,924,000 $840,000 $843,444 Gathering and Boosting Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0
Transmission and Storage Compressor Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0

Pneumatic Controllers

- Natural Gas Transmission and Storage Stations 67 67 1,500 1,459 40 40 1 1 33,000 33,096 $470,000 $466,916 $130,000 $131,242
Reciprocating Compressors

Natural Gas Transmission and Storage Stations 1 1 110 111 3 3 0 0 2,500 2,519 $72,000 $71,783 $110,000 $114,146
Centrifugal Compressors

Natural Gas Transmission and Storage Stations 210 210 590 585 16 16 0 0 13,000 13,272 $48,000 $47,670 $5,200 $5,240

Reporting and Recordkeeping All 0 0 0 0 $0 $1,400,000 $1,381,023
TOTAL 40,000 40,276 180,000 176,072 120,000 123,786 400 402 4,000,000 3,993,256 $180,000,000 $162,471,823 $170,000,000 $169,306,553 Formatted: Font: 9 pt

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- 31 Table 3

- 13 Incrementally Affected Units, Emissions Reductions and Costs , Selected Option 2, 2025

Source/Emissions Point Incrementally Affected Units Nationwide Emissions Reductions National Costs (2012$)
Methane

(short tons) Methane (short tons/year) VOC (short tons) VOC

(short tons/year) HAP (short tons) HAP

(short tons/year) Methane (metric tons CO 2 Eq.) Methane (metric tons CO 2 Eq.) Capital Costs Ann. Costs With Addl. Revenues Well Completions Hydraulically Fractured Development Oil Wells 14,000 13,801 130,000 127,434 110,000 106,713 13 13 2,900,000 2,890,153 $140,000,000 $144,263,380 $120,000,000 $119,440,151

Hydraulically Fractured Wildcat and Delineation Oil Wells 1,200 1,166 11,000 10,766 9,000 9,016 1 1 240,000 244,171 $4,300,000 $4,341,018 $4,300,000 $4,341,018

Fugitive Emissions
Well Pads 140,000 139,108 170,000 171,401 48,000 47,645 1,800 1,800 3,900,000 3,887,303 $110,000,000 $43,123,480 $270,000,000 $258,503,520 Gathering and Boosting Stations 1,600 1,554 33,000 32,765 9,100 9,108 340 344 740,000 743,087 $25,000,000 $8,713,278 $17,000,000 $14,204,388

Transmission Compressor Stations 130 126 10,000 10,225 280 283 8 8 230,000 231,909 $2,100,000 $706,482 $2,600,000 $2,394,053
Pneumatic Pumps
Well Pads 18,000 17,772 32,000 32,439 9,000 9,018 340 341 740,000 735,707 $36,000,000 $35,544,000 $5,100,000 $5,060,666 Gathering and Boosting Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0
Transmission and Storage Compressor Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0

Pneumatic Controllers

- Natural Gas Transmission and Storage Stations 400 402 8,800 8,756 240 243 7 7 200,000 198,578 $2,800,000 $2,801,495 $790,000 $787,449

Reciprocating Compressors
Natural Gas Transmission and Storage Stations 6 6 670 666 18 18 1 1 15,000 15,112 $430,000 $430,697 $680,000 $684,874

Centrifugal Compressors
Natural Gas Transmission and Storage Stations 1,300 1,260 3,500 3,511 97 97 3 3 80,000 79,630 $290,000 $286,020 $31,000 $31,437

Reporting and Recordkeeping All 0 0 0 0 $0 $4,100,000 $4,112,522
TOTAL 180,000 175,195 400,000 397,963 180,000 182,141 2,500 2,517 9,000,000 9,025,650 $330,000,000 $240,209,850 $420,000,000 $409,560,079 Formatted: Font: 9 pt

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- 33 Table 3

- 14 Incrementally Affected Units, Emissions Reductions and Costs , Option 3, 2020

Source/Emissions Point Incrementally Affected

Units Nationwide Emissions Reductions National Costs (2012$)
Methane

(short tons) Methane (short tons/year) VOC (short tons) VOC

(short tons/year) HAP (short tons) HAP

(short tons/year) Methane (metric tons CO 2 Eq.) Methane (metric tons CO 2 Eq.) Capital Costs Ann. Costs With Addl. Revenues Well Completions Hydraulically Fractured Development Oil Wells 14,000 13,806 130,000 127,477 110,000 106,749 13 13 2,900,000 2,891,131 $140,000,000 $144,307,684 $120,000,000 $119,477,262
Hydraulically Fractured Wildcat and Delineation Oil Wells 870 870 8,000 8,033 6,700 6,727 1 1 180,000 182,186 $3,200,000 $3,239,010 $3,200,000 $3,239,010

Fugitive Emissions

Well Pads 22,000 22,080 34,000 34,447 9,600 9,575 360 362 780,000 781,248 $18,000,000 $6,844,800 $81,000,000 $79,030,252 Gathering and Boosting Stations 260 259 7,300 7,281 2,000 2,024 76 76 170,000 165,130 $4,200,000 $1,452,213 $5,400,000 $4,916,695

Transmission Compressor Stations 21 21 2,300 2,272 63 63 2 2 52,000 51,535 $340,000 $117,747 $780,000 $744,306
Pneumatic Pumps

Well Pads 3,000 2,962 5,400 5,407 1,500 1,503 57 57 120,000 122,618 $5,900,000 $5,924,000 $840,000 $843,444 Gathering and Boosting Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0
Transmission and Storage Compressor Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0

Pneumatic Controllers

- Natural Gas Transmission and Storage Stations 67 67 1,500 1,459 40 40 1 1 33,000 33,096 $470,000 $466,916 $130,000 $131,242
Reciprocating Compressors

Natural Gas Transmission and Storage Stations 1 1 110 111 3 3 0 0 2,500 2,519 $72,000 $71,783 $110,000 $114,146
Centrifugal Compressors

Natural Gas Transmission and Storage Stations 210 210 590 585 16 16 0 0 13,000 13,272 $48,000 $47,670 $5,200 $5,234

Reporting and Recordkeeping All 0 0 0 0 $0 $1,400,000 $1,381,023
TOTAL 40,000 40,276 190,000 187,073 130,000 126,701 510 512 4,200,000 4,242,735 $180,000,000 $162,471,823 $210,000,000 $209,882,613 Formatted: Font: 9 pt

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- 35 Table 3

- 15 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025

Source Incrementally Affected Units Nationwide Emissions Reductions National Costs (2012$)
Methane

(short tons) Methane (short tons/year) VOC (short tons) VOC

(short tons/year) HAP (short tons) HAP

(short tons/year) Methane (metric tons CO 2 Eq.) Methane (metric tons CO 2 Eq.) Capital Costs Ann. Costs With Addl. Revenues Well Completions Hydraulically Fractured Development Oil Wells 14,000 13,801 130,000 127,43 4 110,000 106,71 3 13 13 2,900,000 2,890,153 $140,000,000 $144,263,38 0 $120,000,000 $119,440,15 1 Hydraulically Fractured Wildcat and Delineation Oil Wells 1,200 1,166 11,000 10,766 9,000 9,016 1 1 240,000 244,171 $4,300,000 $4,341,018 $4,300,000 $4,341,018

Fugitive Emissions
Well Pads 140,000 139,10 8 230,000 228,53 4 64,000 63,527 2,400 2,40 0 5,200,000 5,183,070 $110,000,000 $43,123,480 $510,000,000 $495,236,52 7 Gathering and Boosting Stations 1,600 1,554 44,000 43,686 12,000 12,144 460 459 990,000 990,783 $25,000,000 $8,713,278 $32,000,000 $29,500,173

Transmission Compressor Stations 130 126 14,000 13,634 380 378 11 11 310,000 309,212 $2,100,000 $706,482 $4,700,000 $4,465,835
Pneumatic Pumps
Well Pads 18,000 17,772 32,000 32,439 9,000 9,018 340 341 740,000 735,707 $36,000,000 $35,544,000 $5,100,000 $5,060,666
Gathering and Boosting Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0
Transmission and Storage Compressor Stations 0 0 0 0 0 0 0 0 0 0 $0 $0 $0 $0

Pneumatic Controllers

- Natural Gas Transmission and Storage Stations 400 402 8,800 8,756 240 243 7 7 200,000 198,578 $2,800,000 $2,801,495 $790,000 $787,449

Reciprocating Compressors
Natural Gas Transmission and Storage Stations 6 6 670 666 18 18 1 1 15,000 15,112 $430,000 $430,697 $680,000 $684,874

Centrifugal Compressors
Natural Gas Transmission and Storage Stations 1,300 1,260 3,500 3,511 97 97 3 3 80,000 79,630 $290,000 $286,020 $31,000 $31,403

Reporting and Recordkeeping All 0 0 0 0 $0 $4,100,000 $4,112,522 Formatted: Font: 9 pt

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- 36 TOTAL 180,000 175,19 5 470,000 469,42 7 200,000 201,15 3 3,200 3,23 5 11,000,000 10,646,41 6 $330,000,000 $240,209,85 0 $680,000,000 $663,660,61 8 Formatted: Font: 9 pt

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- 1 4 BENEFITS OF EMISSION S REDUCTIONS

4.1 Introduction

The proposed NSPS a mendments are expected to prevent new emissions from the oil and
gas sector

. For the proposed NSPS, the re will be climate 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 standards simultaneously reduce methane

, VOC, and HAP emissions. The proposed NSPS is anticipated to prevent 180,000 tons of
methane, 1 2 3 0,000 tons of VOC, and 40 0 tons of HAP from new sources in 2020

. In 2025, the

NSPS would prevent 40 0,000 tons of methane, 180,000 tons of VOC, and 2,5 00 tons of HAP

. . The CO 2 

### - equivalent (CO 2 

### Eq.) methane emission reductions are estimated to be 4.0 million

metric tons in 2020 and 9.0 million m etric tons in 2025

. As described in the su bsequent sections, 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

- related climate effects are estimated to be $210 million and $550 million using a 3 percent discount rate in 2020 and 2025, respectively

. The specific control techniques for the proposed NSPS are anticipated to

have minor emi ssions disbenefits (e.g., increase s in emissions 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 and 2025, respectively

.

While we expect that the avoided VOC emissions will also result in improvements in air quality and reduce health and welfare effects associated with exposure to ozone, fine particulate
matter (PM 2.5 

### ), and HAP, we have determin ed 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 of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for t his industrial sector with the data currently available. With the data available, we are not able to provide a credible health benefits estimates for th ese is rule, due to the differences in the locations of oil and natural gas emission points relative to

e xisting information and the highly localized nature of air quality responses associated with HAP

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- 2 and VOC reductions. 14 

### In this chapter, we provide a qualitative assessment of the health benefits associated with reducing exposure to these pollutants, as well as visibility impairment and ecosystem benefits. Table 4

- 1 summarizes the quantified and unquantified benefits in this analysis.

Table 4

- 1 Climate and Human Health Effects of Emission Reductions from this Pr oposal

Category Specific Effect Effect Has Been Quantified Effect Has Been Monetized More Information
Improved Environment

Reduced climate effects Global climate impacts from metha ne and carbon dioxide (CO 2 ) — 1  Marten et al. (201 5 ), 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 ISA 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 ISA 3 Lost work days (age 18

- 65)

— — PM ISA 3
Minor restricted

- activity days (age 18

- 65)

— — PM ISA 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

14 Previous studies have estimated the monetized benefits

- per

- ton of reducing VOC emissions associated with the effect that those emissions have on ambient PM 2.5 levels and the health effe cts associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009). 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 consistent with emissions modele d in Fann, Fulcher, and Hubbell (2009). In addition, the benefit

- per

- ton estimates for VOC emission reductions in that study are derived from total VOC emissions across all sectors. Coupled with the larger uncertainties about the relationship between VOC e missions and PM 2.5 and the highly localized nature of air quality responses associated with VOC reductions, these factors lead us to conclude that the available VOC benefit

- per

- ton estimates are not appropriate to calculate monetized benefits of these rule s, even as a bounding exercise.

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- 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)

— — Ozone 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 ISA 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

— — Ozone 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 estimated within each integrated assessment model as part of the calculation of the SC

- CO 2 and SC

- CH 4
. The resulting monetized damages, which are relevant for conducting the benefit

- cost analysis, are used in this RIA to estimate the welfare effects 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 limit ations for this analysis, but we have quantified them in other analyses.
4 We assess these benefits qualitatively because current evidence is only suggestive of causality or there are other significan t concerns over the strength of the association.

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- 4 4.2 Emissio n Reductions from the Proposed NSPS

As described in Section 2 of this RIA, oil and natural gas operations in the U.S. include a variety of emission points for methane, VOC

, and HAP

, 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 processing p lants are largely concentrated in the South Central, Midwest, and Southern California regions of the U.S., whereas gas compression stations are located all over the country. Distribution lines to customers are frequently located within areas of high popula tion density.

In implementing this rule, emission controls may lead to reductions in ambient PM 2.5 

### and

ozone below the National Ambient Air Quality Standards (NAAQS) in some areas and assist other areas with attaining the NAAQS. Due to the high degree of variability in the responsiveness of ozone and PM 2.5 

### formation to VOC emission reductions, we are unable to

determine how this rule might affect attainment st atus without air quality modeling data. 15 

### Because the NAAQS RIAs also calculate ozone and PM benefits, t here are important differences worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate the potential costs and benefi ts of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a

N AAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs and benefits of other regulations that result in specific costs of control and emi ssion reductions. However,

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

By contrast, the emission reductions for implementation rules are generally from a specif ic class of well

- characterized sources. In general, EPA is more confident in the magnitude and location of the emission reductions for implementation rules rather than illustrative NAAQS

15 The responsiveness of ozone and PM 2.5 formation is discussed in greater detail in sections 4.4.1 and 4.5.1 of this

RIA.

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- 5 analyses. Emission reductions achieved under these and other promulga ted rules will ultimately be reflected in the baseline of future NAAQS analyses, which would reduce the incremental costs and benefits associated with attaining the NAAQS. EPA remains forward looking towards

the next iteration of the 5

- year review cycle fo r the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline for NAAQS implementation. For more information on the relationship between the NAAQS and rules such as analyzed here, please see Section 1. 3

. 4 of the PM NAAQS RIA (U.S. EPA, 2012c ).

Table 4

- 2 shows the direct emission reductions anticipated for th i s rule , across the regulatory options examined in the rule

. It is important to note that these benefits accrue at different spatial scales. HAP emission reductions reduce exposure to carcinogens and other toxic pollutants primarily near the emission source. Reducing VOC emis sions would reduce precursors to secondary formation of PM 2.5 

### and ozone, which reduces exposure to these pollutants on a regional scale. Climate effects associated with long

- lived greenhouse gases like methane generally do not depend on the location of the emission of the gas, and have global impacts

. M ethane is also a precursor to global background concentrations of ozone.

Table 4

- 2 Direct Emission Reductions from the Proposed NSPS in 20 20 and 2025

Pollutant Option 1 Option 2 Option 3
2020 Methane (short tons/year) 170,000 180,000 190,000 VOC (short tons/year) 120,000 120,000 130,000 HAP (short tons/year) 290 400 510 Methane (metric tons) 150,000 160,000 170,000 Methane (metric tons CO 2 Eq

. ) 3,700,000 4,000,000 4,200,000
2025 Methane (short tons/year) 330,000 400,000 470,000 VOC (short tons/year) 160,000 180,000 200,000 HAP (short tons/year) 1,800 2,500 3,200 Methane (metric tons) 300,000 360,000 430,000 Methane (metric tons CO 2 Eq

. ) 7,400,000 9,000,000 11,000,000

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- 6 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 absorbs terrestrial infrared radiation that contributes to increased global warming and continuing climate change. Methane reacts in the atmosphere to form ozone and ozone als o impacts global temperatures. Methane, in addition to other GHG emissions, contributes to warming of the atmosphere

, which over time leads to increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of global glacier s and ice, increasingly severe weather events, such as hurricanes of greater intensity, and sea level rise, among other impacts.

According to the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report (AR5, 201 3 ), c hanges in methane conc entrations since 1750 contribute d 0.48 W/m 2 

### of forcing, which is about 1 7 percent of all global forcing due to increases in anthropogenic GHG concentrations, and which makes methane the second leading long

- lived climate forcer after

CO 2 

### . However, after acc ounting for changes in other greenhouse substances such as ozone and stratospheric water vapor due to chemical reactions of methane in the atmosphere , historical

methane emissions were estimated to have contributed to 0. 97 W/m 2 

### of forcing today , which is

a bout 30 percent of the contemporaneous forcing due to historical greenhouse gas emissions.

Processes in the oil and gas category emit significant amounts of methane. The Inventory

of U.S. Greenhouse Ga s Emissions and Sinks: 1990

- 2013 (published Apr il 2015) estimates 2013 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries and petroleu m transportation) to be 18 2 MMt CO 2 

### Eq

. In 2013, total methane emissions from the oil and gas industry represented nearly 29 perce nt 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, 20 15 c ).

It is important to note that the 2013 GHG emissions estimates do not include methane

emissions from hydraulically fractured and re

- fractured oil well completions due to lack of available data when the 2013 GHG Inventory estimate was developed. The e stimate in this

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- 7 proposed rule includes an adjustment for hydraulically fractured oil wells, and such an adjustment is also being considered as a planned improvement in the 2014 Inventory (to be published April 2016). This adjustment would increase 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 hydraulically 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 sector in the United States. The proposed NSPS is expected to reduce methane emissions by about 18 0 ,000 short tons or approximately 160 ,000

metric tons methane (or 4.0 MMt CO 2 

### Eq.) in 2020. In 2025, the proposed NSPS is expected to reduce methane emissions by about 40 0 ,000 short tons or approximately 36 0,000 metric tons

methane (or 9. 0 MMt CO 2 

### Eq .). These reductions in 2 020 and 2025 rep resent about 2 percent

and 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 (18 2 MMt CO 2 

### Eq.).

We calculated the global social benefits of methane emission s reductions expected from the proposed NSPS using estimates of the social cost of methane (SC

- CH 4 

### ), a metric that estimates the monetary value of impacts associated with marginal changes in metha ne emissions in a given year. It includes a wide range of anticipated climate impacts, such as net changes in agricultural productivity and human health, property damage from increased flood risk, and changes in energy system costs, such as reduced costs f or heating and increased costs for air conditioning. The SC

- CH 4 

### estimates applied in this analysis were developed by Marten et al.
(201 4 ) and are discussed in greater detail below.

A similar metric, the social cost of CO 2 

### (SC

- CO 2 

### ), provides important cont ext for understanding the Marten et al. SC

- CH 4 

### estimates. Estimates of the SC

- CO 2 

### have been used by EPA and other federal agencies to value the impacts of CO 2 

### emissions changes in benefit cost analysis for GHG

- related rulemakings since 2008. The 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 

### , i t includes a wide range of anticipated climate impacts, such as net

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- 8 changes in agricultural productivity, p roperty damage from increased flood risk, and changes in energy system costs, such as reduced costs for heating and incre ased costs for air conditioning

. It is used to quantify the benefits of reducing CO 2 

### emissions, or the disbenefit from increasing

emiss ions, in regulatory impact analyses.

The SC

- CO 2 

### estimates were developed over many years, using the best science available, and with input from the public. Specifically, an interagency working group (IWG) that included EPA and other executive branch agenci es and offices used three integrated assessment models (IAMs) to develop the SC

- CO 2 

### estimates and recommended four global values for use in regulatory analyses. The SC

- CO 2 

### estimates were first released in February 2010 and updated in 2013 using new version s of each IAM. The 2013 update did not revisit the 2010 modeling decisions with regards to the discount rate, reference case socioeconomic and emission scenarios, and equilibrium climate sensitivity distribution. Rather, improvements in the way damages are modeled are confined to those that have been incorporated into the latest versions of the models by the developers themselves and published in the peer

- reviewed literature. The 2010 SC

- CO 2 

### Technical Support Document (2010 SC

- CO 2 

### TSD) provides a complete d iscussion of the methods used to develop these estimates and the current SC

- CO 2 

### TSD presents and discusses the 2013 update (including recent minor technical corrections to the estimates). 16



### The 2010 SC

- CO 2 

### TSD noted a number of limitations to the SC

- CO 2 

### ana lysis, including the incomplete way in which the IAMs capture catastrophic and non

- catastrophic impacts, their incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of damages to high temperatures, and assumptions re garding risk aversion. Currently IAMs do not assign value to all of the important physical, ecological, 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 bec ause the science incorporated into these 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

16 Both the 2010 SC

- CO 2 TSD and the current SC

- CO 2 TSD are available at:

https://www.whitehouse.gov/om b/inforeg_regpol_agency_review

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- 9 benefit

- cost analysis. The new versions of the models offer some improvements in these areas, although further work is warranted.

Accordingly, EPA and other agencies continue to engage in research on modeling and

valuation of climate impacts with the goal to improve 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 Agency rulemakings that use the SC

- CO 2 

### in

su pporting analyses and through regular interactions with stakeholders and research analysts implementing the SC

- CO 2 

### methodology used by the IWG

. In addition, OMB’s Office of Information and Regulatory Affairs sought public comment on the approach used to de velop the

SC

- CO 2 

### estimates through a separate comment period that ended on February 26, 2014.

After careful evaluation of the full range of comments, the IWG continues to recommend

the use of the SC

- CO 2 

### estimates in regulatory impact analysis. With the r elease of the response
to comments, the IWG announced plans to obtain expert 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 change. The NRC review will be informed by the public comments received and focus on the technical merits and challenges of potential approaches to improving the SC

- CO 2 

### estimates in future updates.

Concurrent with OMB’s publication of the response to comm ents on SC

- CO 2 

### and announcement of the NRC process, OMB posted a revised TSD that includes two minor

technical correcti ons to the current estimates. One technical correction addressed an inadvertent omission of climate change damages in the last year of an alysis (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 associate d with the 95th perc entile 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 error.

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- 10 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). 17 

### 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 ra tes 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 to use in an intergenerational context (where costs and benefits are incurred by diff erent 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 

### distribu tion. The SC

- CO 2 

### increases over time because future emissions are expected to produce larger incremental damages as economies grow and physical and economic systems become more stressed in response to greater climate change.

A challenge particularly relev ant 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 from a perturbation of a non

- CO 2 

### GHG relative to a perturbation of CO 2 

### over a fixed time horizon , often 100 years

. The GWP

mai nly reflects differences in the radiative efficiency of gases and differences in their atmospheric lifetimes. While t he GWP is a simple, transparent, and well

- established metric for assessing the relative impacts of non

- CO 2 

### emissions compared to CO 2 

### on a p urely physical basis

, there are several well

- documented limitations in using it to value non

- CO 2 

### GHG benefits, as
discussed in the 2010 SC

- C O 2 

### TSD and previous rulemak ings (e.g., U

. S

. EPA 2012b, 2012d ). 18 

### In particular, several recent studies found that GWP

- 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 designed to measure the impact of

17 The current version of the SC

- C O 2 TSD is available at: <link to be added when available> . The TSDs present SC

- CO 2 in $2007. The estimates were adjusted to 2012$ using the GDP Implicit Price Deflator. Also available
at: http://www.gpo.gov/fdsys/pkg/ECONI

- 2013

- 02/pdf/ECONI

- 2013

- 02

- Pg3.pdf

. The SC

- C O 2 values have been rounded to two significant digits. Unrounded numbers from the 2013 SCC TSD w ere adjusted to 2012$ and used to calculate the CO 2 benefits.

18 See also Reilly and Richards

, 1993; Schmalensee

, 1993; Fankhauser

, 1994; Marten and Newbold

, 2012

.

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- 11 non

- CO 2 

### GHG emissions rel ative to CO 2 

### at a specific point along the pathway from emissions to monetized damages (depicted in Figure 4

- 1 ), and this point may differ across measures.

Source: Marten et al. 201 5


### Figure 4

- 1 Path from GHG Emissions to Monetized Damages

The GWP is not ideally suited for use in benefit

- cost analyses to approximate the social

cost of non

- CO 2 

### GHGs because it ignore s important nonlinear relationships beyond radiative forcing in the chain between emissions a nd damages. These can become relevant because gases

have different lifetimes and the SC

- C O 2 

### takes into account the fact that marginal damages from an increase in temperature are a function of existing temperature levels. Another limitation of gas compariso n metrics for this purpose is that some environmental 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, the economic impacts ass ociated with increased agricultural productivity due to higher atmospheric CO 2 

### concentrations included in the SC

- C O 2


### woul d be incorrectly allocated to methane emissions with the GWP

- based valuation approach.

Also of concern is the fact that the assumptions made in estimating the GWP are not consistent with the assumptions underlying SC

- C O 2 

### e stimates in general, and the SC

- C O 2


### estimates developed by the IWG more specifically. For example

, the 100

- year time horizon usually used in estimating the GWP is less t han the approximately 300

- year horizon the IWG used in developing the SC

- C O 2 

### estimates. The GWP approach also treats all impacts within the time horizon equally, independent of the time at which they occur. This is inconsistent with the role of discounting in economic analysis, which accounts for a basic preference for earlier over later gains in utility and expectations regarding future levels of economic growth. In the case of

methane , which has a relatively short lifetime compared to CO 2 

### , the temporal in dependence of

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- 1 2 the GWP could lead the GWP approach to underestimate the SC

- CH 4 

### with a larger downward bias under higher discount rates (Marten and Newbold

, 2012 ). 19



### EPA sought public comments on the valuation of non

- CO 2 

### GHG impacts in previous rulemakings. In general, the commenters strongly encouraged EPA to incorporate the monetized

value of non

- CO 2 

### GHG impacts into the benefit cost analysis, however they noted the challenges

associated with the GWP

- approach, as discussed above, and encouraged the use of d irectly

modeled estimates of the SC

- CH 4 

### to overcome those challenges.

EPA had cited several researchers that had directly estimated the social cost of non

- CO 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. EPA found considerable variation among these published estimates in terms of the models and input assu mptions they employ
( U.S. EPA

, 2012 d ). 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 hav e been developed over the last 20 years. Furthermore, at the time, none of the other published 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 likely underestimates due to changes in the underlying science since their publication.

Therefore, EPA concluded that the GWP approach would serve as an interim method of analysis until directly modeled social cost estimates for non

- CO 2 

### GHGs, consistent with the SC

CO 2 

### estimates developed by th e IWG, were developed. EPA presented GWP

- weighted estimates in sensitivity analyses rather than the main benefit

- cost analyses. 20

19 We note that the truncation of the time period in the GWP calculation could lead to an overestimate of SC

- CH 4

for near term perturbation years when the SC

- CO 2 is based on a sufficiently low or steeply declining discount
rate

. 20 For example, the 2012 New Source Performance Standards and Amendments to the National Emissions Standards for Hazar dous Air Pollutants for the Oil and Natural Gas Indust ry are expected to reduce methane 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 Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards, promulgated jointly with the National Highway Traffic Safety Administration, is expected to reduce methane emissions by over 100,000 metric tons in 2025 increasing to nearly 500,000 metri c tons in 2050, see http://www.gpo.gov/fdsys/pkg/FR

- 2012

- 10

- 15/pdf/2012

- 21972.pdf

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- 13 Since then, a paper by Marten et al. (201 4 ) 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. 21 

### Specifically, the estimation approach of Marten et al. used
the same set of three IAMs, five socioeconomic and emissions scenario s, equilibrium climate sensitivity distribution, three constant discount rates, and aggregation approach used by the IWG to develop the SC

- CO 2 

### estimates. The aggregation method involved distilling the 45 distribution

of the SC

- CH 4 

### produced for each emissio ns year into four estimates: 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 scenarios using a 3 percent discount rate. The atmospheri c lifetime and radiative efficacy of methane used by Marten et al. is based on the estimates reported by the IPCC in their Fourth Assessment Report (AR4, 2007), including an adjustment in the radiative efficacy of methane to account for its role as a precu rsor for tropospheric ozone and stratospheric water. These values represent the same ones used by the IPCC in AR4 for calculating GWPs. At the time Marten et al. developed their estimates of the

SC

- CH 4 

### , AR4 was the latest assessment report by the IPCC. The IPCC update s GWP estimates
with each new assessment, and in the most recent assessment , 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 radiative efficiency estimates for CO 2 

### , changes in the lifetime estimate for methane, and changes in the correction factor applied to methane’s GWP to reflect the effect of methane emissions on other climatically important substances such as tropospher ic ozone and stratospheric water vapor. In add i tion, the range presented in the latest IPCC report reflects different choices regarding whether to account for how biogenic and fossil methane have different carbon cycle effects, and for whether to account f or climate feedbacks on the carbon cycle for both methane and CO 2 

### (rather than just for CO 2 

### as was done in AR4). 22 , 23

21 Marten et al. (2015) also provided the first set of SC

- N 2 0 estimates that are consistent with the assumptions underlying the SC

- CO 2 estimates.

22 Climate Change 2013: The Ph ysical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [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 (ed s.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA.
23 Note that this proposal uses a GWP value for methane of 25 for CO 2 equivalency calculations, consistent with the GHG emissions inventories and the IPCC Fourth Assessment Report (AR4).

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- 14 Marten et al. (201 4 ) discuss these estimates, (SC

- CH 4 

### estimates presented below in Table

4

- 3 ), and compare them with other recent estimates in the literature. 24 

### The authors noted that a direct comparison of their estimates with all of the 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 previous estimates. The higher SC

- CH 4 

### estimates are partially driven by the higher effective radiative forcing due to the inclusion of indirect

effects from methane emissions in their modeling. Marten et al. , similar to other recent studies, also find that their directly modeled SC

- CH 4 

### estimates are higher than the GWP

- weighted

estimates. More detailed discussion of the SC

- CH 4 

### estimation methodology, results and a

co mparison to other published estimates can be found 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. , 201 5 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 defined in real terms, i.e., adjusted for inflation using the GDP implicit price deflator.
b The estimates in this table have been adjusted to reflect the minor technical corrections to the SC

- CO 2 estimates d escribed above. See Corrigendum to Marten et al . (2014), erratum for more details http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550 (citation to be provided when available)

. .

24 Marten et al. (2015) estimates are presented in 2007 dollars. These 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 Economic Analysis ), http://www.bea.gov/iTable/index_nipa.cfm Accessed 3/3/15. Formatted: Font: Italic

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- 15 The application of directly modeled estimates from Marten et al. (201 4 ) 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 benefits of reductions in methan e emissions expected as a result of the proposed rulemaking. 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 estim ate, 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.

EPA recently conducted a peer review of the application of the Marten et al. (201 4 ) non

CO 2 

### social cost estimates in regulatory analysis and received responses that s upported this application. Three reviewers considered seven charge questions that covered issues such as EPA’s interpretation of the Marten et al. estimates, the consistency of the estimates with the SC

CO 2 

### estimates, EPA’s characterization of the limits o f the GWP

- approach to value non

- CO 2 

### GHG impacts, and the appropriateness of using the Marten et al. estimates in regulatory impact analyses. The reviewers agreed with EPA’s interpretation of Marten et al. ’s estimates; generally

found the estimates to be co nsistent with the SC

- CO 2 

### estimates; and concurred with the limitations of the GWP approach, finding directly modeled estimates to be more appropriate. While outside of the scope of the review, the reviewers 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 apply to the resulting SC

CH 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 appropriate, 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. EPA supports continued improvemen t in the SC

- CO 2 

### estimates developed by the U.S. government and agrees that improvements in the SC

- CO 2 

### estimates should also be reflected in the SC

- CH 4


### estimates

. T he fact that the reviewers agree that the SC

- CH 4 

### estimates are generally consistent

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- 16 with the SC

- CO 2 

### estimates that are recommended by OMB’s guidance on valuing CO 2 

### emissions
reductions, leads EPA to conclude that use of the SC

- CH 4 

### estimates is an analytical improvement over excluding methane emissions from the monetized portion of the benefit cost analysis.

In light of the favorable peer review and past comments urging EPA to value non

- CO 2 

### GHG impacts in its rulemakings, the Agency has used the Marten et al. (201 4 ) SC

- CH 4 

### estimates to value methane impacts expected from this proposed rulemaking and has included those benefits in the main benefits analysis. EPA 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.

The methane benefits are presented below in Table 4

- 4 for years 2020 and 2025 across regulatory options . Applying this approach to the methane reductions estimated for the proposed

NSPS option , t he 2020 methane benefits vary by discount rate and range from about $ 9 3 million to approximately $ 5 5 0 million; the mean SC

- CH 4 

### at the 3 percent discount rate results in an
estimate of about $ 2 1 0 million in 2020. The methane benefits increase for the propos ed option in 2025 and likewise vary by discount rate, ranging from about $ 2 5 0 million to approximately $1. 4 billion in that year; the mean SC

- CH 4 

### at the 3

- percent discount rate results in an estimate of
about $ 5 5 0 million in 2025.

Table 4

- 4 Estimated Global Benefits of Methane Reductions* (in millions, 2012$)

Discount rate and statistic Option 1 Option 2 (proposed) Option 3

2020 2025 2020 2025 2020 2025
Million metric tonnes of methane reduced 0.15 0.30 0.16 0.36 0.17 0.43

Million metric tonnes of CO 2 Eq. 3. 7 7. 4 4.0 9. 0 4. 2 11

5% (average) $ 87 $210 $ 93 $ 250 $ 99 $ 300 3% (average) $ 190 $450 $210 $550 $220 $ 640 2.5% (average) $260 $580 $280 $ 700 $ 29 0 $830 3% (95 th percentile) $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

- related benefits are associated with methane
reductions, but some climate

- related impacts are expected from the proposal’s secondary air impacts. The secondary impacts are discussed in Section 4.7.

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- 17 Methane is also a precursor to ozone. In remote areas, methane is a dominant precursor to tropospheric ozone formation (U.S. EPA, 20 13 ). Approximately 40 percent of the global annual mean ozone increase since preindustrial times is believed to be due to anthropogenic methane (HTAP, 2010). Projections of future emissions also indicate that methane is likely to be a key

con tributor to ozone concentrations in the future (HTAP, 2010). Unlike NO X 

### and VOCs , which affect ozone concentrations regionally and at hourly time scales, methane emissions affect ozone concentrations globally and on decadal time scales given methane’s rela tively 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 health
effects (West et al. , 2006, Anenberg et al. , 2009)

. These benefits are global and occur in both urban and rural areas. Reductions in background ozone concentrations can also have benefits for agriculture and ecosystems (UNEP/WMO, 2011). Studies show that controlling methane emissions can reduce global ozone concentrations and climate change simultaneously, but controlling other shorter

- lived ozone precursors such as NO X 

### , carbon monoxide, or non

- methane VOCs have larger local health benefits from greater reductions in local ozone concentrations
(West and Fior e, 2005; West et al. , 2006; Fiore et al. , 2008; Dentener et al. , 2005; Shindell et al.

, 2005, 2012; UNEP/WMO, 2011). The health, welfare, and climate effects associated with ozone are described in the preceding sections. Without detailed air quality modeli ng, 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

- reviewed scientific literature that presented a range of estimates of the monetized ozone

- related mortality benefits of reducing methane emissions (Sarofim et al. 2015). For example, under their base case assumptions using a 3% discount rate, Sarofim et al. find global ozone

- related mortality benefits of methane 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 underlying the SC

- CO2 and SC

- CH4 es timates discussed above, and required a number of additional assumptions such as baseline mortality rates and mortality response to ozone concentrations. The Sarofim et al. (2015) study may have implications for this benefits analysis as it provides a pot ential approach to estimating the ozone related mortality benefits resulting from the methane reductions expected from this proposed

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- 18 rulemaking. The EPA requests comment on Sarofim et al.’s approach to estimating the ozone related mortality benefits of met hane emissions reductions, including technical considerations in applying their methodology to this regulatory impact analysis.

4.4 VOC as a PM 2.5 

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

### Most

VOC emitted are oxidized to CO 2 

### rather than to PM, but a portion of VOC emission contributes

to ambient PM 2.5 

### levels as organic carbon aerosols (U.S. EPA, 2009a). Therefore, reducing these

emissions would reduce PM 2.5 

### formation, human exposure to PM 2.5 

### , and t he incidence of PM 2.5 

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

### - related benefits in this analysis. Analysis of organic carbon measurements suggest only a fraction of secondarily formed organic carbon aerosols are of anthropogenic or igin. The current state of the science of secondary organic carbon aerosol formation indicates that anthropogenic VOC contribution to secondary organic carbon aerosol is often lower than the biogenic (natural) contribution. Given that a

fraction of seconda rily formed organic carbon aerosols is from anthropogenic VOC emissions and the extremely small amount of VOC emissions from this sector relative to the entire VOC inventory it is unlikely this sector has a large contribution to ambient secondary organic c arbon

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



### .

Due to data limitations regarding potential locations of new and modified sources affected by this rulemaking , we were did not perform air quality modeling for this rule needed to quantify the PM 2.5 

### benefits associated with reducing VOC emissions

. Due to the high degree of variability in the responsiveness of PM 2.5 

### formation to VOC emission reductions, we are unable

t o 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 avoiding mortality and respiratory morbidity.

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- 19 Researchers have associated PM 2.5 

### - exposure with adverse health effects in numerous toxicological, clinical and epidemiological studies (U.S. EPA, 2009a). When adequate data and resources are available, EPA generally quantifies several health effects associated with e xposure
to PM 2.5 

### (e.g., U.S. EPA ( 2011 g )). These health effects include premature mortality for adults

and infants ; cardiovascular morbidity

, such as heart attacks ; respiratory morbidity

, such as

asthma attacks and acute and chronic bronchitis ; which resul t in hospital and ER visits

, lost work days, restricted activity days, and respiratory symptoms. Although EPA has not quantified these effects in previous benefits analyses, the scientific literature suggests that exposure to PM 2.5 

### is

also associated with adverse effects on birth weight, pre

- term births, pulmonary function, other cardiovascular effects, and other respiratory effects (U.S. EPA, 2009a).

When EPA quantifies PM 2.5 

### - related benefits, the Agency assumes that all fine particles, regardless of thei r chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type (U.S. EPA, 2009a). Based on our review of the current body of scie ntific literature,

EPA estimates PM

- related premature mortality without applying an assumed concentration

threshold. This decision is supported by the data, which are quite consistent in showing effects

down to the lowest measured levels of PM 2.5 

### in the un derlying epidemiology studies.

Previous studies have estimated the monetized benefits

- per

- ton of reducing VOC

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

### levels and the

health effects associated with PM 2.5 

### exposure (Fan n, Fulcher, and Hubbell, 2009) , and these estimates can provide useful context for this rulemaking

. Using the estimates in Fann, Fulcher,
and Hubbell (2009), the monetized benefit

- per

- ton of reducing VOC emissions in nine urban areas of the U.S. ranges fro m $560 in Seattle, WA to $5,700 in San Joaquin, CA, with a national average of $2,400. These estimates assume a 50 percent reduction in VOC , the Laden et al. (2006) mortality function (based on the Harvard Six Cities study , a large cohort epidemiology study in the Eastern U.S., an analysis year of 2015, a 3 percent discount rate , and 2006$ )

. A dditional benefit

- per

- ton estimates are available from this dataset u sing alternate assumptions regarding the relationship between PM 2.5 

### exposure and premature mor tality from empirical studies and supplied by experts ( e.g., Pope et al. , 2002; Laden et al. , 2006; Roman et al. , 2008)

.

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- 20 EPA generally presents a range of benefits estimates 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 EPA provides the benefit estimates derived from expert opinions in Roman et
al. (2 008) as a characterization of uncertainty. As shown in Table 4

- 5 , t he range of VOC benefits that reflects the range of epidemiology studies and the range of the urban areas is $ 3 0 0 to $7, 500 per ton of VOC reduced (2012$)

. 25 

### Since these estimates were prese nted 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 studies and pop ulation data. 26 

### Because these updates would not lead to significant changes in the benefit

- per

- ton estimates for VOC, we have not updated them here.

While these ranges of benefit

- per

- ton estimates provide useful context, the geographic

distribution of VOC e missions from the oil and gas sector are not consistent with emissions
modeled in Fann, Fulcher, and Hubbell (2009). In addition, the benefit

- per

- ton estimates for VOC emission reductions in that study are derived from total VOC emissions across all sector s. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 

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

25 We also converted the estimates from Fann, Fulcher, and Hubbell (2009) to 2012$ and applied EPA’s current value of a statistical life (VSL) estimate. For more 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 r isk reductions.

26 For more information regarding these updates, please see Section 5.3 of the RIA for the final PM NAAQS (U.S. EPA, 2012c).

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- 21 Table 4

- 5 Monetized Benefits

- per - Ton Estimates for VOC based on Previous Modeling in 2015 ( 20 12 $)

Area Pope et al. (2002) Laden et al. (2006) Expert A Expert B Expert C Expert D Expert E Expert F Expert G Expert H Expert I Expert J Expert K Expert L

Atlanta $660 $1,600 $1,700 $1,300 $1,300 $920 $2,100 $1,200 $780 $980 $1,300 $1,000 $260 $1,000
Chicago $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 $2,500

Dallas $320 $790 $830 $650 $630 $450 $1,000 $580 $380 $480 $630 $510 $130 $490

Denver $770 $1,900 $2,000 $1,500 $1,500 $1,100 $2,400 $1,400 $910 $1,100 $1,500 $1,200 $300 $910
NYC/ 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 $3,300

Phoenix $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 $1,600

Salt 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 $2,100
San 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 $4,600

Seattle $300 $730 $770 $570 $590 $420 $950 $540 $350 $440 $580 $470 $120 $350
National 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 assume d a 50 percent reduction in VOC emissions, an analysis year of 2015, and a 3 percent discount rate. All estimates are rounded to two

significant digits. These estimates have been adjusted from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currency year and EPA’s current VSL estimate. However, these estimates have not been updated to reflect recent epidemiological studies for mortality studies, morbidity studies , or population data

. Using a discount rate of 7 percent , the benefit

- per

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

- per

- ton estimates by approximately 4 percent to 52 percent

. Assuming a 25 percent reduction in VOC emissions would decrease the benefit

- per

- ton estimat es by 5 percent to 52 percent

. EPA generally presents a range of benefits estimates derived from the expert functions from Roman et al. (2008) as a characterization of uncertainty.

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- 22 4.4.2 Organic PM welfare effects

According to the previous residual risk assessment for this sector (U.S. EPA, 201 2a ), persistent and bioaccumulative HAP reported as emissions from oil and gas operations include polycyclic organic matter (POM). POM defines a broad class of compounds that includes polycyclic aromat ic hydrocarbon compounds (PAHs). Several significant ecological effects are associated with deposition of organic particles, including 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 environmental conditions (U.S. EPA, 2009a). PAHs can accumulate to high enough concentrations in some coastal environments to pose an environmental health threat that includes cancer in fish populations, toxicity to organisms living

in the sediment and ris ks to those (e.g., migratory birds) that consume these organisms. Atmospheric deposition of particles is thought to be the major source of PAHs to the sediments

of coastal areas of the U.S. Deposition of PM to surfaces in urban settings increases the metal and organic component of storm water runoff. This atmospherically

- associated pollutant burden can then be toxic to aquatic biota. The contribution of atmospherically deposited PAHs to aquatic food webs was demonstrated in high elevation mountain lakes wit h no other anthropogenic contaminant sources.

The recently completed Western Airborne Contaminants Assessment Project (WACAP) is the most comprehensive database on contaminant transport and PM depositional effects on sensitive ecosystems in the Western U.S . (Landers et al. , 2008). In this project, the transport, fate, and ecological impacts of anthropogenic contaminants from atmospheric sources were assessed from 2002 to 2007 in seven ecosystem components (air, snow, water, sediment, lichen,

conifer needles

, and fish) in eight core national parks. The study concluded that bioaccumulation

of semi

- volatile organic compounds occurred throughout park ecosystems, an elevational gradient in PM deposition exists with greater accumulation in higher altitude areas, a nd contaminants accumulate in proximity to individual agriculture and industry sources, which is

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- 23 counter to the original working hypothesis that most of the contaminants would originate from Eastern Europe and Asia

.

4.4.3 Visibility E ffects

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 soil (Sisler, 1996). Suspended particles and gases degrade visibility by scattering and absorbing light. Higher visibility impairment levels in the East are due to generally higher concentrations of fine particles, particularly sulfates, and higher average relative humidity levels. Visibility has dir ect significance to people’s enjoyment of daily activities and their overall sense of wellbeing. Good visibility increases the quality of life where individuals live and work, and where they engage in recreational activities. Previous analyses
(U.S. EPA, 2 006 b ; U.S. EPA, 201 1 a ; U.S. EPA, 2011 g ; U.S. EPA, 2012c ) show that visibility benefits are a significant welfare benefit category. Without air quality modeling, w e are unable to estimate visibility related benefits, nor are we able to determine whether VOC emission reductions would be likely to have a significant impact on visibility in urban areas or Class I

areas.

4.5 VOC as an Ozone Precursor

This rulemaking would reduce emissions of VOC , which are also precursor s to secondary

formation of ozone

. Ozone is no t emitted directly into the air, but is created when its two primary components, volatile organic compounds (VOC) and oxides of nitrogen ( NO X 

### ), react in the presence of sunlight. In urban areas, compounds representing all classes of VOC are important

for o zone formation, but biogenic VOC emitted from vegetation tend to be more important compounds in non

- urban vegetated areas (U.S. EPA, 20 13 ). Therefore, reducing these emissions would reduce ozone formation, human exposure to ozone, and the incidence of ozone

- related

health effects. However, we have not quantified the ozone

- related benefits in this analysis for

several reasons. First, previous rules have shown that the monetized benefits associated with reducing ozone exposure are generally smaller than P M

- related benefits, even when ozone is the pollutant targeted for control (U.S. EPA, 2010 a , 2014 b ). Second, the complex non

- linear chemistry of ozone formation introduces uncertainty to the development and application of a

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- 24 benefit

- per

- ton estimate , particu larly for sectors with substantial new growth

. Third, the impact of reducing VOC emissions is spatially heterogeneous depending on local air chemistry. Urban areas with a hig h population concentration are often VOC

- limited, which means that ozone is

most e ffectively reduced by lowering VOC

. Rural areas 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, ozo ne is relatively insensitive to marginal changes in both NO X 

### and VOC.

Due to data limitations regarding potential locations of new and modified sources affected by this rulemaking, we did not perform air quality modeling for this rule needed to quantify t he ozone benefits associated with reducing 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 modified 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 morbidity (U.S. EPA, 2010a). R esearchers have associated ozone exposure with adverse health effects in numerous toxicological, clinical and epidemiological studies (U.S. EPA, 20 13 ). When adequate data and resources are available, EPA generally quantifies several health effects associated with exposure to ozone (e.g., U.S. EPA

, 2010a ; U.S. EPA, 2011a ). These health effects include respiratory morbidity such as asthma attacks, hospital and emergency department visits, scho ol loss days, as well as premature mortality. T he scientific literature is also suggestive that exposure to ozone is also associated

with chronic respiratory damage and premature aging of the lungs

.

In a recent EPA analysis, EPA estimated that reducing 15 ,000 tons of VOC from

industrial boilers resulted in $3.6 to $15 million (2008$) of monetized benefits from reduced ozone exposure (U.S. EPA, 2011 b ). 27 

### After updating the currency year to 2012$, t his implies a

27 While EPA has estimated the ozone benefits for many scenarios, most of these scenarios also reduce NO X emissions, which make it difficult to isolate the benefits attributable to VOC reductions.

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- 25 benefit

- per

- ton for ozone of $ 2 6 0 to $1, 0 7 0 per ton of VOC reduced. Since EPA conducted the analysis of industrial boilers, EPA published the 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, 2014b). Therefore, the ozone mortality studies applied in the boiler analysis, while current at that time, do not reflect the most updated literature

available. The selection of ozone m ortality studies used to estimate benefits in RIAs was revisited in the RIA for the proposed Ozone NAAQS. Applying the more recent studies would

lead to benefit

- per

- ton estimates for ozone within 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 consistent with emissions modeled in the boiler analysis. Therefore, we do not believe that those estimates to provide useful estimates of th e 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 array of vegetation and ecosystem effects in the published literature (U.S. EPA, 2013 ). Sensitivity to ozone is high ly 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 eff ects are considered adverse to the public welfare and can include reduced growth and/or biomass production in sensitive trees, reduced yield and quality of crop s, visible foliar injury, species composition shift, and changes in ecosystems and

associated ec osystem 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, t ropospheric ozone (ozone in the lower atmosphere) is a harmful air pollutant that adversely affects human health and the environment and contributes significantly to regional and global climate change. Due to its short atmospheric lifetime, tropospheric ozone concentrations exhibit large spatial and temporal variability (U.S. EPA, 2009b). A recent United Nations Environment Programme (UNEP) study

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- 26 reports that the threefold increase in ground level ozone during the past 1 00 years makes it the third most important contributor to human contributed climate change behind CO 2 

### and methane

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

.

4.6 Hazardous Air Pollutant (HAP) Benefits

When looking at exposures from all air toxic sources of outdoor origin across the U.S., we see that emissions declined by approximately 42 percent since 1990. However, despite this

decline , the 2005 National

- Sca le Air Toxics Assessment (NATA) predicts that most Americans are exposed to ambient concentrations of air toxics at levels that have the potential to cause
adverse health effects (U.S. EPA, 2011d). 28 

### The levels of air toxics to which people are exposed

vary depending on where they live and work and the kinds of activities in which they engage. In order to identify and prioritize air toxics, emission source types and locations that are of greatest potential concern, U.S. EPA conducts the NATA. 29 

### The most recen t 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, EPA estimates that about 5 percent of census tracts nationwide have increased cancer risks greater than 100 in a million. The average national cancer

risk is about 50 in a million. Nationwide, the key pollutants that contribute most to the overall

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

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

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

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- 27 cancer risks are formaldehyde and benzene. 30

, 31 

### Secondary formation (e.g., formaldehyde forming from other emitted pollutants) was the largest contributor to cancer risks, while stationary, mobile and background sources contribute almost equal portions of the remaining

cancer risk.

Noncancer health effects can result from chronic, 32 

### subchronic, 33 

### or acute 34 

### inhalation

exposure to air toxics, and include neurological, cardiovascular, liver, kidney, and respiratory effects as well as effects on the immune and reprod uctive systems. According to the 2005
NATA, about three

- fourths of the U.S. population was exposed to an average chronic concentration of air toxics that has the potential for adverse noncancer respiratory health effects.

Results from the 2005 NATA indicat e that acrolein is the primary driver for noncancer respiratory risk.

Figure 4

- 2 and Figure 4

- 3 depict the 2005 NATA estimated census tract

- level carcinogenic risk and noncancer respiratory hazard from the assessment. It is important to note

that l arge re ductions in HAP emissions may not necessarily 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 emissions were more than double a crolein

emissions on a national basis in EPA’s 2005 National Emissions Inventory (NEI). However, the Integrated Risk Information System (IRIS) reference concentration (RfC) for acrolein is considerably lower than that for acetaldehyde, suggesting that acro lein could be potentially more

30 Details on EPA’s approach to characterization of cancer risks and uncertainties associated with the 2005 NATA risk estimates can be found at http://www.epa.gov/ttn/atw/nata1999/riskbg.html#Z2

. 31 Details about the overall confidence of certainty ranking of the individual p ieces of NATA assessments including both quantitative (e.g., model

- to

- monitor ratios) and qualitative (e.g., quality of data, review of emission inventories) judgments can be found at http://www.epa.gov/ttn/atw/nata/roy/page16.html.
32 Chronic exposure is d efined in the glossary of the Integrated Risk Information System (IRIS) database (http://www.epa.gov/iris) as repeated exposure by the oral, dermal, or inhalation route for more than approximately 10 of the life span in humans (more than approximately 90 d ays to 2 years in typically used laboratory animal species).

33 Defined in the IRIS database as r epeated exposure by the oral, dermal, or inhalation route for more than 30 days, up to approximately 10 of the life span in humans (more than 30 days up to appr oximately 90 days in typically used laboratory animal species)

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

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- 28 toxic than acetaldehyde. 35 

### 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 Carcinogenic Risk from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics Inventory

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

.

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- 29 Figure 4

- 3 2005 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics Inventory

Due to methodology and data limitations, we were unable to estimate the benefits associated with the hazardous air pollutants that would be reduced as a result of this rule . In a few previous analyses of the benefits of reductions in HAP, EPA has quantified the benefits of potential reductions in the incidences of cancer and noncancer risk (e.g., U.S. EPA, 1995 ). In those analyses, EPA relied on unit risk factors (URF) and reference concentrations (RfC) developed through risk assessment procedures. The URF is a quantitative estimate of the carcinogenic potency of a pollutant, often expressed as the probability of contracting cancer from

a 70

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

### of a pollutant . 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 o f risk. An RfC is an estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure

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- 30 to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious noncancer he alth effects during a lifetime. As the purpose of a benefit analysis is to describe the benefits most likely to occur from a reduction in pollution, use of high

- end, conservative risk estimates would overestimate the benefits of the regulation. While

we us ed high

- end risk estimates in past analyses, advice from the EPA’s Science Advisory Board (SAB) recommended that we avoid using high

- end estimates in benefit analyses (U.S. EPA

SAB, 2002 ). Since this time, EPA has continued to develo p better methods for analyzing the

benefits of reductions in HAP.

As part of the second prospective analysis of the benefits and costs of the Clean Air Act (U.S. EPA, 2011a), EPA conducted a case study analysis of the health effects associated with reducing exposure to benzene in Houston from implementation of the Clean Air Act (IEc, 2009 ). While reviewing the draft report, EPA’s Advisory Council on Clean Air Compliance Analysis concluded that “the challenges for assessing progress in health improvement as a result of reductions in emissions of hazardous air pollutants (HAP) are daunting...due to a lack of

exposure

- response functions, uncertainties in emissions inventories and background levels, the difficulty of extrapolating risk e stimates to low doses and the challenges of tracking health progress for diseases, such as cancer, that have long latency periods” (U.S. EPA

- SAB, 2008 ).

In 2009, EPA convened a workshop to address the inherent complexities, limit ations, and uncertainties in current methods to quantify the benefits of reducing HAP. Recommendations from this workshop included identifying research priorities, focusing on susceptible and vulnerable populations, and improving dose

- response relationship s (Gwinn et al. , 2011 ).

In summary, monetization of the benefits of reductions in cancer incidences requires several important inputs, including central estimates of cancer risks, estimates of exposure to carcinogenic HAP, and e stimates 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 provide a qualitative analysis of the h ealth effects associated with the HAP anticipated to be reduced by this rule

. EPA remains committed to improving methods for estimating HAP benefits by continuing to explore additional concepts of benefits, including changes in the distribution of risk.

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- 31 A vailable emissions data show that several different HAP are emitted from oil and natural gas operations, either from equipment leaks, processing, compressing, transmission and distribution, or storage tanks. Emissions of eight HAP make up a large percentag e 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, toluene, carbonyl sulfide, eth yl benzene, mixed xylenes , and n

- hexane. This rule is anticipated to avoid or reduce 2, 3 5 00 tons of HAP in 2025

. With the data available, it was not possible to estimate the tons of each individual HAP that

would be reduced.

4.6.1 Benzene

The EPA’s IRIS database lists benzene as a known human carcinogen (causing leukemia) by all routes of exposure, and concludes that exposure is associated with add itional health effects, including genetic changes in both humans and animals and increased proliferation of

bone marrow cells in mice. 36

, 37

, 38 

### EPA states in its IRIS database that data indicate a causal relationship between benzene exposure and acute lymphocy tic leukemia and suggest a relationship between benzene exposure and chronic non

- lymphocytic leukemia and chronic lymphocytic leukemia. The International Agency for Research on Carcinogens (IARC) has determined that benzene is a human carcinogen and the U. S. Department of Health and Human Services has characterized benzene as a known human carcinogen. 39 , 40 

### A number of adverse

36 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene. Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm.

37 International Agency for Research on Cancer, IARC monographs on the evaluation of carcinogeni c risk of chemicals to humans, Volume 29, Some industrial chemicals and dyestuffs, International Agency for Research on Cancer, World Health Organization, Lyon, France, p. 345

- 389, 1982.

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

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

- 3695.

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

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

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- 32 noncancer health effects including blood disorders, such as preleukemia and aplastic anemia, have also been associated with long

- term e xposure to benzene. 41

, 42 

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

count in blood. 43

, 44 

### In addition, recent work, including studies sponsored by the Health Effects
Institute (HEI ), provides evidence that biochemical responses are occurring at lower levels of benzene exposure than previously known. 45

, 46

, 47

, 48 

### EPA’s IRIS program has not yet evaluated

these new data.

4.6.2 Toluene 49



### Under the 2005 Guidelines for Carcinogen Risk Assessment, ther e is inadequate information to assess the carcinogenic potential of toluene because studies of humans chronically exposed to toluene are inconclusive, toluene was not carcinogenic in adequate inhalation cancer bioassays of rats and mice exposed for life, a nd increased incidences of mammary cancer and leukemia were reported in a lifetime rat oral bioassay.

The central nervous system (CNS) is the primary target for toluene toxicity in both humans and animals for acute and chronic exposures. CNS dysfunction (which is often

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

- 197.

42 Goldstein , B.D. (1988). Benzene toxicity. Occupational medicine. State o f the Art Reviews. 3: 541

- 554.

43 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.

44 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene (Noncancer Effects). Research and Development, National Center for Environmental Assessme nt, Washington, DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm.

45 Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; Cohen, B.; Melikian, A.; Eastmond, D.; Rappaport, S.; Li, H.; Rupa, D.; Suramaya, R.; Songnian, W.; Huifant, Y.; Meng, M.; Winnik, M.; Kwok, E.; Li, Y.; Mu, R.; Xu, B.; Zhang, X.; Li, K. (2003). HEI Report 115, Validation & Evaluation of Biomarkers in Workers Exposed to Benzene in China.

46 Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohen, et al. (20 02). Hematological changes among Chinese workers with a broad range of benzene exposures. Am. J. Industr. Med. 42: 275

- 285.

47 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels of Benzene. Science 3 06: 1774

- 1776.

48 Turtletaub, K.W. and Mani, C. (2003). Benzene metabolism in rodents at doses relevant to human exposure from Urban Air. Research Reports Health Effect Inst. Report No.113.

49 All health effects language for this section came from: U.S. EPA. 2005. “Full IRIS Summary for Toluene (CASRN 108

- 88

- 3)” Environmental Protection Agency, Integrated Risk Information System (IRIS), Office of Health and Environmental Assessment, Environment al Criteria and Assessment Office, Cincinnati, OH. Available on the Internet at < http://www.epa.gov/iris/subst/0118.htm >.

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- 33 reversible) and narcosis have been frequently observed in humans acutely exposed to low or moderate levels of toluene by inhalation: symptoms include fatigue, sleepiness, headaches, and

nausea. Central nervous system depress ion 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, hearing, and vision. Chronic inhalation exposure of humans to toluene also causes irritation of the upper respiratory tract, eye irritation, dizziness, headaches, and difficulty with sleep.

Human studies have also reported developmental effects, such as CNS dysfunction,
attention deficits, and minor craniofacial a nd limb anomalies, in the children of women who abused toluene during pregnancy. A substantial database examining the effects of toluene in subchronic and chronic occupationally exposed humans exists. The weight of evidence from

these studies indicates neu rological effects (i.e., impaired color vision, impaired hearing, decreased performance in neurobehavioral analysis, changes in motor and sensory nerve conduction velocity, headache, and dizziness) as the most sensitive endpoint.

4.6.3 Carbonyl sulfid e

Limited i nformation is available on the health effects of carbonyl sulfide. Acute (short

term) inhalation of high concentrations of carbonyl sulfide may cause narcotic effects and irritate the eyes and skin in humans. 50 

### No information is available on the chronic (lo ng

- term), reproductive, developmental, or carcinogenic effects of carbonyl sulfide in humans. Carbonyl sulfide has not undergone a complete evaluation and determination under U.S. EPA's IRIS program for evidence of human carcinogenic potential. 51



### 4.6.4 Ethylbenze ne
Ethylbenzene is a major industrial chemical produced by alkylation of benzene. The pure chemical is used almost exclusively for styrene production. It is also a constituent of crude

50 Hazardous Substances Data Bank (HSDB), online database). US National Library of Medicine, Toxicology Data Network, available online at http://toxnet.nlm.nih.gov/. Carbonyl health effects summary available at http://toxnet.nlm.nih.gov/cgi

- bin/sis/search/r?dbs+hsdb:@term+@rn+@rel+463

- 58

- 1.

51 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Carbonyl Sulfide. Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at http://www.epa.gov/iris/subst/0617.htm.

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- 34 petroleum and is found in gasoline and diesel fuels. Acute (short

- term) exposure to ethylbenzene in humans results in respiratory effects such as throat irritation and chest constriction, and irritation of the eyes, and neurological effects such as dizziness. Chronic (long

- term) exposure of humans to ethylbenzene may cause ey e and lung irritation, with possible adverse effects on the

blood. Animal studies have reported effects on the blood, liver, and kidneys and endocrine system from chronic inhalation exposure to ethylbenzene. No information is available on the developmental or reproductive effects of ethylbenzene in humans, but animal studies have reported developmental effects, including birth defects in animals exposed via inhalation. Studies in rodents reported increases in the percentage of animals with tumors of the nas al and oral cavities in male and female rats exposed to ethylbenzene via the oral route. 52 , 53 

### The reports of these studies lacked detailed information on the incidence of specific tumors, statistical analysis,
survival data, and information on historical con trols, 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). 54 , 55 

### The NTP (1999) carried out a chronic inhalation bioassay in mice and rats an d found clear evidence of carcinogenic activity in male rats and some
evidence in female rats, based on increased incidences of renal tubule adenoma or carcinoma in
male rats and renal tubule adenoma in females. NTP (1999) also noted increases in the incid ence of testicular adenoma in male rats. Increased incidences of lung alveolar/bronchiolar adenoma or carcinoma were observed in male mice and liver hepatocellular adenoma or carcinoma in female mice, which provided some evidence of carcinogenic activity i n male and female mice (NTP, 1999). IARC (2000) classified ethylbenzene as Group 2B, possibly carcinogenic to humans,

based on the NTP studies.

52 Malton i C, Conti B, Giuliano C and Belpoggi F, 1985. Experimental studies on benzene carcinogenicity at the Bologna Institute of Oncology: Current results and ongoing research. Am J Ind Med 7:415

- 446.

53 Maltoni C, Ciliberti A, Pinto C, Soffritti M, Belpoggi F an d Menarini L, 1997. Results of long

- term experimental carcinogenicity studies of the effects of gasoline, correlated fuels, and major gasoline aromatics on rats. Annals NY Acad Sci 837:15

- 52.

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

- 266. IARC, Lyon, France.

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

- 41

- 4) in F344/N Rats and in B6C3F1 Mice (Inhalation Studies). Technical Report Series No. 466. NIH Publication No. 99

- 3956. U.S. Department of Health and Human Services, Public Health Service, National Institutes of Health. NTP, Research Triangle Park, NC.

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- 35 4.6.5 Mixed xylenes

Short

- term inhalation of mixed xylenes (a mixture of three closely

- related compounds) in

humans m ay cause irritation of the nose and throat, nausea, vomiting, gastric irritation, mild transient eye irritation, and neurological effects. 56 

### Other reported effects include labored breathing, heart palpitation, impaired function of the lungs, and possible ef fects in the liver and kidneys. 57 

### Long

- term inhalation exposure to xylenes in humans has been associated with a number of effects in the nervous system including headaches, dizziness, fatigue, tremors, and impaired motor coordination. 58 

### EPA has classified mi xed xylenes in Category D, not classifiable with respect to human carcinogenicity.

4.6.6 n - Hexane

The studies available in both humans and animals indicate that the nervous system is the primary target of toxicity upon exposure of n

- hexane via inhalation. There are no data in humans and very limited information in animals about the potential effects of n

- hexane via the oral route.
Acute (short

- term) inhalation exposure of humans to high levels of hexane causes mild central nervous system effects, including dizzin ess, giddiness, slight nausea, and headache. Chronic (long

- term) exposure to hexane in air causes numbness in the extremities, muscular weakness, blurred vision, headache, and fatigue. Inhalation studies in rodents have reported behavioral effects, neuroph ysiological changes and neuropathological effects upon inhalation exposure to n

hexane. Under the Guidelines for Carcinogen Risk Assessment (U.S. EPA, 2005), the database

for n

- hexane is considered inadequate to assess human carcinogenic potential, therefo re the EPA has classified hexane in Group D, not classifiable as to human carcinogenicity. 59

56 U.S. Environmental Protection Agency (U.S. EPA). 2003. Integrated Risk Information System File for Mixed Xylenes. Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at http://w ww.epa.gov/iris/subst/0270.htm.

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

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

59 U.S. EPA. 2005. Guidelines for Carcinogen Risk Assessment. EPA/630/P

- 03/001B. Risk Assessmen t Forum, Washington, DC. March. Available on the Internet at <http://www.epa.gov/ttn/atw/cancer_guidelines_final_3

- 25

- 05.pdf>.

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- 36 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 those compounds can be found in EPA’s IRIS database. 60



### 4.7 Secondary Air Emissions Impacts

The control techniques to meet the standards are associated with several types of secondary emissions impacts, which may partially offset the direct benefits of this rule. Ta b le 4

- 7 shows the

est imated secondary emissions impacts. Relative to the direct emission reductions anticipated from this rule, the magnitude of these secondary air pollutant impacts is small.

Table 4

- 6 Secondary Air Pollutant Impacts ( short tons per year)
2020 Emissions Category CO 2 NO X PM CO THC Total Hydraulically Fractured and Re

fractured Oil Well Completions 5 8 5 0,000 30 28 0 10 1,600 6 20 40 Fugitive Emissions minimal minimal minimal minimal minimal Pneumatic Pumps 2 4 4 ,000 1 2 2 0 6 6 6 2 5 5
Pneumatic Controllers 0 0 0 0 0 Compressors 550 0 0 2 1
Total 2020 61 58 0,000 31 29 0 1 0 1 1, 7 6 00 6 4 6 0



### 2025 Emissions Category CO 2 NO X PM CO THC

Total Hydraulically Fractured and Re

fractured Oil Well Completions 610 570 ,000 31 29 0 11 1, 7 6 00 6 4 6 0 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 4
Total in 2025 7 2 5 0,000 3 8 7 0 11 2, 1 0 00 79 81 0



### EPA has estimated that an increase in flaring of methane in response to this rule will produce a variety of emissions, including about 580,000 short tons (about 530,000 metric tons)

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

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- 37 of CO 2 

### i n 2020 and about 720,000 short tons (about 650,000 metric tons) of CO 2 

### in 2025

. In
addition, Table 4

- 7 presents summary

- level secondary emissions impacts across regulator y options. Note that the secondary emision impacts for the proposed option are the same as for the

more stringent option 3. This result holds because option 3 contemplates a more rigorous fugitive programs than the proposed option contains, but minimal secondary emissions impacts are expected from the fugitives program, regardless of frequency of detection and repair site visits.

Table 4

- 7 Summary

- level Secondary Air Pollutant Impacts Associated with Control s, across Regulatory Options ( short tons per year)

Option 1 Option 2 (proposed) Option 3

Polluta nt 2020 2025 2020 2025 2020 2025

CO 2 1,100,000 1,000, 000 1,200,000 1,200, 000 610,000 580,0 00 750,000 720,0 00 610,000 580,0 00 750,000 720,0 00 NO X 550 530 630 600 310 290 380 370 310 290 380 370

PM 19 19 20 20 10 11 11 11 10 11 11 11

CO 3,000 2,900 3,400 3,300 1,700 1,600 2,100 2,000 1,700 1,600 2,100 2,000

THC 1,100 1,200 1,300 1,300 640 660 790 810 640 660 790 810



### 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 absence of the flare would have eventually oxidized into CO 2 

### in the atmosphere. Note that t he CO 2 

### produced from the methane oxidizing in the atmosphere is not included in the calculation of t he SC

- CH 4



### .

However, EPA does recognize that because the growth 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 estimated 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 with the lifetime used in IPCC AR4, the

disbenefits associated with destroy ing one m etric ton of methane and releasing the CO 2


### 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 C H 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 estimates for 2025
are $7 to $34 per metric ton C H 4 

### or 0.8 percent to 1.0 percent of the SC

- CH 4 

### estimates per metric

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- 38 ton for 2025. 61 

### While EPA is not accounting for the CO 2 

### disbenefits at this time, we reque st comment on the appropriateness of the monetization of such impacts using the SC

- CO 2 

### and aspects of the calculation.

Table 4

- 8 provides a summary of the direct and secondary e missions changes

. Bas ed on this summary and analysis above , the net impact of both the direct an d secondary impacts of this proposal would be an improvement in ambient air quality, which would reduce potency of greenhouse gas emissions, reduce exposure to various harmful pollutants, improve visibility impairment, and reduce vegetati on damage.

Table 4

- 8 Summary of Emissions Changes (short tons per year , except where noted ) Option 1 Option 2 (proposed) Option 3 Pollut

ant 2020 2025 2020 2025 2020 2025
Change in Direct Emissio

ns Metha

ne 170,000 330,000 180,000 400,000 190,000 470,000

VOC 120,000 160,000 120,000 180,000 130,000 200,000

HAP 290 1,800 400 2,500 510 3,200

Change in Second
ary Emissio

ns CO 2 1,100,000 1,00 0,000 1,200,000 1,20 0,000 610,000 580 ,000 750,000 720 ,000 610,000 580 ,000 750,000 720 ,000
NO X 550 530 630 600 310 290 380 370 310 290 380 370

PM 19 19 20 20 10 11 11 11 10 11 11 11
CO 3,000 2,900 3,400 3,300 1,700 1,600 2,100 2,000 1,700 1,600 2,100 2,000
THC 1,100 1,200 1,300 1,300 640 660 790 810 640 660 790 810

Change in CO 2 Eq. Emissio

ns CO 2 Eq. (millio n short tons) 4.4 4.1 9.9 8.2 4.4 9.9 4. 6 7 12

CO 2 Eq. (millio

n metric tons) 3.7 7.4 4.0 9.0 4.2 11

Note: T otals may not sum due to independent rounding.

61 To calculate the disbenefits as sociated the complete 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 discounted 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 contained in a ton of CH 4 versus a ton of CO 2 . The value of the SC

CO 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.

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- 39 4.8 References

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

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Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. “Chronic Exposure to Fine Particles and Mortality: An Extended Follow

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### GHG Emissions: Methane and Nitrous Oxide.” Energy Policy 51:957

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- term Exposure to Fine Particulate Air Pollution.” Journal of the American Medical Association 287:1132

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### Schmalensee, R. 1993 “ Comparing greenh ouse gases for po licy purposes,” Energy Journal

, 14 (1): 245

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- Maenhout, F. Raes, J. Schwartz, G. Faluvegi, L. Pozzoli, K. Kupiainen, L. Hoglund

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. 2012

. Simultaneously mitigating near

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- 42 Shindell, D.T., G. Faluvegi, N. Bell, and G.A. Schmidt

. 2005

. “An emissions

- based view of climate forcing by methane and tropospheric ozone,” Geophysical Res earch Lett ers 32 : L04803, doi:10.1029/2004GL021900

Sisler, J.F. 1996. Spatial and seasonal patterns and long

- term variability of the composition of the haze in the United States: an analysis of data from the IMPROVE network . CIRA Report, ISSN 0737

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

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

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. 2011. An Integrated Assessment of Black Carbon and Tropospheric Ozone

, United Nations Environment Programme, Nairobi.

< http://www.unep.org/dewa/Portals/67/pdf/BlackCarbon_report.pdf >

. Accessed April 6, 2015

. United Nations Environment Programme (UNEP). 2011. Near

- Term Climate Protection and Clean Air Benefits: Actions for Controlling Short

- Lived Climate Forcers

. United Nations Environment Programme, Nairobi. < http://www.unep.org/ pdf/ Near_Term_Climate_ Protecti on_&_Air_Benefits .pdf >. Accessed March 30

, 2015

. U.S. Environmental Protection Agency (U.S. EPA). 1995. Regulatory Impact Analysis for the Petroleum Refinery NESHAP. Revised Draft for Promulgation . Office of Air Quality Planning and Standards, Research Tri angle Park, N.C.

< http://envinfo.com/caain/mact/petroria.html >. Accessed March 30, 2015

. U.S. Environmental Protection Agency (U.S. EPA). 2006b. Regulatory Impact Analysis, 2006 National Ambient Air Quality Standards for Particulate Matter , Chapter 5. Offi ce of Air Quality Planning and Standards, Research Triangle Park, NC. <http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter205

-- Benefits.pdf>. Accessed March 30, 2015.

U.S. Environmental Protection Agency (U.S. EPA). 2009a. Integrated Science Assessment for Pa rticulate Matter (Final Report). EPA

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— RTP Division. <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>. Accessed March 30, 2015

. U.S. Environmental Protection Agency (U.S. EPA). 2009b. Technical Support Document for Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act

. < http://www.epa.gov/climatechange/Downloads/endangerment/Endangerment_TSD.pdf >

. Accessed March 30, 2015

.

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

. Regulatory Impact Analysis, National Ambient Air Quality Standards for Ozone. Office of Air Quality Planning and Standards, Research Triangle Park, NC. < http://www.epa.gov/ttn/ecas/regdata/RIAs/s1

- sup plemental_analysis_full.pdf >. Accessed March 30, 2015

. U.S. Environmental Protection Agency (U.S. EPA). 2011 a

. The Benefits and Costs of the Clean Air Act from 1990 to 2020

. Office of Air and Radiation, Washington, DC

. March

. < http://www.epa.gov/cleanairac tbenefits/feb11/fullreport_rev_a.pdf >. Accessed March 30, 2015

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. Regulatory Impact Analysis : National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boile rs and Process Heaters. Office of Air Quality Planning and Standards, Research Triangle Park, NC. February

. < http://www.epa.gov/ttn/ecas/regdata/RIAs/boilersriafinal110221_psg.pdf >. Accessed March 30, 2015

. U.S. Environmental Protection Agency (U.S. EPA). 2011d

. 2005 National

- Scale Air Toxics Assessment

. Office of Air Quality Planning and Standards, Research Triangle Park, NC. March

. < http://www.epa.gov/ttn/atw/nata2005/ > Accessed March 30, 2015

. U.S. Environmental Protection Agency (U.S. EPA). 2011g. Regul atory Impact Analysis for the Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States; Correction of SIP Approvals for 22 States. Office of Air Quality Planning and Standards, Research Triangle Park, NC . July. <http:// www.epa.gov/airtransport/pdfs/FinalRIA.pdf>. Accessed March 30, 2015

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. Residual Risk Assessment for the Oil and Gas Production and Natural Gas Transmission and Storage Source Categories

. Office of Air Quality Planning and Standards, Research Triangle Park, NC.

U.S. Environmental Protection Agency (U.S. EPA). 2012b. Regulatory Impact Analysis Final New Source Performance Standards and Amendments to the National Emissions Standards for Haz ardous Air Pollutants for the Oil and Natural Gas Industry . Office of Air Quality Planning and Standards, Health and Environmental Impacts Division. April.

< http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf

>. Accessed Mar ch 30, 2015

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. EPA

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- 003. Office of Air Quality Planning and Standards, He alth and Environmental Impacts Division. December. Available at: <http://www.epa.gov/ttnecas1/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf>. Accessed March 30, 2015

.

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- 44 U.S. Environmental Protection Agency (U.S. EPA). 2012 d. Regulatory Impact Analys is: Final Rulemaking for 2017

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. EPA

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< http://www.epa.gov/otaq/climate/documents/420r12016.pdf >. Accessed March 30, 2015.

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- 10/076F. February. <http://cfpub.epa.gov/ncea/isa/recordisplay.cfm?deid=247492#Download>. Accessed March 30, 2015

. U.S. Environmental Protection Agency (U.S. EPA). 2014a. Health Risk and Exposure Assessment for Ozone (F inal 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

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- 452/P

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- 006. December. <http://www.epa.gov/ttnecas1/regdata/RIAs/20141125ria.pdf>. Accessed March 30, 2015

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U.S. Environm ental Protection Agency (U.S. EPA). 201 4c

. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990

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- SAB). 2002. Workshop on the Benefits of Reductions in Exposure to Hazardous Air Pollutants: Developing Best Estimates of Dose

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- g.pdf>. Accessed March 30, 2015

. U.S. Environmental Protection Agency

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- SAB). 2008. Benefits of Reducing Benzene Emissions in Houston, 1990

– 2020 . EPA

- COUNCIL

- 08

- 001. July. <http://yosemite.epa.gov/sab/sabproduct.nsf/D4D7EC9DAEDA8A548525748600728A8 3/$File/EPA

- COUNCIL

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- 001

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. 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

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. Accessed April 3, 2014.

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- 45 West et al. 2006. “Global health benefits of mitigating ozone pollution with methane emission controls.” P roceedings of the National Academ y of Sciences 103( 11 ) :3988

- 3993.

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. 2005

. “ Management of tropospheric ozone by reducing methane emissions.” Environmental Science & Technology 39:4685

- 4691.

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- 1 5 STATUTORY AND EXECUT IVE O RDER REVIEWS

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

Under 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

th e economy of $100 million or more. Accordingly, the EPA submitted this action to the Office of Management and Budget ( OMB ) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendati ons have been

documented in the docket for this action. Table s 6

- 1 through 6

- 4 shows the results of the cost and benefits analysis for th is proposed rule.

5.2 Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. The ICR document prepared by the EPA has been assigned EPA ICR Numbers ####.## (40 CFR part 60, subpart OOOOa). You can find a co py of the ICR in the docket for this rule, and it is briefly summarized here.

The information to be collected for the proposed NSPS is based on notification, recordkeeping and reporting requirements in the NSPS which are mandatory for all operators subjec t to national emission standards. These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.

These proposed rules would require maintenance inspections of the control devices, but would not require any notifications or reports be yond those required by the General Provisions.

The recordkeeping requirements require only the specific information needed to determine compliance. For sources subject to the proposed NSPS, burden changes associated with these

amendments result from the re spondents’ annual reporting and recordkeeping burden associated

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- 2 with this proposed rule for this collection (averaged over the first 3 years after the effective date of the standards). The burden is estimated to be 92,450 labor hours at a cost of $3,156,60 5 per year. The average hours and cost per regulated entity subject to the NSPS for oil and natural gas affected facilities would be 3.9 hours per response and $1,237 per response, based on an average of 2,552 operators responding per year providing 92,450 responses per year. Burden is defined at
5 CFR 1320.3(b).

An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB

control numbers for th e EPA’s regulations in 40 CFR are listed in 40 CFR part 9.

Submit your comments on the Agency’s need for this information, the accuracy of the provided burden estimates and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. You may also send your ICR

related comments to OMB’s Office of Information and Regulatory Affairs via email to RIA_submissions@omb.eop.gov , Attention: Desk Officer for the EPA. Since OMB is required

to make a deci sion concerning the ICR between 30 and 60 days after receipt, OMB must receive comments no later than [insert date 30 days after publication in the Federal Register]. The EPA will respond to any ICR

- related comments in the final rule.

5.3 Regulatory Flexibili ty Act

[ Placeholder for In itial Regulatory Flexibility Analysis]

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 affect small governments. The a ction imposes no enforceable duty on any state, local or tribal go vernments or the private sector

.

5.5 Executive Order 13132: Federalism

This action does not have federalism implications. It will not have substantial direct

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- 3 effects on the states, on the relati onship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. These final rules primarily affect private industry and would not impose significant economic costs on state or local governments

.

5.6 Executive Order 13175: Consultation and Coordination with Indian Tribal Governments

This action has tribal implications. Ho wever, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law. The majority of the units impacted by this rulemaking on tribal lands are owned by private entities,

and tribes will not b e directly impacted by the compliance costs associated with this rulemaking. There would only be tribal implications associated with this rulemaking in the rare case where a unit is owned by a tribal government or a tribal government is given delegated aut hority to enforce the rulemaking.

The EPA consulted with tribal officials under the EPA Policy on Consultation and Coordination with Indian Tribes early in the process of developing this regulation to permit them to have meaningful and timely input into i ts development. Additionally, the EPA has conducted meaningful involvement with tribal stakeholders throughout the rulemaking process. We provided an update on the methane strategy on the January 29, 2015 NTAA and EPA Air Policy call. As required by sectio n 7(a), the EPA’s Tribal Consultation Official has certified that the requirements of the Executive Order have been met in a meaningful and timely manner. A copy

of the certification is included in the docket for this action.

Consistent with previous actio ns affecting the oil and natural gas sector, there is significant tribal interest because of the growth of the oil and natural gas production in Indian country. The EPA specifically solicits additional comment on this propos ed action from tribal

officials

.

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- 4 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 safety risk addressed by th is action has a disproportionate effect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children.

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

The assessment literature cited in the EPA’s 2009 Endangerment Finding concl uded that certain populations and life stages, including children, the elderly, and the poor, are most

vulnerable to climate

- related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings rega rding these groups’ vulnerabilities and the projected impacts they may experience.

These assessments describe how children’s unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to chil dren are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as healt h effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within hou seholds.

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

Executive Order 13211 (66 FR 28355, May 22, 2001) provides that agencies will prepare

and submit to the Administrator of the Offic e of Information and Regulatory Affairs, Office of

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- 5 Management and Budget, a Statement of Energy Effects for certain actions identified as “significant energy actions.” Section 4(b) of Executive Order 13211 defines “significant energy actions” as any action by an agency (normally published in the Federal Register) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1)(i) that is a significant regulatory action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action

.

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

T he EPA used the National Energy Modeling System (NEMS) to estimate the impacts of the proposed rule on the United States energy system. The NEMS is a publically

- avail able model of the United States energy economy developed and maintained by the Energy Information Administration of the DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States ener gy economy.

We estimate that natural gas and crude oil production levels remains essentially 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 produc tion (about 2,000 barrels per day or 0.03 percent). Wellhead natural 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 price s for onshore lower 48 production are not estimated to change, 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 202 5 (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 percent) in 2025.

Additionally, the NSPS establishes several performance standards that give regulated

entities f lexibility in determining how to best comply with the regulation. In an industry that is

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- 6 geographically and economically heterogeneous, this flexibility is an important factor in reducing regulatory burden. For more information on the estimat ed energy effe cts of this proposed rule, please see Section 7 of this RIA.

5.9 National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995
(NTTAA), Public Law No. 104

– 113 (15 U.S.C. 272 note) directs the EPA to use voluntary

consensus standards (VCS) in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are technical 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 provide Congress, through OMB, explanations when the Agency decides not to use available and applicable VCS.

The proposed rule involves technical standards. Therefor e, the requirements of the NTTAA apply to this action. We are proposing 40 CFR part 60, subpart OOOOa to allow

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 on ly and not the instrumental 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 proposed rulemaking and, specifically, i nvites the public to identify potentially

- applicable VCS and to explain why such standards should be used in this regulation

.

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

- Income Populations

The EP A believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low

- income or indigenous populations. The EPA has determined this beca use the rulemaking increases the level of environmental protection for all affected populations without

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- 7 having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low

- income or indigenous populations. The EPA has provided meaningful participation opportunities for minority, low

- income, indigenous populations and tribes during the pre

- proposal period by conducting community calls and webinars. Additionally, the EPA will conduct outreach for communities after the rulemaking is

finalized

.

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- 1 6 COMPARISON OF BENEFI TS AND C OSTS

Tables 6

- 1 though Table 6

- 3 present the summary of the benefits, costs, and net benefits

for the NSPS across regulatory option s , where Table 6

- 1 presents the proposed option , Table 6

- 2 presents a less stringent regulatory option, and Table 6

- 3 presents a more stringent regulatory option

. Table 6

- 4 provides a summary of the direct and secondary emissions changes for each regulatory option

.

Table 6

- 1 Summary of the Monetized Benefits, Costs, and Net Benefits for the Proposed NSPS in 2020 and 2025

2020 2025

Total Monetized Benefits 1 $210 million $550 million

Total Costs 2 $170 million $4 20 10 million

Net Benefits 3 $ 3 5 8 million $1 2 4 0 million

Non

- monetized Benefits Non

- monetized climate benefits Non

- monetized climate 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 180,000 tons of VOC reduced Health effects of HAP exposure from 400 tons of HAP reduced Health effects of HAP exposure from 2,500 tons of HAP reduced Health effects of ozone exposure from 180,000 tons of methane Health effects of ozone exposure from 400,000 tons of methane

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC

- CH 4 ) (model average at 2.5 percent discount rate, 3 percent, 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. However we emphasize the importance an d value of considering the benefits calculated using all four SC

- CH4 estimates; the additional benefit estimates range from $93 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 4.0 million metric tons in 2020 and 9.0 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 using 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 di scount rate as they are for the 7 percent 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.

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- 2 Table 6

- 2 Summary of the Monetized Benefits, Costs, and Net Benefits for the Less Stringent Option for the NSPS in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits 1 $190 million $450 million
Total Costs 2 $80 million $ 240 220 million
Net Benefits $110 million $ 210 230 million

Non

- monetized Benefits Non

- monetized climate benefits Non

- monetized climate 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 160,000 tons of VOC reduced Health effects of HAP exposure from 290 tons of HAP reduced Health effects of HAP exposure from 1,800 tons of HAP reduced Health effects of ozone exposure from 170,000 tons of methane Health effects of ozone exposure from 330,000 tons of methane Visibility impairment Visibility impairment

Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC

- CH4) (model average at 2.5 percent discount rate, 3 percent, 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. However we emphasize the importance and value of considering the benefits calculated using all four SC

- CH4 estimates; the additional benefit estimates range from $87 million to $520 million in 2020 and $210 million to $1,200 million in 2025 for this less stringent option , as shown in Section 4.3. The CO 2 - equivalent (CO 2 Eq.) methane emission reductions are 3.7 million metric tons in 2020 and 7.4 million metric tons in 2025 . Also, the specific control technologies for the proposed NSP S are anticipated to have minor secondary disbenefits.

2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost est imates are the same for the 3 percent discount rate as they are for the 7 percent 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.

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- 3 Table 6

- 3 Summary of the Monetized Benefits, Costs, and Net Benefits for the More Stringent Option for the NSPS in 2020 and 2025 (2012$)

2020 2025

Total Monetized Benefits 1 $220 million $640 million
Total Costs 2 $210 million $ 680 660 million
Net Benefits $ 7.6 10 million

- $ 35 20 million

Non

- monetized Benefits Non

- monetized climate benefits Non

- monetized climate 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 5 1 0 0 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 different estimates of the social cost of methane (SC

- CH4) (model average at 2.5 percent discount rate, 3 percent, 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. However we emphasize the importance and value of considering the benefits calculated using all four SC

- CH4 estimates; the additional benefit estimates range from $ 99 million to $5 9 0 million in 2020 and $30 0 million to $1, 7 00 million in 2025 for this more stringent option , as shown in Section 4.3

. The CO 2 - equivalent (CO 2 Eq.) methane emission reductions are 4.2 million metric tons in 2020 and 10.6 million metric tons in 2025

. Also, t he specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefi ts

. 2 T he engineering compliance costs are annualized using a 7 percent discount ra t e 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 ar e for the 7 percent 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.

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- 4 Table 6

- 4 Summary of Emissions Changes across Option for the NS PS in 2020 and 2025 (short tons per year , unless otherwise noted )

Option 1 Option 2 (proposed) Option 3

Pollutant 2020 2025 2020 2025 2020 2025

Chan ge in Direct Emiss ions Methane 170,00 0 330,0 00 180,000 400,000 190,000 470,000

VOC 120,00 0 160,0 00 120,000 180,000 130,000 200,000

HAP 290 1,800 400 2,500 510 3,200

Chan ge in Secon dary Emiss ions CO 2 1,100,0 00 1,00 0,000 1,200, 000 1, 200,0

00 610,000 58 0,000 750,000 720,000 610,000 5 80,000 750,000 7 20,000

NO X 550 530 630 60 0 310 290 380 370 310 290 380 370

PM 19 19 20 20 10 11 11 11 10 11 11 11

CO 3,000 2, 900 3,400 3,300 1,700 1,60 0 2,100 2,0 00 1,700 1,6 00 2,100 2,0 00

THC 1,100 1, 200 1,300 1,300 640 660 790 810 640 660 790 810

Chan ge in CO 2 Eq. Emiss ions CO 2 Eq. (million short tons) 4.4 1 8.2 9.9 4.4 9.9 4. 6 7 11.7

CO 2 Eq. (million metric tons) 3.7 7.4 4.0 9.0 4.2 1 1 0.6



### Option 1 Option 2 (proposed) Option 3

Pollutant 2020 2025 2020 2025 2020 2025

Change in Direct Emissions Methane 170,000 330,000 180,000 400,000 190,000 470,000

VOC 120,000 160,000 120,000 180,000 130,000 200,000

HAP 290 1,800 400 2,500 510 3,200

Change in Secondary Emissions CO 2 1,100,000 1,200,000 610,000 750,000 610,000 750,000

NO X 550 630 310 380 310 380

PM 19 20 10 11 10 11

CO 3,000 3,400 1,700 2,100 1,700 2,100

THC 1,100 1,300 640 790 640 790 Formatted Table

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- 5 Change in CO 2 Eq. Emissions CO 2 Eq. (million short tons) 4.1 8.2 4.4 9.9 4.6 11.7

CO 2 Eq. (million metric tons) 3.7 7.4 4 9 4.2 11

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- 1 7 ECONOMIC IMPACT ANAL YSIS AND DISTRIBUTIONAL ASSES SMENTS

7.1 Introduction

This section include s three sets of analyses for the proposed NSPS :

• Energy System Impacts

• Employment Impacts

• Small Entity Impacts Analysis

7.2 Energy System Impacts Analysis

We use the National Energy Modeling System (N EMS) to estimate the impacts of the proposed NSPS on the U.S. energy system. The impacts we estimate include changes in drilling activity, price and quantity changes in the production and consumption of crude oil and natural gas, and changes in internation al trade of crude oil 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. A brief conceptual discussion about our ene rgy system impac ts 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 performing reduced emissions completions on hydraulically

fractured oil wells contributes about 75 percent of the natural gas captured by emissions contro ls

in 2020 and about 32 percent of captured natural gas in 2025. The fugitive emissions program at well sites is expected to capture about 18 percent of the natural gas captured by emissions

controls in 2020 and about 52 percent of captured natural gas in 2025.

T he assumed $4/Mcf price for natural gas is the price paid to producers at the wellhead. In the natural gas industry, production is metered at or very near to the wellhead, and producers are paid based upon this metered production. Depending on the situation, the gas captured by a
REC is sent through a temporary or permanent meter. Payments for the gas are typically made within 30 days.

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- 2 In the engineering cost analysis, it is necessary to estimate the expected costs and revenues from implementing emi ssions controls at the unit level. Because of this, we estimate the net costs as expected costs minus expected revenues for representative units. On the other hand, NEMS models the profit maximizing behavior of representative project developers at a drilli ng project level. The net costs of the regulation alter the expected discounted cash flow of drilling and implementing oil and gas projects, and the behavior of the representative drillers adjusts accordingly. While in the regulatory case natural gas drill ing has become more efficient because of the gas recovery, project developers still interact with markets for which supply and demand are simultaneously adjusting. Consequently, project development adjusts to a new equilibrium.

While we believe the cost sa vings as measured by revenues from selling recovered gas (engineering costs) and measured by cost savings from averted production through efficiency gains (energy economic modeling) are approximately the same, it is important to note that the engineering c ost analysis and the national

- level cost estimates do not incorporate economic feedbacks such as supply and demand adjustments.

7.2.1 Description of the Department of Energy National Energy Modeling System

NEMS is a model of U.S. energy economy developed and maintained by the Energy Information Administration of the U.S. Department of Energy (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 developed 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 s ource code available and fully documented for the public. The source code and accompanying documentation is released annually when a new Annual Energy Outlook is produced. Because of the availability of the NEMS model, numerous age ncies, national laboratories, research institutes, and academic and private

- sector researchers have used NEMS to analyze a variety of issues.

NEMS models the dynamics of energy markets and their interactions with the broader U.S. economy. The system projec ts the production of energy resources such as oil, natural gas, coal, and renewable fuels, the conversion of resources through processes such as refining and

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- 3 electricity generation, and the quantity and prices for final consumption across sectors and regio ns. The dynamics of the energy system are governed 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 programming model. NEMS iteratively solves multiple models, linear and non

- linear, using nonlinear Gau ss

- Seidel methods
(Gabriel et al. 2001)

. What this means is that NEMS solves a single module, holding all else constant at provisional solutions, then moves to the next model after establishing an updated provisional solution.

NEMS provides what EIA refer s to as “mid

- term” projections to the year 2040. For this RIA, we draw upon the same assumptions and model used in the Annual Energy Outlook 2014. 62 

### The RIA baseline is consistent with that of the Annual Energy Outlook 2014 which is used extensively in Sect ion 2 in the Industry Profile.

7.2.2 Inputs to National Energy Modeling System

To model potential impacts associated with the proposed rule , we modified oil and gas production costs within the Oil and Gas Supply Module (OGSM) of NEMS and domestic and

Canadian natural gas production within the Natural Gas Transmission and Distribution Module
(NGTDM). The OGSM projects domestic oil and gas production from o nshore, offshore,

Alaska n wells, as well as having a smaller

- scale treatment of Canadian oil and gas product ion
(U.S. EIA, 2014). The treatment of oil and gas resources is detailed in that oil, shale oil, conventional gas, shale gas, tight sands gas, and coalbed methane (CBM) are explicitly modeled.

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

- level production economics govern finding and success rates and costs

.

62 Assumptions for the 201 4 Annual Energy Outlook can be found at

< http://www.eia.gov/forecasts/aeo/assumptions/ >.

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- 4 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 oi l and gas productio n 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 recovered when implementing the proposed rule

.

While the o il production simulated b y the OGSM is sent 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 NGTDM balances gas supplies and prices and “negotiates” supply and co nsumption to determine a regional equilibrium between supply, demand and prices, including imports and exports via pipeline or LNG. Natural gas is

trans ported through a simplified arc

- node representation of pipeline infrastructure based upon pipeline econo mics

.

7.2.2.1 Compliance Costs for Oil and Gas Exploration and Production

As the NSPS affects new emissions sources, we chose to estimate impacts on new exploration and development projects by adding costs of environmental regulation to the algorithm that evaluate s the profitability of new projects. Additional NSPS costs associated with reduced emission completions for hydraulically fractured oil well completions are added to the drilling and completion costs of oil wells in the OGSM.

Other costs are operations an d maintenance

- type costs 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, depending on whether the costs would apply to oil

wells or natural gas wells

. We base the per well cost estimates on the engineering costs . Because we model natural gas recovery, we do not include revenues from additional product recovery in

these costs

. This approach is appropriate given the structure of the NEMS algori thm that estimates the net present value of drilling projects.

One caveat in introducing new cost requirements into the model is that potential barriers to obtaining capital may not be adequately incorporated in the model. However, i n general, potential barriers to obtaining additional capital should be reflected in the annualized cost via

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- 5 these barriers increasing the cost of capital. With this in mind, assuming the estimates of capital costs and product recovery are valid, the NEMS results will reflect barriers to obtaining the

re quired capital. A caveat to this is that the estimated unit

- level capital costs of controls that are newly required at a national

- leve l as a result of the regulation may not incorporate potential

additional transitional costs as the supply of control equipment adjusts to new demand.

Table 7

- 1 shows the incremental compliance that accrue to new drilling pr ojects 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, w e first ide ntify 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 o f successful completions 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 emissions poin t by the appropriate number of expected new wells in the year of analysis. The result yields an approximation of per well compl iance costs. We assume this approximation is representative of the incremental cost faced by a producer when evaluating a prospective drilling project (Table 1)

.

Hydraulically fractured oil wells completions and fugitives 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 combustion alone. The resulting co st is itself weighted by the proportion of new hydraulically fractured oil wells estimated to be affected by the regulation (70 percent).

Meanwhile, assuming there is an average of two wells per wells site (see TSD for more details), new oil and gas wells face an increased annual cost of one

- half of implementing the well site fugitive emission requirements.

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- 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 5,107 9 Reciprocating Compressors Transmission Stations New Gas Wells $1,748 $5 1,122 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 Production

A result of controlling methane and VOC emissions from oil and natural gas production is that methane that would otherwise be lost to the atmosphere can be directed into the natural gas production stream. We chose to model methane capture in NEMS as an increase in natural gas industry productivity, ensuring that, within the model, natural gas reservoirs are not decremented by production gains from methane capture. We add estimates of the quantities of methane captured (or otherwise not vented or combusted) to the base quantities that the OGSM model supplies to the NGTDM model. We subdivide the estimates of commercially valuable averted emissions by region and well type in order to more accurately portray the economics of implementing the envir onmental technology. Adding the averted methane emissions in this

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- 7 manner has the effect of moving the natural gas supply curve to the right an increment consistent with the technically achievable emissions transferred into the production stream as a result of the proposed NSPS.

We enter the increased natural gas recovery into NEMS on a per

- well basis for new natural gas wells, following an estimation procedure 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 we re unable to incorporate the natural gas recovery from performing RECs on hydraulically fractured oil well completions or from other emissions control activities at oil well sites

. We hope to make

this modification in t he RIA for the final rule.

7.2.3 Energy System Impacts

As mentioned earlier, we estimate impacts to drilling 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. In each of these estimates, we present estimat es for the baseline years of 2020 and

202 5 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 a ctivities 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 in 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.

W e first report estimates of impacts on crude oil and natural gas drilling activities and production. Table 7

- 2 presents esti mates of successful onshore natural gas and crude oil wells

drilled in the continental U.S.

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- 8 Table 7

- 2 Successful Oil and Gas Wells Drilled (Onshore, 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 27,638 155,201 155,202 Total 37,482 44,959 44,959 52,375 52,438 297,965 297,840

% 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%



### Results sho w that the proposed NSPS will have a relatively small impact on onshore well drilling in the lower 48 states. Drilling remains essentially unchanged in 2020, but increases for natural gas wells in 2025, while decreasing for crude oil wells in 2025. The increase in natural gas well drilling in 2025 is so mewhat counter

- intuitive as production costs have been increased under the proposed NSPS. However, given NEMS is a dynamic, multi

- period model, it is important to examine changes over multiple time periods. Natural gas well drilling over the 2020 to 2025 p eriod decreases but about 120 wells total. Crude oil drilling, over the same six

- year, period remains at the same levels.

T able 7

- 3 shows estimates of the changes in the domestic 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%

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- 9 As indicated by the estimated change in the new well drilling activities, the analysis

show s that the proposed NSPS will have a relatively small impact on onshore natural gas and crude oil production in the lower 48 states. Again, produc tion levels Drilling remains essentially 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 day or 0.03 percent). T otal production over the 2020 to 2025 is also estimated to decline for natural ga s (by about 9 bcf or 0.01 percent) and crude oil (by about 1,000 barrels per day or

about 0.01 percent)

Note this analysis estimates no increase in domestic natural gas production , despite some

environmental controls anti c ip ated to be used in response to the proposed rule capture natural gas
that would otherwise be emitted ( 8.2 bcf in 2020 and 19 bc f in 2025 )

. There are two sources for this difference. First, we were unable to incorporate 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, NEM S models the adjustment of energy markets to the n e w slightly more costly natural gas and crude oil productive activities. At the new post

- rule equilibrium, producers implementing emissions controls are still anticipated to capture and sell the captured na tural gas, and this natural gas might 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 wellhead natural gas and crude oil prices for onshore pro duction in the lower 48 states

.

Table 7

- 4 Average Natural Gas and Crude Oil Wellhead 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 5.064 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 Baseline

Natural Gas 0.00% 0.14% 0.06% Crude Oil 0.00% 0.00% 0.00%

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- 10 Wellhead natural gas price s 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. 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, well crude oil p rices 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 relatively small scale of the costs of the new compliance requirements, as well as th e fact that oil prices are more a function of global prices that are natural gas prices.

Meanwhile, a s shown in Table 7

- 5

, net imports of natural 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 total 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%



### 7.3 Small Entity Analysis

[ Placeholder for Initial Regulatory Flexibility Analysis ]

7.4 Employment Impact Analysis

In addition to addressin g the costs and benefits of the proposed rule, EPA has analyzed the impacts of this rulemaking on employment, which are presented in this section. While a standalone analysis of employment impacts is not included in a standard cost

- benefit analysis,

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- 11 such an analysis is of particular concern in t he current economic climate given continued interest in the employment impact o f regulations such as this proposed rule. Executive Order 13563, states, “Our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation.” 63 

### A

discussion of compliance costs, including reporting and recordkeeping requi rements, is included

in Section 3 of this RIA. This analysis uses detailed engineering information on labor requi rements for each of the control strategies identified 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 portion of potent ial employment impacts within the regulated industry, and do not represent estimates of the net employment impacts of this rule. First, this section presents an overview of the various ways that environmental regulation can affect employment. EPA continues to explore the relevant theoretical and empirical literature and to seek public comments in order to ensure that the way EPA characterizes the employment effects of its regulations is valid and informative. The section concludes with partial employment

im

pact estimates that rely on engineering

- based information for labor requirements for each of the control strategies identified by the proposed rule.

7.4.1 Employment Impacts of Environmental Regulation

From an economic perspective labor is an input into producin g goods and services; if a regulation requires that more labor be used to produce a given amount of output, that additional labor is reflected in an increase in the cost of production. Moreover, when the economy is at full employment, we would not expect a n environmental regulation 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 (both positive and negative) are possible.

For example, an increase in labor demand due to regulation 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 t o produce new abatement capital resulting in hirin g previously unemployed workers . When

63 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.

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- 12 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 reg ulation 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 indus try 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 context of environmental regulation, and suggest that, for example, if all firms in the industry are faced with the same compliance costs of regulation and product demand is inelastic, then industry output may not change much a t all.

Regulations set in motion new orders for pollution control equipment and services. New categories of employment have been created in the process of implementing environmental regulations. When a regulation is promulgated, one typical response of ind ustry is to order pollution control equipment and services in order to 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 com ply 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 the environmental technology industry. While these increases represent g ains for that industry, they translate into costs to the regulated industries required to install the equipment.

Environmental regulations support employment in many basic industries. Regulated firms either hire workers to design and build pollution contro ls directly or purchase pollution control devices from a third party for installation. Once the equipment is installed, regulated firms hire workers to operate and maintain the pollution control equipment

— much like they hire workers to produce more output. In addition to the increase in employment in the environmental protection industry (via increased orders for pollution control equipment), environmental regulations also support employment in industries that provide intermediate goods to the

environmental protection industry. The equipment manufacturers, in turn, order steel, tanks, vessels, blowers, pumps, and chemicals to manufacture and install the equipment. Currently in most cases there is no scientifically defensible way to generate sufficiently reli able estimates of

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- 13 the employment impacts in these intermediate goods sectors.

Berman and Bui (2001) demonstrate using standard neoclassical microeconomics that environmental regulations have an ambiguous effect on employment in the regulated sector. The

th eoretical results imply that the effect of environmental 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 in novative approach to examine how an increase in local air quality regulation that reduces nitrogen oxides ( NO X 

### ) emissions affects manufacturing employment in the South Coast Air Quality Management District (SCAQMD), which incorporates Los Angeles and its s uburbs. 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 regulations, Berman and Bui identify the effect of environmental regulations on ne t employment in the regulated industries. 64 

### 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 l abor demand slightly” but that “the employment 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). 65



### While there is an extensive e mpirical, peer

- reviewed literature analyzing the effect of environmental regulations on various economic outcomes including productivity, investment, competitiveness as well as environmental performance, there are only a few papers that examine the impact of environmental regulation on employment, 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 regulations do not have a s ubstantial impact on net employment (either negative or positive) in the regulated sector. Similarly, Ferris, Shadbegian, and Wolverton (2014) also find that regulation

- 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 in EPA’s 1998 “Cluster Rule” experienced

64 Berman and Bui include over 40 4

- digit SIC industries in their sample.
65 Including the employment effect of exiting plants and plants dissuaded from opening will increase the estimated impact of regulation on e mployment.

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- 14 relatively small and not always statistically significant, decreases in employment. Nevertheless, other empirical res earch suggests that more highly regulated counties may generate fewer jobs than less regulated ones (Greenstone 2002, Walker 2011). However, the methodology used in these two studies cannot estimate whether aggregate employment is lower or higher due to mo re stringent environmental regulation, it can only imply that relative employment growth in some sectors differs between more and less regulated areas. List et al. (2003) find some evidence that this type of geographic relocation, from more regulated areas to less regulated areas may be occurring. Overall, the peer

- reviewed literature does not contain evidence that environmental regulation has a large impact on net employment (either 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 quant itative estimates to estimate the employment impacts from this proposed regulation. In particular, the industries used in these two studies as well as the timeframe (late 1970’s to early 1990’s) are quite different than those in this proposed NSPS.

Further more, the control strategies analyzed for this RIA include implementing RECs, reducing fugitive emissions, and reducing emissions from pneumatic controllers, pumps, and reciprocating and centrifugal compressors , which are very different than the control st rategies examined by

Berman and Bui. 66 

### For these reasons we conclude there are too many uncertainties 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 a ssessment of employment impacts

.

The preceding sections have outlined the challenges associated with estimating net employment effects in the regulated sector and in the e nvironmental protection sector. These challenges make it very difficult to accurately produce 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

66 More detail on how emission reductions expected from compliance with this rule can be obtained can be found in Section 3 of this RIA.

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- 15 estimating national impacts of regulations, EPA has not generally estimated economy

- wide employment impacts of its regulations in its benefit

- cost analyses. However, in its continuing

effort to advance t he evaluation of costs, benefits, and economic impacts associated with environmental regulation, EPA has formed a panel of experts as part of EPA’s Science Advisory Board (SAB) to advise EPA on the technical merits and challenges of using economy

- wide

econ omic models to evaluate the impacts of its regulations, including the impact on net national employment. 67 

### Once EPA receives guidance from this panel it will carefully consider this input and then decide if and how to proceed on economy

- wide modeling of emp loyment impacts of its regulations.

7.4.2 Labor Estimates Associated with Proposed Requirements

Section 2 of the RIA, in Tables 2

- 17 and 2

- 18, presents background information on employment and wages in the oil and natural gas industry. As well as producing much of the U.S. energy supply, the oil and natural gas industry 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. 68 

### 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 Gas Extraction (NAICS 211111) and Support Activities for Oil and Gas Operations (NAICS 213112) employ the majority of workers in the industry. From 1990 to 2013, average wages for the oil and natural gas industry have increased. Tab le 2

- 18 shows real wages (in 2012 dollars) from 1990 to 2013 for the NAICS codes associated with the oil and natural gas industry.

T he focus of this part of the analysis is on labor require ments related to the compliance

actions for the proposed rule, of the affected entities 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, w e do not estimate net employment impacts for the affected sector, apart from the partial estimate of the labor requirements related to control strategies. This analysis estimates the labor required to the install, operate, and maintain control equipment and

67 For further information see: http://yosemite.epa.gov/sab/sabproduct.nsf/0/07E67CF77B54734285257BB0004F87ED? OpenDocument

68 NAICS 211111, 21112, 213111, 213112, 486110, and 486210.

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- 16 activities , as well as to perform new reporting and recordkeeping requirements.

It is important to highlight that unlike the typical case where to reduce output negative production externality (i.e., e missions) a firm often has to reduce production, many of the

em ission controls required by the proposed NSPS will simultaneously increase production and

reduce negative externalities . That is, these controls jointly produce environmental improvements and i ncrease output in the regulated sector . New labor associated with implementing these controls to comply with the new regulations can also be viewed as additional labor increasing output while reducing undesirable emissions. To the extent, however, that the se rules may require unprofitable investments for some operators, there is a possibility that these producers decrease output in response and create downward pressure on labor demand, both in the regulated sector and on those sectors using natural gas as a n input. This RIA does not include quantified estimates of these potential adverse effects on the labor market due to data and theoretical challenges, as described above.

No estimates of the labor used to manufacture or assemble pollution control equipment or to supply the materials for manufacture or assembly are included because EPA does not currently have this information. The labor requirements analysis uses a bottom

- up engineering

- based methodolog y to estimate employment impacts . The engineering cost a nalysis summarized in Chapter 3 of this RIA includes estimates of the labor requirements associated with implementing the regulations. Each of these labor changes may either be required as part of an initial effort to comply with the new regulation or requ ired as a continuous or annual effort to maintain compliance. We estimate up

- front and continual, annual labor requirements by estimating hours of labor required and converting this number to full

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

The results of this employment analysis of the proposed NSPS are presented in Tables 7

- 6 through Table 7

- 9 for 2020 and 2025 for individual sources regulate d under this proposal.

Table 7

- 10 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

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- 17 RIA and present both the estimated hours required and the conversion of this estimate to FTE. The labor information is based upon the cost analysis presented in the TSD that supports this proposal, ba sed 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, f or the proposed NSPS, reporting and recordkeeping requirements were estimated for the entire rule ra ther than by anticipated control requirements; the reporting and recordkeeping estimates are consistent with estimates EPA submitted as part of its Information Collection Request (ICR) , the estimated costs of which are included in the cost estimates presen ted in Chapter 3

.

Table 7

- 6 presents estimates labor requirements for hydraulically fractured oil well completions. The REC and completion combustion requirements are associated with certain new and existing oil well completions . While individual completi ons occur over a short period of time (days to a few weeks), new wells and other existing wells are completed annually. Because
of these reasons, we assume the REC

- related labor requirements are annual.

The per unit estimates of one

- time labor requirements associated with implementing RECs and completion combustion are drawn from the labor requirements estimated for implementing RECs on hydraulically fractured well completions in U.S. EPA (2012). However, the labor requirements in that report were based upo n a completion that is assumed to last seven days (218 hours per completion for a REC or 22 hours labor per completion for completion
combustion) . In this analysis, completion events for hydraulically fractured oil wells are assumed to last three days , so we multiply the seven

- day requirements by 3/7 (93 hours per completion for a REC or 9 hours labor per completion for completion combustion).

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- 18 Table 7

- 6 Estimates of Labor Required to Comply with Proposed NSPS for Hydraulically Fractured Oil Well Completions, 2020 and 2025

Emissions

Source Emissions Control Projected No. of Incr. Affected

Units Per Unit One

time Labor Est. (hrs) Per Unit Annual Labor Est. (hrs) Total One

Time Labor Estimate

(hrs) Total Annual Labor Estimate

(hrs) One

time 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 un its by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding.



### Table 7

- 8 presents estimates of labor requirements for fugitive emissions along the process chain. Consistent with the cost estimates for fugitive emissions presented in the TSD , we estimate labor associated with company

- level activities and activities at field sites. Company

level activities include one time activities such as planning the company’s fu gitive emissions program and annual requirement s such as reporting and recordkeeping. Field

- level activities include semiannual inspection and repair of leaks as proposed. It is important to note, however, that the compliance costs estimates for leak inspection were based upon an estimate of the costs

t o 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 labor

req ui rements for the f u gi tives program are likely underestimates.

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- 19 Table 7

- 7 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, 2020 and 2025

Emissions Source / Emissions Control Projected No. of Incr. Affected

Units Per Unit One

time Labor (hrs) Per Unit Ann ual Labor (hrs) Total One

Time Labor (hrs) Total Annual Labor (hrs) One

time 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 0 150
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 81 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 un its by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum d ue to independent rounding.

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- 20 Most labor required for fugitive emissions is needed at well sites in the field, which number in the thousands. Note that the labor requirements estimates increase from 2020 to 2025 as the number of sites regulated under the pro posed NSPS accumulates.

Table 7

- 9 presents labor requirement estimates for reciprocating and centrifugal

compressors. Like the estimates for completions, the per unit labor estimates were based on U.S.
EPA (2012). As relatively little labor is required for reciprocating compressors and relatively few affected centrifugal compressors are expected in the future, the estimates of both one

- time and

on

- going labor requirements for compressor requirements are minimal.

Table 7

- 8 Estimates of Labor Required to Comply with Proposed NSPS for Reciprocating and Centrifugal Compressors, 2020 and 2025

Emissions Source Emissions Control Projected No. of Incr. Affected

Units Per Unit One

time Labor Est. (hrs) Per Unit Annual Labor Est. (hrs) Total One

Time Labor Estimate

(hrs) Total Annual Labor Estimate

(hrs) One

time 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 un its by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding.



### Table 7

- 10 presents the labor requirement estimates for requirements applying to pneumatic controllers and pneumatic pumps. Note that pneumatic controllers have no one

- time or continuing labor requirements. While the controls do require labor for installation, operation, and maintenance, the required labor is less than that of the controllers that would be used absent

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- 21 the regulation (U.S. EPA, 2012) . In this instance, we assume the incremental labor requirements

are zero. Meanwhile, we are current ly unable to estimate the labor associated with pneumatic pump control activities

.

Table 7

- 9 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic Controllers and Pumps, 2020 and 2025

Emissions

Source Emissions Control Projected No. of Incr. Affected

Units Per Unit One

time Labor Est. (hrs) Per Unit Annual Labor Est. (hrs) Total One

Time Labor Estimate

(hrs) Total Annual Labor Estimate

(hrs) One

time 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 un its by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding.



### Table 7

- 10 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 fracture oil well completions and fugitive emissions detection and repair at well sites. The up

- front labor requirement to comply with the

p roposed NSPS is estimated at 73 FTEs in 2020 and in 2025

. The annual labor requirement to comply with proposed NSPS is estim ated at about 530 FTEs in 2020 and 1,400 FTEs in 2025. We note that this type of FTE estimate cannot be used to identify the specific number of people involved or whether new jobs are created for new employ e es , versus displacing jobs from other

sectors of the economy.

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- 22 Table 7

- 10 Estimates of Labor Required to Comply with Proposed NSPS, 2020 and 2025

Emissions Source Projected No. of Incrementally Affected Units (2020) Total One

Time Labor

Estimate (hours) Tot al Annual Labor Estimate (hours) One

- time FTE Annual FTE



### 2020 Hydraulically Fractured and Re

fractured Oil Well Completions 14,676 0 718,227 0 345

Fugitive Emissions 22,360 151,469 343,555 73 165
Pneumatic Controllers 210 0 0 0 0
Pneumatic Pumps 2,962 N/A N/A N/A N/A Reciprocating Compressors 67 67 67 0 0 Centrifugal Compressors 1 355 0 0 0 Reporting and Recordkeeping Requirements All 0 40,447 0 19

Total 40,276 151,891 1,102,296 73 530



### 2025 Hydraulically Fractured and Re

fractured Oil Well Completions 14,967 0 720,806 0 347
Fugitive Emissions 140,788 151,469 2,154,855 73 1,036
Pneumatic Controllers 1,260 0 0 0 0 Pneumatic Pumps 17,772 N/A N/A N/A N/A Reciprocating Compressors 402 67 402 0 0 Centrifugal Compressors 6 355 0 0 0 Reporting and Recordkeeping Requirements All 0 120,447 0 58

Total 175,195 151,891 2,996,510 73 1,441
Note: Full

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



### 7.5 References

Berman, E. and L. T. M. Bui

. 2001. “Environmental Regulation and Labor Demand: Evidence from the South Coast Air Basin .” Journal of Public Economics 79(2): 265

- 295, docket nr. EPA

- HQ

- OAR

- 2011

- 0135 at http://www.regulations.gov

Ferris, A., R. J. Shadbegian, and A. Wolverton. 2014. “The Effect of Environmental Regulation on Power S ector Employment: Phase I of the Title IV SO 2 

### Trading Program.” Journal of the Association of Environmental and Resource Economists 5 : 173

- 193.

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- 23 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 Amendments 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.

U.S. Bureau of Labor Statistics.

U.S. Census Bureau (Census).

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

. 2014

. Oil and Gas Supply Module of the National Energy Modeling System: Model Documentation 2014 . July 2014

. < http://www.eia.gov/forecasts/aeo/nems/documentation/ogsm/pdf/m063(2014). pdf > Accessed May 10, 2015

. U.S. Energy Information Administration (U.S. EIA) . 2014

. Model Documentation Report: Natural Gas Transmission and Distribution Module of the National Energy Modeling

. June 2014.

< http://www.eia.gov/forecasts/aeo/nems /documentation/ngtdm/pdf/m062(2014).pdf > Accessed May 10, 2015

. U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis: Final New Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air P ollutants for the Oil and Natural Gas Industry

. < http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf > Accessed December 19, 2014. U.S. Small Business Administration (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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Walker, R . 2011. “Environmental Regulation and Labor Reallocation." American Economic Review : 101(3):442

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

– Draft

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

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