*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

EO12866_O&GNSPS 2060 AS30 RIA_201508 10 03



# Regulatory Impact Analysis of the Proposed

Emission Standards for New and Modified Sources in the Oil and Natural Gas Sector*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

ii [This page intentionally left blank]*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

iii EPA-452/R-15-002, August 2015



### Regulatory Impact Analysis of the Pr oposed Emission Sta ndards 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 Pl anning and Standards Research Triangle Park, NC 27711*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

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 docu ment should be addressed to Alexander Macpherson, U.S. Environmental Pr otection 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, perso nnel from the U.S. EPA Office of Policy, EC/R Incorporated, and ICF Intern ational contributed data and analysis to this document.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

v TABLE OF CONTENTS

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

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

.............................................................................................................................. .......... 1-3 1.3 S UMMARY OF R ESULTS

.............................................................................................................................. .. 1-3 1.4 O RGANIZATION OF THIS R EPORT .................................................................................................................. 1-9 2 I NDUSTRY P ROFILE ............................................................................................................. 2-1
2.1 I NTRODUCTION

.............................................................................................................................. .............. 2-1 2.2 P RODUCTS OF THE C RUDE O IL AND N ATURAL G AS I NDUSTRY .................................................................... 2-2 2.2.1 Crude Oil ..................................................................................................................... ...................... 2-2 2.2.2 Natural Gas ................................................................................................................... ..................... 2-3 2.2.3 Condensates ................................................................................................................... .................... 2-3 2.2.4 Other Recovered Hydrocarbons .................................................................................................. ....... 2-3 2.2.5 Produced Water ................................................................................................................ ................. 2-4 2.3 O IL AND N ATURAL G AS P RODUCTION P ROCESSES ...................................................................................... 2-4 2.3.1 Exploration and Dr illing

...................................................................................................... .............. 2-4 2.3.2 Produc tion

.................................................................................................................... ...................... 2-5 2.3.3 Natural Gas Proce ssing

........................................................................................................ .............. 2-7 2.3.4 Natural Gas Transmissi on and Dist ributi on ..................................................................................... .. 2-8 2.4 R ESERVES AND M ARKETS ............................................................................................................................ 2 -8 2.4.1 Domestic Prove d Reserves ...................................................................................................... .......... 2-9 2.4.2 Domestic Pr oductio n............................................................................................................ ............ 2-13 2.4.3 Domestic Consumption .......................................................................................................... .......... 2-20 2.4.4 Internationa l Trade ........................................................................................................... ................ 2-25 2.4.5 Forecas ts ..................................................................................................................... ..................... 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 Eq uipment Costs ................................................................................................. ..... 2-34 2.6 F IRM C HARACTERISTICS ............................................................................................................................ 2 -36 2.6.1 Ownership ..................................................................................................................... ................... 2-37 2.6.2 Size Distribution of Firm s in Affected NAICS ................................................................................ 2 -37 2.6.3 Trends in National Empl oyment and Wages ................................................................................... 2-3 8 2.6.4 Horizontal and Ver tical Inte gration ........................................................................................... ...... 2-40 2.6.5 Firm-level In formation ........................................................................................................ ............ 2-42 2.6.6 Financial Performa nce and Co ndition............................................................................................ .. 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 .................................................................................................................... 3-5 3.4.1 Control Op tions

............................................................................................................... .................. 3-6 3.4.2 Projection of Incrementa lly Affected Fac ilities

............................................................................... .. 3-8*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

vi 3.4.3 Emissions Re ductio ns .......................................................................................................... ............ 3-10 3.4.4 Product R ecovery

.............................................................................................................. ............... 3-11 3.4.5 Engineering Comp liance Costs .................................................................................................. ...... 3-13 3.4.6 Cost-Effec tiveness ............................................................................................................ ............... 3-14 3.4.7 Comparison of Regula tory 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 ...................................................................................................................... 3-22 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 eff ects and va luation ......................................................................................... ...... 4-6 4.4 VOC AS A PM 2.5 PRECURSOR ...................................................................................................................... 4-18 4.4.1 PM 2.5 health effects and valu ation .................................................................................................. .. 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 effect s and valuation ............................................................................................ ...... 4-24 4.5.2 Ozone vegetatio n eff ects ...................................................................................................... ............ 4-25 4.5.3 Ozone climat e 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 su lfide .............................................................................................................. ................. 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 OPULATIONS ................................................................................................... 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 M odeling System .................................. 7-2 7.2.2 Inputs to National Ener gy Modeling System ..................................................................................... 7-3*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

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 .......................................... 7-7 7.2.3 Energy System Impacts ......................................................................................................... ............ 7-8 7.3 I NITIAL R EGULATORY F LEXIBILITY A NALYSIS .......................................................................................... 7-11 7.4 E MPLOYMENT I MPACT A NALYSIS .............................................................................................................. 7-11 7.4.1 Employment Impacts of Envi ronmental Regul ation ........................................................................ 7-12 7.4.2 Labor Estimates Associated with Proposed Requirements .............................................................. 7-16 7.5 R EFERENCES

.............................................................................................................................. ................ 7-23*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

viii LIST OF TABLES

Table 1-1 Summary of the Monetized Benefits, Costs, and Ne t Benefits for the Proposed Option in 2020 and 2025 (2012$) 1-7 Table 1-2 Summary of the Monetized Benefits , Costs, and Net Benefits for the Less Stringent Option in 2020 and 2025 (2 012$) .............................................................................................................. ......................................... 1-8 Table 1-3 Summary of the Monetized Benefits , Costs, and Net Benefits for the More Stringent Option in 2020 and 2025 (2 012$) .............................................................................................................. ......................................... 1-9 Table 2-1 Technically Recoverable Crude O il and Natural Ga s Resour ce ...................................................... 2-10 Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Pr oduction, Proved Reserves, and Proved Ultimate Recovery, 1 977-20 13 ........................................................................................................... .................................... 2-11 Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by St ate, 2 013 .................................................... 2-13 Table 2-4 Crude Oil Domestic Production, Wells, Well Produc tivity, a nd...................................................... 2-14 Table 2-5 Natural Gas Production and We ll 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 Natural Gas Pipe line Mileage, 2010-2013 .................................................................. 2-20 Table 2-9 Crude Oil Consumption by Sector, 199 0-2012 ................................................................................ 2-2 2 Table 2-10 Natural Gas Consumption by Sector, 1990 -2012 ............................................................................ 2-24 Table 2-11 Total Crude Oil and Petroleum Pr oducts Trade (M illion Bbl)
, ........................................................ 2-26 Table 2-12 Natural Gas Imports and Exports, 19 90-2013 ................................................................................. 2- 27 Table 2-13 Forecast of Total Successful Wells Drille d, Lower 48 Stat es, 2010-2 040 ....................................... 2-28 Table 2-14 Forecast of Crude Oil Supply, Reserves , and Wellhead Pric es, 2011-2 040 .................................... 2-29 Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and We llhead Price ..................................... 2-31 Table 2-16 SBA Size Standards and Size Distributio n of Oil and Natura l Gas Firms ....................................... 2-38 Table 2-17 Oil and Natural Gas Industry Empl oyment by NAICS, 1990-20 13 ................................................. 2-39 Table 2-18 Oil and Natural Gas Industry Average Wage s by NAICS, 1990-2013 (2012 dollars) .................... 2-40 Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total As sets), 20 12 ......................................... 2-44 Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throu ghput), 2 009 ............................................. 2-45 Table 2-21 Performance of Top 20 Gas Pipeline Compan ies (Based on Net Income), 2012 ............................ 2-46 Table 2-22 Selected Financial Items from Income Statements (Billion 2 008 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 Evalua ted at Proposal for the NSPS .............................................. 3-7 Table 3-2 Number of Incrementally Affect ed Sources for the NSPS ................................................................ 3-9 Table 3-3 Emissions Reductions from Propo sed NSPS, 2020 and 2025 ......................................................... 3-10 Table 3-4 Estimated Natural Gas Recovery (Mcf) in 2020 and 2025 .............................................................. 3-13 Table 3-5 Engineering Compliance Cost Esti mates in 2020 and 2025 ............................................................ 3-14 Table 3-6 Engineering Compliance Cost-Effect iveness Estimates in 2020 and 2025, Single Pollutant Approach 3-17 Table 3-7 Engineering Compliance Cost-Effectiveness Estimates in 2020 and 2025, Multipollutant Approach 3- 18 Table 3-8 Comparison of Regula tory Alternatives ......................................................................................... . 3-19 Table 3-10 Annualized Costs using 3 and 7 Percent Discount Rates for the Proposed NSPS in 2020 and 2025 .. 3- 21 Table 3-11 Incrementally Affected Units, Emissions Re ductions and Costs, Option 1, 2020 ........................... 3-23 Table 3-12 Incrementally Affected Units, Emissions Re ductions and Costs, Option 1, 2025 ........................... 3-24 Table 3-13 Incrementally Affected Units, Emissions Reductio ns and Costs, Selected Option 2, 2020 ............. 3-26 Table 3-14 Incrementally Affected Units, Emissions Reductio ns and Costs, Selected Option 2, 2025 ............. 3-27 Table 3-15 Incrementally Affected Units, Emissions Re ductions and Costs, Option 3, 2020 ........................... 3-28 Table 3-16 Incrementally Affected Units, Emissions Re ductions and Costs, Option 3, 2025 ........................... 3-29 Table 4-1 Climate and Human Health Effects of Emissi on Reductions from this Proposal .............................. 4-2 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 Table 4-4 Estimated Global Benefits of Methane Reductions* (in millions, 2012$) ....................................... 4-16*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

ix Table 4-5 Monetized Benefits-per-Ton Estimates for VOC base d on Previous Modeling in 2015 (2012$) .... 4-21 Table 4-6 Secondary Air Pollutant Impacts (short tons pe r year) .................................................................... 4-36 Table 4-7 Summary-level Secondary Air Pollutant Impacts Associated with Controls, across Regulatory Options (short tons per year) ................................................................................................. .................................. 4-37 Table 4-8 Summary of Emissions Changes (short tons per year, except where noted) .................................... 4-38 Table 6-1 Summary of the Monetized Benefits, Costs, and Ne t Benefits for the Proposed NSPS in 2020 and 2025 6-1 Table 6-2 Summary of the Monetized Benefits, Costs, and Ne t Benefits for the Less Stringent Option for the NSPS in 2020 an d 2025 (2 012$) ................................................................................................. .............................. 6-2 Table 6-3 Summary of the Monetized Benefits, Costs, and Ne t Benefits for the More Stringent Option for the NSPS in 2020 an d 2025 (2 012$) ................................................................................................. .............................. 6-3 Table 6-4 Summary of Emissions Changes across Option for the NSPS in 2020 and 2025 (short tons per year, unless otherwis e note d) ....................................................................................................... ...................................... 6-4 Table 7-1 Per Well Costs for Environmental Contro ls Entered into NEMS (2012$) ........................................ 7-7 Table 7-2 Successful Oil and Gas Wells Drilled (Onshore, Lower 48 States ) ................................................... 7-9 Table 7-3 Annual Domestic Natural Gas and Crude Oil Production (Onshore, Lo wer 48 States) .................... 7-9 Table 7-4 Average Natural Gas and Crude Oil Wellhead Pr ice (Onshore, Lower 48 States, 2012$) .............. 7-10 Table 7-5 Net Imports of Natura l Gas and Cr ude Oil ...................................................................................... 7-11 Table 7-6 Estimates of Labor Required to Comply with Pr oposed NSPS for Hydraulically Fractured Oil Well Completions, 20 20 and 2025 .................................................................................................... ............................... 7-19 Table 7-7 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, 2020 and 2025 7-20 Table 7-8 Estimates of Labor Required to Comply with Proposed NSPS for Reciprocating and Centrifugal Compressors, 2 020 and 2025 .................................................................................................... ............................... 7-21 Table 7-9 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic Controllers and Pumps, 2020 and 2025 7-22 Table 7-10 Estimates of Labor Required to Comply with Proposed NSPS, 2020 and 2025 .............................. 7-23*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

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 Produc tion, 19 90-2013............................................................... .... 2-12 Figure 2-2 A) Total Producing Crude Oil Wells and Average Well Productivity, 1990-2011. B) Total Producing Natural Gas Wells and Average Well Productivity, 1990-2013. ................................................................... .......... 2-16 Figure 2-3 U.S. Produced Water Volume by Management Prac tice, 200 7 ....................................................... 2-19 Figure 2-4 Crude Oil Consumption by Sector (Percen t of Total Consumpt ion), 1990 -2011 ............................ 2-23 Figure 2-5 Forecast of Domestic Crude Oil Pro duction and Net Impor ts, 2010-204 0 ...................................... 2-30 Figure 2-6 Costs of Crude Oil and Natural Ga s Wells Drilled, 1981-200 8 ....................................................... 2-32 Figure 2-7 Finding Costs for FRS Comp anies, 1981 -2009 ............................................................................... 2-33 Figure 2-8 Direct Oil and Natural Gas Lifting Costs for FR S Companies, 1981-2009 (3-year Running Average) 2-34 Figure 2-9 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976 dollars), 1976-2 009

........................................................................................................... ....................................... 2-35 Figure 2-10 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas Price, 1976-2009 2-36 Figure 4-1 Path from GHG Emissions to Monetized Da mages ......................................................................... 4-11 Figure 4-2 2005 NATA Model Estimated Census Tract Carcinogenic Risk from HAP Exposure from All Outdoor Sources based on the 20 05 National Toxi cs Inventory.................................................................... .......... 4-28 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 ............................................................... ........ 4-29*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-1 1 EXECUTIVE SUMMARY

1.1 Background

The action analyzed in this regulatory imp act analysis (RIA) proposes to amend the new source performance standards (NSPS) for the o il and natural gas sour ce category by setting standards for both methane and volatile orga nic compounds (VOC) for certain equipment, processes and activities ac ross this source category.

The Environmental Protection Agency (EPA ) is including requirements for methane emissions in this proposal becau se methane is a greenhouse gas (GHG), and the oil and natural gas category is currently one of the country's largest emitters of methane. In 2009, the EPA found that by causing or contributing to climat e change, GHGs endanger both the public health and the public welfare of curre nt 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 natu ral gas source category. Specifically, we are proposing both methane and VOC standards for se veral emission sources not currently covered by the NSPS (i.e., hydraulically fractured oil well completions, fugitive emissions from well sites and compressor stations, pneumatic pumps). In addition, we are proposing methane standards for certain emission sources that are currently regul ated 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 ar e used across the source category, the current NSPS regulates only a subset of these e quipment (pneumatic c ontrollers, centrifugal compressors, reciprocating compressors). The proposed amendents would establish methane standards for these equipment across the source category and extend the current VOC standards to the remaining unregulated equipment. Last ly, amendments to the current NSPS are being proposed that improve several aspects of the cu rrent standards related to implementation. These improvements result from reconsideration of certain issues raised in petiti ons for reconsideration that were received by the Administrator on the August 16, 2012, final NSPS for the oil and*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-2 natural gas sector and related amendments. Ex cept for these implementation improvements and the setting of standards for methane, these am endments do not change the requirements for operations already covered by the current standards.

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

This analysis estimates regulatory imp acts for the analysis years of 2020 and 2025 , which spans a period of six years . The analysis 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 illu strate how new and modified s ources accumulate over time under the proposed NSPS. The regulatory impact estimate s for 2025 include sources newly affected in
2025 as well as the accumulation of affected sour ces from 2020 to 2024 that are also assumed to be in continued operation in 2025, thus incurring compliance cost s and emissions reductions in
2025.

Several emission controls for the NSPS, such as reduced emissions completions (RECs) of hydraulically-fractured oil wells, capture me thane and VOC emissions that otherwise would be vented to the atmosphere. The averted methan e emissions can be directed into natural gas production streams and sold. The revenues derived from natural gas recovery are expected to offset a portion of the engineering costs of im plementing the NSPS. In this RIA, we present results that include the additional product recovery and the revenues we expect producers to gain from the additional product recovery.

1 The analysis in this draft RIA constitutes the economic assessment required by CAA section 317. In the EPA’s judgment, the assessment is as extensive as practicable taking into account the EPA’s time, resources, and other duties and authorities.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-3 The baseline used for the impacts analysis of our NSPS takes into account emissions reductions conducted pursuant to state regulations covering th e relevant operations. More
detailed discussion on the derivation of the baselin e is presented in Section 3 of this RIA.

1.2 Market Failure

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

Greenhouse Gas (GHG) and VOC emissions impos e costs on society, such as negative climate, health, and welfare impacts that are not reflected in the market price of the goods produced through the polluting process. For this regulatory action the goods produced, processed, transported, or stored are crude oi l, natural gas, and ot her hydrocarbon products.
These social costs associated w ith the climate, health, and welf are impacts are referred to as negative externalities. If an o il and natural gas firm pollutes the atmosphere while extracting, processing, transporting, or storing the commodities , this cost will be borne not by the polluting firm but by society as a whole. The market price of the products will fail to incorporate the full opportunity cost to society of pr oducing the products. All else equa l, given this externality, the quantity of oil and natural gas produc ed in a free market will not be at the socially optimal level. More oil and natural gas will be produced th an would occur if the power producers had to account for the full opportunity cost of produc tion including the negative externality. Consequently, absent a regulation on emissions, the marginal social cost of the last units of oil and natural gas produced will exceed its marginal 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, including 180,000 tons of methan e, 120,000 tons of VOCs and 400 tons of hazardous air pollutants (HAP) in 2020, incr easing to 400,000 tons of methane, 180,000*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-4 tons of VOCs, and 2,500 tons of HAP prevented in 2025. 2 The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 4.0 million me tric tons in 2020 and 9.0 million metric tons in 2025.

 Benefits Analysis: The monetized benefits in this RIA include those from reducing methane emissions, which are valued using the social cost of methane (SC-CH 4 ). 3 The EPA estimates that, in 2020, the proposal wi ll 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 $210 million in 2020. In 2025, the EPA estimates monetized climate benefits of $250 million to approximate ly $1.4 billion; the mean SC-CH4 at the 3% discount rate results in an estimate of about $550 million in 2025 4 While we expect that the avoided emissions will result in improvements in ambient air quality and reductions in health effects associated w ith exposure to HAP, ozone, and particulate matter (PM), we have determined that quant ification of those benefits cannot be accomplished for this rule. 5 This is not to imply that there are no health benefits anticipated from the proposed ru le; rather, it is a reflection of the difficulties in modeling the direct and indirect impact s of the reductions in emissions for this industrial sector with the data currently available. In addi tion to health improvements, there will be improvements in visibility effects, ecosystem effects, as well as additional natural gas recovery. The specific contro l 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 $180 million in 2020 and $330 million in 2025. The estimate of total annualized engineering costs of the proposed NSPS is $200 million in 2020 and $500 million in 2025 when using a 7 percent discount rate. When estimated revenues from additional natural gas are included, the annualized e ngineering costs of the proposed NSPS are estimated to be $170 million in 2020 and $420 million in 2025, assuming a wellhead natural gas price of $4/thousa nd cubic feet (Mcf). The estimated engineering compliance costs that include the product recovery are sens itive to the assumption about the price of the recovered product. There is also geographi c variability in wellhead prices, which can also influence estimated engineering costs. For example, $1/Mcf change in the wellhead price causes a change in estimated engineer ing compliance costs of about $8.2 million in 2020 and $19 million in 2025, given EPA estimat es that about 8.2 million Mcf in 2020

2 Estimates are presented in short tons. 3 The social cost of methane (SC-CH 4 ) is the monetary value of impacts a ssociated with a marginal change in methane emissions in a given year.
4 The range of estimates reflects four SC-CH 4 estimates are associated with diffe rent discount rates (model average at 2.5, 3 and 5 percent; 95 th percentile at 3 percent). See Section 4.3 for a complete discussion. 5 Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the effect that those emissi ons 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, the benefit-per-ton estimates for VOC emission reductions in that study are derived from total VOC emissions across a ll sectors. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 and the highly localized nature of air quality responses associated with VOC reductions, thes e 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.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-5 and 19 million Mcf of natural gas will be recovered by implementing the NSPS. When using a 3 percent discount rate, the estimate of total annualized engineering costs of the proposed NSPS is $200 million in 2020 a nd $4900 million in 2025, or $170 million in 2020 and $420 million in 2025, when estimated re venues from additional natural gas are included. 6

 Energy System Impacts Analysis: The EPA used the Nation al Energy Modeling System (NEMS) to estimate the impacts of the propos ed 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 ar e 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). 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. Meanwh ile, 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. M eanwhile, net imports of natural gas are estimated to decline sligh tly 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 pe r day (or 0.02 percent) in 2025.

 Small Entity Analyses: [ Placeholder for summary of In itial Regulatory Flexibility Analysis]

 Employment Impacts Analysis: EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipmen t and control activities, as well as the labor associated with new reporting and reco rdkeeping requirements. We estimated onetime and continual, annual labor requiremen ts by estimating hours of labor required for compliance and converting this number to fu ll-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks). The one-time labor requirement to comply with the proposed NSPS is estimated at about 70 FTEs in 2020 and in 2025. The annual labor requirement to comply with pr oposed 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 invo lved or whether new jobs are created for new employees, versus displacing jobs from other sectors of the economy.

In the RIA, we examine three broad regul atory 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 stri ngent regulatory option, and Table 6-4 presents summary results for the more stringent regulatory option.

6 The choice of discount rate has a small effect on nationw ide 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, compressors, and pneumatic controllers are sensitive to interest rate, but these constitute a relatively small part of the total compliance cost estimates for the proposal.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-6*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-7 Table 1-1 Summary of the Monetized Bene fits, Costs, and Net Benefits for the Proposed Option in 2020 and 2025 (2012$)
2020 2025
Total Monetized Benefits 1 $210 million $550 million
Total Costs 2 $170 million $420 million Net Benefits 3 $35 million $120 million

Non-monetized Benefits Non-monetized climate benefits Health effects of PM 2.5 and ozone exposure from 120,000 tons of VOC reduced Non-monetized climate benefits Health effects of PM 2.5 and ozone exposure from 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 exposure from 2,500 tons of HAP reduced 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 bene fits 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 an nualized 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 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.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-8 Table 1-2 Summary of the Monetized Benefi ts, Costs, and Net Benefits for the Less Stringent Option in 2020 and 2025 (2012$)
2020 2025
Total Monetized Benefits 1 $ 200 190 million $4 6 5 0 million Total Costs 2 $ 150 80 million $ 2 32 4 0 million Net Benefits 3 $ 42 110 million $ 15 21 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 1 7 6 0,000 tons of VOC reduced Health effects of HAP exposure from 31 29 0 tons of HAP reduced Health effects of HAP exposure from 1, 9 8 00 tons of HAP reduced Health effects of ozone exposure from 170,000 tons of methane Health effects of ozone exposure from 3 4 3 0,000 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, an d 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 bene fits calculated using all four SC-CH4 estimates; the additional benefit estimates range from $8 8 7 million to $520 million in 2020 and $ 210 220 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 8 million metric tons in 2020 and 7. 4 7 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.
2 The engineering compliance costs are an nualized 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 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.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

1-9 Table 1-3 Summary of the Monetized Benefi ts, 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 $680 million Net Benefits 3 $7.6 million -$35 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 510 tons of HAP reduced Health effects of HAP exposure from 3,200 tons of HAP reduced Health effects of ozone exposure from 190,000 tons of methane Health effects of ozone exposure from 470,000 tons of methane Visibility impairment Visibility impairment Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH 4 ) (model average at 2.5 percent discount rate, 3 percent, an d 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-CH 4 estimates; the additional benefit estimates range from $99 million to $590 million in 2020 and $300 million to $1,700 million in 2025 for this more stringent option, as shown in Section 4.3. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 4.2 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticip ated to have minor secondary disbenefits.
2 The engineering compliance costs are an nualized 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 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 report details the me thodology and the results of the RIA. Section 2 presents the industry profile of the oil and natural gas industry. Section 3 describes the emissions and engineering cost analysis. Section 4 presen ts the benefits analys is. Section 5 presents statutory and executive order anal yses. Section 6 presents a comparison of benefits and costs. Section 7 presents energy system impact, employ ment impact, and small entity impact analyses.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-1 2 INDUSTRY PROFILE

2.1 Introduction
The oil and natural gas indus try includes the following five segments: drilling and extraction, processing, transportation, refining, and marketing. The Oil and Natural Gas NSPS require controls for the oil and natural gas produ cts and processes of th e drilling and extraction of crude oil and natural gas, natural gas pro cessing, and natural gas tr ansportation segments.

Most crude oil and natural gas production facilities ar e classified under NAICS 211:
Crude Petroleum and Natural Gas Extraction (211111) and Natural Gas Liquid Extraction (211112). The drilling of oil and natural gas we lls is included in NAICS 213111. Most natural gas transmission and storage facilities are classified under NAICS 486210—Pipeline Transportation of Natural Gas. While ot her NAICS (221210—Natural Gas Distribution, 486110—Pipeline Transportation of Crude O il, and 541360—Geophysical Surveying and Mapping Services) are often included in the oil and natural gas sect or, these are not discussed in detail in the Industry Profile because they ar e not directly affected by the proposed NSPS.

The outputs of the oil and natural gas industr y are inputs for larger production processes of gas, energy, and petroleum products. As of 2013, the Energy Information Administration (EIA) estimates that about 490,000 producing natural gas wells operated in the U.S. The latest
available information from EI A indicates there were about 360,000 producing oil wells in the U.S. as of 2009. Domestic dry natural gas pr oduction was 24.3 trillion cubic feet (tcf) in 2013, the highest annual production level in U.S. history. The leading five natural gas producing states are Texas, Pennsylvania, Louisiana, Oklahoma, and Wyoming. Domestic cr ude oil production in 2013 was 2,716 million barrels (bbl), the highest a nnual level in the U.S. since 1991. The leading five crude oil producing states are Texas, North Dakota, Cali fornia, Alaska, and Oklahoma.

The Industry Profile provides a brief introduc tion to the components of the oil and natural gas industry that are relevant to the proposed NSPS. The purpose is to give the reader a general understanding of the geophysical, engineering, and economic aspect s of the industry that are addressed in subsequent economic analysis in th is RIA. The Industry Profile relies heavily on background material from the U.S. EPA’s “Econo mic Analysis of Air Pollution Regulations: Oil
and Natural Gas Production” (1996), the U.S. EPA’s “Sector No tebook Project: Profile of the Oil*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-2 and Gas Extraction Industry” (2000), and the U.S. EPA’s “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” (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 natu ral gas and reservoir characteristi cs are likely to be different from that of any other reservoir.

2.2.1 Crude Oil
Crude oil can be broadly classified as pa raffinic, naphthenic (or asphalt-based), or intermediate. Generally, paraffinic crudes are used in the manufactur e of lube oils and kerosene. Paraffinic crudes have a high con centration of straight chain hydrocarbons and are relatively low in sulfur compounds. Naphthenic crudes are genera lly used in the manufacture of gasolines and asphalt and have a high concentr ation 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 above categories.

Another classification measur e of crude oil and other hydr ocarbons is by API gravity. API gravity is a weight per unit volume meas ure of a hydrocarbon liquid as determined by a method recommended by the American Petroleum Institute (API). A heavy or paraffinic crude oil is typically one w ith API gravity of 20 o or less, while a light or naphthenic crude oil, which typically flows freely at atmosphe ric conditions, usually has API gr avity in the range of the high
30's to the low 40's.

Crude oils recovered in the production phase ma y be referred to as live crudes. Live
crudes contain entrained or dissolv ed gases which may be released during processing or storage. Dead crudes are those that have gone through va rious separation and storage phases and contain little, if any, entrained or dissolved gases.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-3 2.2.2 Natural Gas
Natural gas is a mixture of hydrocarbons a nd varying quantities of non-hydrocarbons that exists in a gaseous phase or in solution with crude oil or other hydrocar bon liquids in natural underground reservoirs. Natural gas may contai n 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 from a reservoi r that contains condens able hydrocarbons. Dry gas is either natural gas whose water content has been reduced through dehydration or natural gas that contains little or no recoverable liquid hydrocarbons.

Natural gas streams that contain threshold concentrations of H 2 S are classified as sour gases. Those with threshold concentrations of CO 2 are classified as acid gases. The process by
which these two contaminants ar e removed from the na tural gas stream is called sweetening. The most common sweetening method is amin e treating. Sour gas contains a H 2 S concentration of greater than 0.25 grain per 100 standard c ubic feet, along with the presence of CO 2
. Concentrations of H 2 S and CO 2 , along with organic sulfur co mpounds, vary widely among sour gases. A majority of total ons hore natural gas production and n early 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 we llbore or the production process. C ondensates, including volatile oils, typically have an API gravity of 40 o or more. In addition, condens ates may include hydrocarbon liquids recovered from gaseous streams from various oil and na tural gas production or natural gas transmission and storag e processes and operations.

2.2.4 Other Recovered Hydrocarbons
Various hydrocarbons may be recovered th rough the processing of the extracted hydrocarbon streams. These hydrocarbons include mixed natural gas liquids (NGL), natural gasoline, propane, butane, and liquefied petroleum gas (LPG).*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-4 2.2.5 Produced Water

Produced water is the water recovered fr om a production well. Produced water is separated from the extracted hydrocarbon stre ams in various production processes and operations.

2.3 Oil and Natural Gas Production Processes

2.3.1 Exploration and Drilling
Exploration involves the search for rock form ations associated with oil or natural gas deposits and involves geophysical prospecting and/or explorator y drilling. We ll development occurs after exploration has located an economically recove rable field and involves the construction of one or more wells from the begi nning (called spudding) to either abandonment if no hydrocarbons are found or to well completion if hydrocarbons are found in sufficient quantities.

After the site of a well has been located, drilling commences. A well bore is created by using a rotary drill to drill into the ground. As the well bore gets deep er sections of drill pipe are added. A mix of fluids called drilling mud is releas ed down into the drill pipe then up the walls of the well bore, which removes drill cuttings by taking them to the surfac e. The weight of the mud prevents high-pressure rese rvoir fluids from pushing thei r way out (“blowing out”). The well bore is cased in with telescoping steel pipi ng during drilling to a void 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 avai lable since the 1950s. Horizontal drilling
facilitates the construction of hor izontal wells by allowing for the well bore to run horizontally underground, increasing the surface area of contac t between the reservoir and the well bore so that more oil or natural gas can move into the we ll. Horizontal wells are particularly useful in unconventional gas extraction where th e gas is not concentrated in a reservoir. Recent advances have made it possible to steer th e drill in different directions (directional drilling) from the*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-5 surface without stopping the drill to switch directions and allowing for a more controlled and precise drilling trajectory.

Hydraulic fracturing (also refe rred to as “fracking”) has be en performed since the 1940s (U.S. DOE, 2013). Hydraulic fractu ring involves pumping fluids into the well under very high pressures in order to fracture th e formation containing the resour ce. Proppant is a mix of sand and other materials that is pumped down to hold the fractures open to secure gas flow from the formation (U.S. EPA, 2004).

2.3.2 Production
Production is the process of extracting the hydrocarbons and separating the mixture of liquid hydrocarbons, gas, water, and solids, remo ving the constituents that are non-saleable, and selling the liquid hydrocarbons and gas. The ma jor activities of crude oil and natural gas production are bringing the fluid to the surface, separating the liquid and gas components, and removing impurities.

Oil and natural gas are found in the por es of rocks and sand (Hyne, 2001). In a conventional source, the oil and natural gas have been pushed out of these pores by water and moved until an impermeable surface had been reac hed. Because the oil and natural gas can travel no further, the liquids and gases accumulate in a reservoir. Where oil a nd gas are associated, a gas cap forms above the oil. Natural gas is extrac ted from a well either because it is associated with oil in an oil well or from a pure natural ga s reservoir. Once a well has been drilled to reach the reservoir, the oil and gas can be extracted in different ways depe nding 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 increase of gas over oil occurs because natural gas usua lly 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 of ten handle crude oil and natural gas from more than one well (Hyne, 2001).*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-6 Well pressure is required to move the resour ce up from the well to the surface. During primary extraction, pressure from the well itself drives the resource out of the well directly. Well pressure depletes during this process. Typica lly, about 30 to 35 percent of the resource in the reservoir is extracted this way (Hyne, 2001) . The amount extracted depends on the specific well characteristics (such as perm eability and oil viscosity). Lacking enough pressure for the resource to surface, gas or water is injected in to the well to increase th e well pressure and force the resource out ( secondary or improved oil recovery). Finally, in tertiary extraction or enhanced recovery, gas, chemicals or steam are injected into the well. This can result in recovering up to 60 percent of the original amount of oil in th e reservoir (Hyne, 2001).

In contrast to conventional sources, unconventional oil and gas are trapped in rock or sand or, in the case of oil, are found in rock as a chemical substance that requires a further chemical transformation to become oil (U.S. DOE , 2013). Therefore, the resource does not move
into a reservoir as in the case with a conventional source. Mining, induced pressure, or heat is required to release the resource. The specific t ype of extraction method needed depends on the type of formation where the resource is loca ted. Unconventional oil and natural gas resource types relevant for this rule include:

 Shale Oil and Natural Gas: Shale natural gas comes from sediments of clay mixed with organic matter. These sediments form low perm eability shale rock form ations that do not allow the gas to move. To release the gas, the rock must be fragmented, making the extraction process more complex than it is for conventional gas extraction. Shale gas can be extracted by drilling either vertically or horizontally, and breaking the rock using hydraulic fracturing (U.S. DOE, 2013).

 Tight Sands Natural Gas: Reservoirs are composed of low-porosity sandstones and carbonate into which natural gas has migrat ed from other sources. Extraction of the natural gas from tight gas reservoirs is of ten 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 be d due to the activity of microbes in
the coal or from alterations of the coal th rough temperature changes. Horizontal drilling*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-7 is used but given that coalbed methane re servoirs are frequently associated with underground water reservoirs, hydraulic fractu ring is often restricted (Andrews, 2009).

2.3.3 Natural Gas Processing
Natural gas conditioning is the process of removing impurities from the gas stream so that it is of sufficient quality to pass through 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 se nt directly to the pipeline. As the natural gas is separated from the liquid components, it may contain impurities th at pose potential hazards or other problems.

The most significant impurity is H 2 S, which may or may not be contained in natural gas.
H 2 S is toxic (and potentially fatal at certain concentrations) to huma ns and is corrosive for pipes.
It is therefore desirable to remove H 2 S as soon as possible in th e conditioning process.

Another concern is that posed by water vapor. At high pre ssures, water can react with components in the gas to form gas hydrates, whic h 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 hydr ocarbons that are liquids at surface temperature and pressure (benzene, toluene, ethylbenzene, and xylene, or BTEX) are removed and processed separately.

Dehydration removes water from the gas st ream. Three main approaches toward dehydration are the use of a liqui d 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 regene ration. The glycol can then be reused. Solid desiccants, often materials called molecular siev es, 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, pa rticularly for gas extracted from deep, hot wells, simply cooling the gas to a temperature below the condensati on point of water can remove enough water to transport the gas. Of the three approaches me ntioned above, glycol de hydration is the most common when processing at or near the well.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-8 Sweetening is the procedure in which H 2 S and sometimes CO 2 are removed from the gas
stream. The most common method is amine treatment. In this process, the gas stream is exposed to an amine solution, which will react with the H 2 S and separate them from the natural gas. The contaminant gas solution is then heated, thereby separating the ga ses and regenerating the amine. The sulfur gas may be disposed of by flaring, in cinerating, 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 Transmission and Distribution
After processing, natural gas enters a netw ork of compressor stations, high-pressure transmission pipelines, and often-underground storag e sites. Compressor stat ions are any facility which supplies energy to move natural gas at increas ed pressure in transmi ssion pipelines or into underground storage. Typically, co mpressor stations are located at intervals along a transmission pipeline to maintain desired pressure for natural gas transport. These stations will use either large internal combustion engines or gas turbines as prime movers to provide the necessary horsepower to maintain system pressure. Undergr ound storage facilities are subsurface facilities utilized for storing natural gas which has been transferred from its original location for the primary purpose of load balancing, which is the process of equaliz ing the receipt and delivery of natural gas. Processes and opera tions that may be located at underground storage facilities include compression and dehydration.

2.4 Reserves and Markets
Crude oil and natural gas have historically se rved two separate and distinct markets. Oil
is an international co mmodity, transported and consumed throughout the world. Natural gas, on the other hand, has historically been consumed close to where it is produced. However, as pipeline infrastructure and LNG trade expand, natural gas is increas ingly a national and international commodity. The following subsections provide historical and forecast data on the U.S. reserves, production, consumption, and fo reign trade of crude oil and natural gas.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-9 2.4.1 Domestic Proved Reserves
Table 2-1 shows crude oil and dry natural gas proved reserves, unproved reserves, and total technically recoverable res ources as of 2009. According to EIA 7 , these concepts are defined

as:

 Proved reserves: estimated quantities of energy sources that analysis of geologic and engineering data demonstrates with r easonable certainty are recoverable under existing economic and operating conditions.

 Unproved resources: additional volumes estimated to be technically recoverable without consideration of economics or ope rating conditions, based on the application of current technology.

 Total technically 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-g rade natural gas. The dry natural gas volumes reported in Table 2-1 reflect th e amount of gas remaining afte r 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 pr oved reserves and unproved reserves equal the total technically recoverable re sources. As seen in Table 2- 1, as of 2009, proved domestic crude
oil reserves accounted for about 10 percent of the totally tec hnically recoverable crude oil

resources.

7 U.S. Department of Energy, Energy Information Administration, Glossary of Terms <http://www.eia.doe.gov/g lossary/index.cfm?id=P> Accessed 12/21/2010.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-10 Table 2-1 Technically Recoverable Crude Oil and Natural Gas Resource Estimates, 2009

Region Proved Reserves Unproved Resources Total Technically Recoverable

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

Dry Natural Gas (trillion cubic feet) Conventionally Reservoired Fields 105.5 904.0 1,009.5 48 States Onshore 1/ 81.4 369.7 451.1 48 States Offshore 15.0 262.6 277.6 Alaska 9.1 271.7 280.8
Tight Gas, Shale Gas and Coalbed Methane 167.1 1,026.7 1,193.8 Total U.S. 272.5 1,930.7 2,203.3

Source: U.S. Energy Information Administration, Annual Energy Review 2012. Totals may not sum due to independent rounding. 1/

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

Proved natural gas reserves accoun ted for about 12 percent of the 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 2009 were es timated at 272.5 tcf, wet natural gas reserves were estimated at 283.9 tcf. Of the 283.9 tcf, 250.5 tcf (about 88 percent) is considered to be wet non-associated natural gas, while 33.3 tcf (about 12 pe rcent) is considered to be wet associated-dissolved natural gas. Associ ated-dissolved natural gas, according to EIA, is natural gas which occurs in crude oil reservoirs as free natural gas or in solution with crude oil.

Table 2-2 and Figure 2-1 show trends in crude oil and natural gas production and reserves from 1990 to 2013. In Table 2-2, proved ultimate recovery equals th e sum of cumulative production and proved reserves. While crude oil a nd natural gas are nonre newable resources, the table shows that proved ultimate recovery ri ses over time as new discoveries become*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-11 economically accessible. Reserves growth and dec line is also partly a function of exploration activities, which are correlated with oil and natura l gas prices. For example, when oil prices are high there is more of an incentiv e to use secondary and tertiary recovery, as well as to develop
unconventional sources.

Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Production, Proved Reserves, and Proved Ultimate Recovery, 1977-2013

Crude Oil and Lease Cond ensate (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 pr oved reserves has declined over time for both crude oil and natural gas, from above 11 percent in the early 1990s to 8 to 10 percent over the*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-12 period from 2006 to 2013 for crude oil and from above 11 percent during the 1990s to between 7 and 9 percent from 2006 to 2013 for natural gas.

Figure 2-1 A) Domestic Crude Oil Proved Reserves 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 of crude oil and natural gas by state or producing area as of 2013. Five areas currently acc ount for 81 percent of the U.S. total proved reserves of crude oil, led by Texas and followed by North Dakota, U.S. Federal Offshore, Alaska, and California. The t op five states (Texas, Pennsylvania, Wyoming, Oklahoma, and West Virginia) account for about 65 percent of the U.S. total pr oved reserves of natural gas. 0 50,000 100,000 150,000 200,000 250,000 300,000Crude Oil (million bbl) A). Crude Oil

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

Cumulative Production Proved Reserves*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-13 Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by State, 2013

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

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

2.4.2 Domestic Production
Domestic oil production was in a state of d ecline 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 2013 at 2,716 million bbl per year.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-14 Table 2-4 Crude Oil Domestic Producti on, 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 aver age price at the lease or wellhead at which domestic crude is purchased. Prices adjusted using GDP Implicit Price Deflator.

Average well productivity has also generally de creased since 1990 (Table 2-4 and Figure 2-2). These production and productivity d ecreases are in spite of the f act that average first purchase prices have shown a gene rally increasing trend.

Annual production of natural gas from natura l gas wells has increased more than 8000 bcf from the 1990 to 2013 (Table 2-5). The numbe r of wells producing natural gas has nearly doubled between 1990 and 2011 (Figure 2-2). Wh ile the number of producing wells has increased overall, average well productivity has declined, despite improvements in exploration and gas well stimulation technologies.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-15 Table 2-5 Natural Gas Production and Well Productivity, 1990-2013
Natural Gas Gross Withdrawals (Billion Cubic Feet) Natural Gas Well Productivity

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

Feet/Year) 1990 21,523 17,810 269,790 66.0 1991 21,750 17,698 276,987 63.9 1992 22,132 17,840 276,014 64.6 1993 22,726 18,095 282,152 64.1 1994 23,581 18,821 291,773 64.5 1995 23,744 18,599 298,541 62.3 1996 24,114 18,854 301,811 62.5 1997 24,213 18,902 310,971 60.8 1998 24,108 19,024 316,929 60.0 1999 23,823 18,832 302,421 62.3 2000 24,174 19,182 341,678 56.1 2001 24,501 19,616 373,304 52.5 2002 23,941 18,928 387,772 48.8 2003 24,119 19,099 393,327 48.6 2004 23,970 18,591 406,147 45.8 2005 23,457 18,051 425,887 42.4 2006 23,535 18,504 440,516 42.0 2007 24,664 19,266 452,945 42.5 2008 25,636 20,159 476,652 42.3 2009 26,057 20,624 493,100 41.8 2010 26,816 21,316 487,627 43.7 2011 28,479 22,902 514,637 44.5 2012 29,542 24,033 482,822 49.8 2013 30,005 24,334 487,286 49.9*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-16 Figure 2-2 A) Total Producing Crude Oil Wells and Average Well Productivity, 1990- 2011. B) Total Producing Natural Gas Well s and Average Well Productivity, 1990-2013.
Domestic exploration and development for o il has continued during the last two decades. From 2002 to 2010, crude oil well drilling show ed significant increases, although the 1992-2004 period showed relatively low levels of crude dr illing activity compared to periods before and after (Table 2-6). The drop in 2009 showed a departure from th is trend, likely due to the recession experienced in the U.S.

Meanwhile, natural gas drilli ng has increased significantl y during the 1990-2010 period. Like crude oil drilling, 2009 and 2010 saw a relati vely low level of natu ral gas drillings. The success rate of wells (producing we lls versus dry wells) has also increased gradually over time from 75 percent in 1990, to 86 percent in 2000, to a peak of 90 percent in 2009 (Table 2-6). The increasing success rate reflects improvements in 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*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-17 improvements in well drilling and completion. Sim ilarly, well average depth has also increased by during this period (Table 2-6).
Table 2-6 Crude Oil and Natural Gas Exploratory and Development Wells and Average Depth, 1990-2010

Wells Drilled

Year Crude Oil Natural Gas Dry Holes Total Successful Wells (%) Average Depth (ft) 1990 12,445 11,126 8,496 32,067 75 4,881 1991 12,035 9,611 7,882 29,528 75 4,920 1992 9,019 8,305 6,284 23,608 75 5,202 1993 8,764 10,174 6,513 25,451 75 5,442 1994 7,001 9,739 5,515 22,255 77 5,795 1995 7,827 8,454 5,319 21,600 77 5,636 1996 8,760 9,539 5,587 23,886 79 5,617 1997 10,445 11,186 5,955 27,586 79 5,691 1998 6,979 11,127 4,805 22,911 80 5,755 1999 4,314 11,121 3,504 18,939 83 5,090 2000 8,090 17,051 4,146 29,287 86 4,961 2001 8,888 22,072 4,598 35,558 87 5,087 2002 6,775 17,342 3,754 27,871 87 5,232 2003 8,129 20,722 3,982 32,833 88 5,426 2004 8,789 24,186 4,082 37,057 89 5,547 2005 10,779 28,590 4,653 44,022 89 5,508 2006 13,385 32,838 5,206 51,429 90 5,613 2007 13,371 32,719 4,981 51,071 90 6,064 2008 16,633 32,246 5,423 54,302 90 5,964 2009* 11,190 18,088 3,525 32,803 90 6,202 2010* 15,753 16,696 4,162 36,611 89 6,108 Source: U.S. Energy Information Administration * Average Depth values for 2009-2010 are estimates. Produced water is an important byproduct of the oil and natural gas industry, as management, including reuse and recycling, of produced water can be costly and challenging. Texas, California, Wyoming, Oklahoma, and Kans as were the top five states in terms of produced water volumes in 2007 (Table 2-7). Th ese estimates do not include estimates of flowback water from hydraulic fracturing activities (ANL 2009).*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-18 Table 2-7 U.S. Onshore and Offshore Oil, Gas, and Produced Water Generation, 2007

State Crude Oil (1000 bbl) Total Gas (bcf) Produced Water (1000 bbl) Total Oil and Natural Gas (1000 bbls oil

equivalent) Barrels Produced Water per Barrel

Oil Equivalent Alabama 5,028 285 119,004 55,758 2.13 Alaska 263,595 3,498 801,336 886,239 0.90 Arizona 43 1 68 221 0.31 Arkansas 6,103 272 166,011 54,519 3.05 California 244,000 312 2,552,194 299,536 8.52 Colorado 2,375 1,288 383,846 231,639 1.66 Florida 2,078 2 50,296 2,434 20.66 Illinois 3,202 no data 136,872 3,202 42.75 Indiana 1,727 4 40,200 2,439 16.48 Kansas 36,612 371 1,244,329 102,650 12.12 Kentucky 3,572 95 24,607 20,482 1.20 Louisiana 52,495 1,382 1,149,643 298,491 3.85 Michigan 5,180 168 114,580 35,084 3.27 Mississippi 20,027 97 330,730 37,293 8.87 Missouri 80 no data 1,613 80 20.16 Montana 34,749 95 182,266 51,659 3.53 Nebraska 2,335 1 49,312 2,513 19.62 Nevada 408 0 6,785 408 16.63 New Mexico 59,138 1,526 665,685 330,766 2.01 New York 378 55 649 10,168 0.06 North Dakota 44,543 71 134,991 57,181 2.36 Ohio 5,422 86 6,940 20,730 0.33 Oklahoma 60,760 1,643 2,195,180 353,214 6.21 Pennsylvania 1,537 172 3,912 32,153 0.12 South Dakota 1,665 12 4,186 3,801 1.10 Tennessee 350 1 2,263 528 4.29 Texas 342,087 6,878 7,376,913 1,566,371 4.71 Utah 19,520 385 148,579 88,050 1.69 Virginia 19 112 1,562 19,955 0.08 West Virginia 679 225 8,337 40,729 0.20 Wyoming 54,052 2,253 2,355,671 455,086 5.18 State Total 1,273,759 21,290 20,258,560 5,063,379 4.00 Federal Offshore 467,180 2,787 587,353 963,266 0.61 Tribal Lands 9,513 297 149,261 62,379 2.39 Federal Total 476,693 3,084 736,614 1,025,645 0.72 U.S. Total 1,750,452 24,374 20,995,174 6,089,024 3.45 Source: Argonne National Laboratory and Department of Energy (2009). Natural gas production converted to barrels oil equivalent to facilitate comparison using th e conversion of 0.178 barrels of crude oil equals 1000 cubic feet natural gas. Totals may not sum due to independent rounding.
As can be seen in Table 2-7, the amount of water produced is not necessarily correlated with the ratio of water produced to the volume of oil or natural gas produced. Texas, Alaska and*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-19 Wyoming were the three largest producers in ba rrels of oil equivalent (boe) terms, but had relatively low rates of water production compared to more Midwestern stat es such as Illinois, Missouri, Indiana, and Kansas. Figure 2-3 shows the distribution of produced water management practices in 2007.

Figure 2-3 U.S. Produced Water Volu me by Management Practice, 2007
More than half of the water pr oduced (51 percent) was re-injected to enhance resource recovery through maintaining reservoir pressure or hydraulic ally pushing oil from th e 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 to tal 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 1990-2011 period (Table 2-8), appearing to follow the downward supply trend shown in Table 2-4. While exhibiting some variation, pipeline mileage transporting refined products remained relatively constant. 51%

34% 3% 11%

Injection for Enhanced Recovery Injection or Disposal Surface Discharge

Unknown

Source: Argonne National Laboratory*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-20 Table 2-8 U.S. Oil and Natural Gas Pipeline Mileage, 2010-2013 Natural Gas Pipelines (miles) Distribution mains Distribution Service Transmission pipelines Gathering lines Total 2010 1,229,501 872,377 304,775 19,640 2,426,293 2011 1,238,683 881,886 305,036 19,364 2,444,969 2012 1,247,115 892,209 303,333 16,524 2,459,181 2013 1,254,686 894,605 302,827 17,435 2,469,553 Source: U.S. Department of Transpor tation, Pipeline and Hazardous Material s Safety Administration, Office of Pipeline Safety, Annual Report Mileage Summary Statistics , available at http://phmsa.dot.gov/pipeline/library/dat a-stats as of December 29, 2014.

Table 2-8 splits natural gas pipelines into four types: distribution mains, distribution service, transmission pipelines, and gathering li nes. 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 ga thering lines to transport gas primarily to processing plants. Transmission pipelines move large volumes of gas to or from processing plants to distribution points. Fr om 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-l evel consumption trends fo r 1990 through 2012 are shown in*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-21 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 power on a percentage basis declined dur ing this period, while the share of total consumption by the transportation sector rose from 64 percent in 1990 to 71 percent in
2012.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-22 Table 2-9 Crude Oil Consumption by Sector, 1990-2012

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.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-23 Figure 2-4 Crude Oil Consumption by Sect or (Percent of Total Consumption), 1990- 2011

Natural gas consumption has increased over the last twenty years. From 1990 to 2012, total U.S. consumption increased by an average of about 1 per cent per year (Table 2-10 and Figure 2-5). Over the same period, industrial co nsumption of natural gas declined, whereas electric power generation increased its consumpti on quite dramatically, an important trend in the industry as many utilities increasingly use natura l gas for peak generation or switch from coalbased to natural gas-based electricity generation. The residential, commercial, and transportation sectors maintained their consumption levels at more or less constant levels during this time period. 0% 10% 20% 30% 40% 50% 60% 70% 80%Consumption (% of total)

Residential and Commercial Industrial Transportation Sector Electric Power*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-24 Table 2-10 Natural Gas Consumption by Sector, 1990-2012
Percent of Total
Total (tcf) Residential Commercial Industrial Electric Power Transportation
1990 19.93 22.0 13.1 45.3 16.2 3.3 1991 19.56 23.2 13.9 42.8 17.0 3.1 1992 20.23 23.1 13.8 43.1 17.0 2.9 1993 20.80 23.8 13.8 42.7 16.7 3.0 1994 21.27 22.8 13.6 42.0 18.3 3.2 1995 22.25 21.8 13.6 42.4 19.0 3.2 1996 22.67 23.1 14.0 42.9 16.8 3.2 1997 22.88 21.8 14.1 43.0 17.8 3.3 1998 22.32 20.3 13.4 42.9 20.6 2.9 1999 22.43 21.1 13.6 40.9 21.5 2.9 2000 23.31 21.3 13.6 39.9 22.3 2.8 2001 22.21 21.4 13.6 37.9 24.1 2.9 2002 23.02 21.2 13.7 37.5 24.7 3.0 2003 22.03 23.0 14.4 37.5 22.2 2.8 2004 21.99 22.1 14.2 37.9 23.0 2.7 2005 21.62 22.3 13.9 35.7 25.3 2.9 2006 21.37 20.4 13.2 35.9 27.6 2.9 2007 22.78 20.7 13.2 34.6 28.6 2.9 2008 22.95 21.3 13.7 34.4 27.6 3.0 2009 22.89 20.9 13.6 32.5 29.9 3.1 2010 24.06 19.9 12.9 33.7 30.6 3.0 2011 24.38 19.3 12.9 33.7 31.0 3.0 2012 25.64 16.3 11.3 33.4 36.1 3.0 Source: U.S. Energy Information Administration.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-25 Natural Gas Consumption by Sector (P ercent of Total Consumption), 1990-2012

2.4.4 International Trade Until 2006, net trade of crude oil and refine d 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). Sinc e then, however, imports have been declining while exports have been rising, l eading to significant declines in net trad e 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*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-26 Table 2-11 Total Crude Oil and Petrol eum Products Trade (Million Bbl), 1990-2013 Imports Exports Net Imports Crude

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

Natural gas imports also increased steadily from 1990 to 2007 in volume and percentage terms (Table 2-12). The years 2007 through 2012 sa w imported natural gas constituting a lower percentage of domestic natural gas consumpti on. Until recent years, industry analysts forecast that LNG imports would continue to grow as a percentage of U. S. consumption. However, it is possible that increasingly accessi ble 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.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-27 Table 2-12 Natural Gas Imports and Exports, 1990-2013 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. Th e forecasts are from the 2014 Annual Energy Outlook produced by EIA, the most current forecas t information available from EIA. As will be
discussed in detail in Secti on 7, to analyze the impacts of the proposed NSPS on the national energy economy, we use the National Energy Mo deling System (NEMS) that was used to produce the 2014 Annual Energy Outlook.

Table 2-13 present forecasts of successful wells drilled in the U.S. from 2010 to 2040.
Crude oil well forecasts for the lower 48 states s how a rise up to the year 2025 then a gradual
decline until 2040.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-28 Table 2-13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2040

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

Table 2-14 presents forecasts of domestic cr ude oil production, reserves, imports and 6 depicts these trends graphically.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-29 Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2011-2040 Domestic Production (million bbls)

Total Domestic Lower 48 Onshore Lower 48 Offshore Alaska Other Crude Supply Net Imports Total Crude Supply (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 2040, an increas e of 25 percent overall. This increment is larger than the forecast increase in production from the lower 48 states during this period, 12*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-30 percent, showing reserves are forecast to grow more rapidl y than production. Table 2-14 also shows average wellhead prices increasing mo re than 100 percent from 2010 to 2040, from $76.78 per barrel to $160.38 per barrel in 2011 dollar terms.

Figure 2-5 Forecast of Domestic Crude Oil Production and Net Imports, 2010-2040

Table 2-15 shows domestic natural gas production is forecast to increase until 2040. Meanwhile, imports of natural gas via pipeline ar e expected to be eliminated during the forecast period, from 1.68 tcf in 2011 to -2.43 in 2040 tcf. Im ports of LNG are also eliminated during the forecast period, from 0.28 tcf in 2011 to -3.37 tc f in 2040. Total supply, then, increases about 33 percent, from 22.55 tcf in 2011 to 37.54 tcf in 2040. 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*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-31 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 increas ed significantly over the past two decades, particularly in recent years. Cost per well has increased by an annual average of Dry Gas Productio

n Supplemen tal Natural Gas Net Imports (Pipeline) Net Imports (LNG) Total Supply Lower 48 End of Year Dry

Reserves

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

Source: U.S. Energy Information Administration, Annual Energy Outlook, 2014*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-32 about 15 percent, and cost per foot has increased on average of about 13 pe rcent 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 leasi ng of real property. EIA publishes finding costs as running three-year averages, in order to better compare these costs, which occur over several years, with annual average lifting costs. Figure 2-7 shows average domestic onshore and offshore and foreign finding costs for the sample of U.S. firms in EI A’s Financial Reporting System (FRS) database from 1981 to 2009. The costs are reported in 2009 do llars on a barrel of oil equivalent basis for crude oil and natural gas combined. Th e average domestic finding costs dropped from 1981 until the mid-1990s. Interesti ngly, 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 domes tic 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)*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-33 Figure 2-7 Finding Costs for FRS Companies, 1981-2009

After 2000, average finding costs rose sharply, w ith 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 Figur e 2-7 present similar trends overall.

2.5.2 Lifting Costs
Lifting costs are the costs to produce crude oi l or natural gas once the resource has been found and accessed. EIA’s definition of lifting cost s includes costs of operating and maintaining wells and associated production equipment. Di rect lifting costs excl ude production taxes or royalties, while total lifting costs includes taxes and royalties. Like finding costs, EIA reports average lifting costs for FRS firms in 2009 dollars on a barrel of oil equivalent basis. Total lifting costs are the sum of direct lifting costs and produ ction taxes. Figure 2-8 de picts direct lifting cost
trends from 1981 to 2009 for dome stic and foreign production. 0 10 20 30 40 50 60 70 80$2008/boe

U.S. Onshore U.S. Offshore Foreign*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-34 Figure 2-8 Direct Oil and Natural Gas Liftin g Costs for FRS Companies, 1981-2009 (3- year Running Average)

Direct lifting costs (excludes taxes and royalties) for domestic produc tion rose a little more than $2 per barrels of oil equivalent from 1981 to 1985, then declined almost $5 per barrel of oil equivalent from 1985 until 2000. From 2000 to 2009, do mestic lifting costs increased sharply, just over $8 per barrel of oil equivalent. Foreign lifting costs diverged fr om domestic lifting costs from 1981 to 1991, as foreign lifting costs were lo wer than domestic costs during this period. Foreign and domestic lifting co sts followed a similar track un til they again diverged in 2004, with domestic lifting again becoming more expens ive. Combined with finding costs, the total finding and lifting costs rose significantly in from 2000 to 2009.

2.5.3 Operating and Equipment Costs
The EIA report, “Oil and Gas Lease E quipment and Operating Costs 1994 through
2009” 8 , contains indices and estimated costs for domestic oil and natural gas equipment and production operations. The indices and cost trends track costs for representa tive operations in six regions (California, Mid-Contin ent, South Louisiana, South Te xas, West Texas, and Rocky

8 U.S. Energy Information Administration. “Oil and Gas Lease Equipment and Operating Costs 1994 through 2009.” September 28, 2010.
< http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_p ublications/cost_indices_equipment_production/curren t/coststudy.html > Accessed February 2, 2011. 0 2 4 6 8 10 12 14$2008/boe

Domestic Foreign*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-35 Mountains) with producing dept hs ranging from 2000 to 16,000 feet and low to high production rates (for example, 50,000 to 1 million c ubic feet per day for natural gas).

Figure 2-9 depicts crude oil operating cost s and equipment costs indices for 1976 to 2009, as well as the crude oil pri ce in 1976 dollars. The indices show that crude oil operating and equipment costs track the price of oil over th is time period, while operating costs have risen more quickly than equipment costs. Operating and equipment costs and oil pr ices rose steeply in the late 1970s, but genera lly decreased from about 1980 until the late 1990s.

Figure 2-9 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976 dollars), 1976-2009 9
Oil costs and prices again gene rally rose between 2000 to presen t, with a peak in 2008. The 2009
index values for crude oil operating and equipment cost s are 154 and 107, respectively.

9 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)*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-36 Figure 2-10 Natural Operating Costs a nd Equipment Costs Indices (1976=100) and Natural Gas Price, 1976-2009
Figure 2-10 depicts natural gas op erating and equipment costs indices, as well as natural gas prices. Similar to the cost trends for crude oil, natural gas operating and equipment costs track the price of natural gas over this time period, wh ile operating costs have ri sen more quickly than equipment costs. Operating and equipment costs a nd gas prices also rose steeply in the late 1970s, but generally decreased from about 1980 until the mid-1990s. The 2009 index values for natural gas operating and equipment costs are 137 and 112, respectively.

2.6 Firm Characteristics
A regulatory action to reduce po llutant discharges from fac ilities producing crude oil and natural gas will potentially affect the business entities that own the regulated facilities. In the oil and natural gas production industr y, facilities comprise those s ites where plant and equipment 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 busin ess decisions that a ffect 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)*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-37 2.6.1 Ownership
Enterprises in the oil and natural gas industr y may be divided into different groups that include producers, transporters , and distributors. Th e producer segment may be further divided between major and independent producers. Majo r producers include large oil and gas companies
that are involved in each of the five indus try segments: drilling and exploration, production, transportation, refining, and mark eting. Independent producers incl ude smaller firms that are
involved in some but not all of the five activities.

According to the Independent Petroleum A ssociation of America (IPAA), independent companies produce approximately 68 percent of do mestic 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 secondar y fuel for many producers. However, now it is of primary importance to many producers. IPAA re ports that about 50 percent of its members’ spending in 2007 was directed toward natural gas production, largely to ward production of unconventional gas (IPAA, 2009). Meanwhile, tran sporters are comprised of the pipeline companies, while distributors are compri sed of the local dist ribution companies.

2.6.2 Size Distribution of Firms in Affected NAICS

As of 2014, there were 6,659 firms with in the 211111 and 211112 NAICS codes, of which 6,535 (98 percent) were considered sm all entities (Table 2-16). Within NAICS 211111 and 211112, large firms compose about 2 percent of the firms, but account for about 60 percent of employment listed under these NAICS.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-38 Table 2-16 SBA Size Standard s 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 Natu ral Gas $27.5 million N/A N/A 27,151 Source: U.S. Small Business Administ ration Office of Advocacy. 2014. Firm Size Data. <Available at http s://www.sba.gov/advocacy/firm-size-da ta> 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 Ce nsus 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. en ergy supply, the oil and natural gas industry directly employs a significant number of peopl e. Table 2-17 shows employment in oil and natural gas-related NAICS codes from 1990 to 2013. The overall trend shows a decline in total industry employment throughout the 1990s, hitti ng a low of 314,000 in 1999, but rebounding to a 2013 peak of 620,000. Crude Petroleum and Na tural Gas Extraction (NAICS 211111) and Support Activities for Oil and Gas Operations (NAICS 213112) employ the majority of workers in the industry.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-39 Table 2-17 Oil and Natural Gas Indus try Employment by NAICS, 1990-2013 Crude Petroleum and Natural Gas Extraction

(NAICS 211111) Natural Gas Liquid Extraction

(NAICS 211112) Drilling of Oil and Natural Gas Wells (NAICS 213111) Support Activities for Oil and Gas Ops. (NAICS 213112) Pipeline Trans. of Crude Oil (NAICS 486110) Pipeline Trans. of Natural Gas

(NAICS 486210) Total 1990 182,848 8,260 52,365 109,497 11,112 47,533 411,615 1991 177,803 8,443 46,466 116,170 11,822 48,643 409,347 1992 169,615 8,819 39,900 99,924 11,656 46,226 376,140 1993 159,219 7,799 42,485 102,840 11,264 43,351 366,958 1994 150,598 7,373 44,014 105,304 10,342 41,931 359,562 1995 142,971 6,845 43,114 104,178 9,703 40,486 347,297 1996 139,016 6,654 46,150 107,889 9,231 37,519 346,459 1997 137,667 6,644 55,248 117,460 9,097 35,698 361,814 1998 133,137 6,379 53,943 122,942 8,494 33,861 358,756 1999 124,296 5,474 41,868 101,694 7,761 32,610 313,703 2000 117,175 5,091 52,207 108,087 7,657 32,374 322,591 2001 119,099 4,500 62,012 123,420 7,818 33,620 350,469 2002 116,559 4,565 48,596 120,536 7,447 31,556 329,259 2003 115,636 4,691 51,526 120,992 7,278 29,684 329,807 2004 117,060 4,285 57,332 128,185 7,073 27,340 341,275 2005 121,535 4,283 66,691 145,725 6,945 27,341 372,520 2006 130,188 4,670 79,818 171,127 7,202 27,685 420,690 2007 141,239 4,842 84,525 197,100 7,975 27,431 463,112 2008 154,898 5,183 92,640 223,635 8,369 27,080 511,805 2009 155,150 5,538 67,756 193,589 8,753 26,753 457,539 2010 153,490 4,833 74,491 201,685 8,893 26,708 470,100 2011 164,900 5,835 87,272 241,490 8,959 27,320 535,776 2012 181,473 6,529 92,340 282,447 9,348 27,595 599,732 2013 189,804 6,928 93,261 296,891 10,059 26,981 623,924 Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2013 , <http://www.bls.gov/cew/>

From 1990 to 2013, average wages for the oil an d natural gas industry have increased. Table 2-18 shows real wages (in 2012 do llars) from 1990 to 2013 for the NAICS codes
associated with the oil and natural gas industry.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-40 Table 2-18 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2013 (2012 dollars) Crude Petroleum and Natural Gas Extraction (211111) Natural Gas Liquid Extraction (211112) Drilling of Oil and Natural Gas Wells (213111) Support Activities for Oil and Gas Ops. (213112) Pipeline Trans. of Crude Oil (486110) Pipeline Trans. of Natural

Gas (486210) Total 1990 74,475 69,877 44,193 48 ,010 71,231 64,452 62,245 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 Census of Employment and Wages, 2013, annual wages per employee <http://www.bls.gov/cew/>

Employees in the NAICS 211 codes earn the highest average wages in the oil and natural gas industry, while employees in the NAICS 213 codes have relatively lower wages. Average wages in natural gas pipeline transpor tation show the highest variation.

2.6.4 Horizontal and Vertical Integration

Because of the existence of major companies, 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 outsi de are produced in hous e, while the horizontal*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-41 aspect of a firm’s size refers to the scale of pr oduction in a single-product firm or its scope in a multiproduct one. Vertical integra tion is a potentially important dimension in analyzing firmlevel impacts because the regulation could affect a vertically integrated firm on more than one level. The regulation may affect companies for whom oil and natural gas production is only one of several processes in which the firm is invol ved. For example, a company that owns oil and natural gas production facilities may ultimately produce final petroleum products, such as motor gasoline, jet fuel, or kerosene. Th is firm would be considered vert ically integrated because it is involved in more than one level of requiring cr ude oil and natural gas and finished petroleum products. A regulation that increas es the cost of oil and natura l gas production will ultimately affect the cost of producing final petroleum products.

Horizontal integration is also a potentially im portant dimension in firm-level analyses for any of the following reasons. A horizontally integr ated firm may own many facilities of which only some are directly affected by the regulati on. Additionally, a horizon tally integrated firm may own facilities in unaffected industries. This type of diversification would help mitigate the financial impacts of the regulation. A horizontally integrated firm coul d also be indirectly as well as directly affected by the regulation.

In addition to the vertical and horizontal inte gration that exists among the large firms in the industry, many major producer s often diversify within the energy industry and produce a wide array of products unrelated to oil and gas production. As a result, so me of the effects of regulation of oil and gas production can be mitig ated if demand for other energy sources moves inversely compared to petroleum product demand.

In the natural gas sector of the industry, vert ical integration is le ss predominant than in
the oil sector. Transmission and local distribution of natural gas usually occur at individual firms, although processing is increasing performed by the integrated major compan ies. Several natural gas firms operate multiple facilities. However, na tural gas wells are not exclusive to natural gas firms only. Typically wells produce both oil and gas and can be ow ned by a natural gas firm or an oil company.

Unlike the large integrated firms that have several profit centers such as refining, marketing, and transportation, most independents ha ve to rely only on profits generated at the*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-42 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 pipeli ne companies and are not vertica lly integrated. Independents may also own relatively few facilities, indi cating limited horizon tal 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 ga s companies with domestic reserves and headquarters in the U.S. In the past, the survey reported information on the top 300 companies, now the top 150. In 2012, 134 public companies are listed; in 2011there were 145 firms. 10 The 2012 list contains four companies th at were not on the list in th e previous year. Also, 10 other companies listed in 2011do not appear on the 2012 list as a result of merg ers, bankruptcies, or
other reasons. Table 2-19 lists selected statis tics for the top 20 companies in 2012. 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 cap ital and operating costs in 2012.

Net income for the top 134 companies fe ll between 2011 and 2012 fr om $114.5 billion to $91.1 billion. Revenues for these companies fe ll 1.4 percent from 2011 to 2012. Even though earnings decreased in 2012, strong earnings from 2011 boosted ava ilable financial resources and the companies continued to invest. Capital a nd exploratory spending for the companies in 2012 totaled $206.5 billion, up 17.1 from 2011.

The total worldwide liquids production for the 134 firms increased 6.85 percent to 2.879 billion bbl, while total worldwid e gas production increased 2.4 percent to a total of 17.4 tcf ( Oil
and Gas Journal , September 2, 2013). Meanwhile, the 134 firms on the OGJ list increased both oil and natural gas production and reserves fr om 2011 to 2012. Domestic production of liquids increased about 19.8 percent from 2011 to 1.437 b illion bbl, and natural gas production was up about 6.3 percent. For context, the OGJ150 do mestic crude production represents about 49 percent of total domestic production (2.06 billi on bbl, according to EIA). The OGJ150 natural gas production represents about 69 percent of total domestic production (28.5 tcf, according to

10 Oil and Gas Journal. “OGJ150 Earnings Down as US Production Climbs.” September 2, 2013.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-43 EIA).

The OGJ also releases a period report ent itled “Worldwide Gas Processing Survey”, which provides a wide range of information on ex isting 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 co mpany 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 we re 727 facilities with a capacity of 60,533 million cubic feet per day (U.S. DOE, 2006).

Trends in gas processing facility ownershi p 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 pe rcent of the facilities. That larger companies tend to own larger facilities is indicated by these top 20 firms owning 86 percen t of the total capacity and 88 percent of actual throughput.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***2-44Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012WorldwideProductionUSProductionRank byTotalAssets Company EmployeesTotalAssets($Million)TotalRevenue($Million)NetIncome($Million)Liquids(Millionbbl)NaturalGas(Bcf)Liquids(Millionbbl)NaturalGas(Bcf)NetWellsDrilled1ExxonMobil Corp.76,900 333,795 482,295 47,681 625 2,992 166 1,518 1,4112Chevron Corp.17,418 232,982 241,909 26,336 536 1,737 151 1,129 1,2723ConocoPhillips16,900 117,144 62,004 8,498 271 1,539 120 916 1,1634Occidental Petroleum Corp.12,300 64,210 24,253 4,598 201 1129 100 752 1,0165Apache Corp.5,976 60,737 17,078 2,001 145 938 84 685 9586 Anadarko Petroleum Corp. 5,200 52,589 13,411 2,445 115 916 75 565 9517 Hess Corp. 14,775 43,441 38,373 2,063 110 839 61 440 8268 Devon Energy Corp. 5,700 43,326 9,502 -206 103 565 57 407 7699 Chesapeake Energy Corp. 12,000 41,611 12,316 -594 93 557 49 380 75110 Marathon Oil Corp. 3,367 35,306 16,221 1582 78 470 45 380 69911 EOG Resources Inc. 2,650 27,337 11,683 570 49 416 39 313 51312 Noble Energy Inc. 2,190 17,554 4,223 1027 42 380 34 300 49213 Murphy Oil Corp. 9,185 17,523 28,626 971 41 322 26 259 46814 Plains Exploration andProduction Co 906 17,298 2,565 343 34 284 25 253 43915Pioneer Natural Resources Co.3,667 13,069 3,228 243 26 259 24 249 36716 Linn Energy LLC 1,136 11,451 1,774 -387 25 253 24 249 33417 Denbury Resources Inc. 1,432 11,139 2,456 525 24 249 24 183 31518 Sandridge Energy Inc. 2,510 9,791 2,731 247 24 249 20 161 29719 WPX Energy Inc. 1,200 9,456 3,189 -211 22 244 18 160 27120 Continental Resources Inc. 753 9,140 2,573 416 20 183 18 156 263Source: Oil and Gas Journal. “OGJ150 Earnings Down asUS Production Climbs.” September 2, 2013. The annualOil and Gas Journal(OGJ) survey, theOGJ150, reports financial and operating results for public oil and natural gas companies with domestic reserves and headquarters in the U.S.Notes: The source for employment figures is Hoovers, a D&B Company.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-45 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 Processi ng: 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 th e economics of the U.S. pipeline industry. This report examines the economic status of all major and non-major natural gas pipeline companies, which amounts to 162 companies in 2011 ( Oil and Gas Journal , September 2, 2013). Table 2-21 presents the pipeline mileage, volum es of natural gas tran sported, operating revenue, and net income for the top 20 U. S. natural gas pipeline compan ies in 2012. Ownership of gas pipelines is mostly independent from ownership of oil and gas pr oduction companies, as is seen from the lack of overlap between the OGJ lis t 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 61 perc ent of the total pipeline mileage and transport about 56 percent of the volume of the industry (Table 2-21). Operating revenues of the*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-46 top 20 companies equaled $12.1 billion, representi ng 59 percent of the to tal operating revenues for major and non-major companies. The top 20 co mpanies 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), 2012

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

1 Dominion Transmission Inc. 3,687 653,272 903,404 256,010 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 System (FRS) collects financial and operating information from a subset of the U.S. major energy producing companies and reports summary information in the publica tion “The Performance Profiles of Major Energy
Producers”. 11 This information is used in annual report to Congress, as well as is released to the

11 The “Performance Profiles of Major En ergy Producers 2009” released on Febr uary 25, 2011 is the most recent release of this report.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-47 public in aggregate form. While the companies that report information to FRS each year changes,
EIA makes an effort to retain sufficient consiste ncy such that trends can be evaluated. For 2009, there are 30 companies in the FRS 12 that accounted for 43 percent of total U.S. crude oil and NGL production, 43 percent of natu ral gas production, 78 percent of U.S. refining capacity, and 0.3 percent of U.S. electricity net generation (U.S. EIA, 2011). Table 2-22 shows a series of financial trends in 2008 dollars selected and aggr egated from FRS firms’ financial statements. The table shows operating revenues and expenses rising significantly from 1990 to 2008, with operating income (the difference between operating revenues and expenses) rising until dropping off significantly in 2009. Interest expenses remained relatively flat during this period. Meanwhile, recent years have shown that other in come and income taxes have played a more significant role 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 d eclined signifi cantly during the
latter half of 2008.

12 Alenco, Alon USA, Anadarko Petroleum Corporation, Apache Corporation, BP America, Inc., Chalmette, Chesapeake Energy Corporation, Chevron Corporation, CITGO Petroleum Corporation, ConocoPhillips, Devon Energy Corporation, El Paso Corporation, EOG Resources, Inc., Equitable Resources, Inc., Exxon Mobil Corporation, Hess Corporation, Hovensa, Lyondell Chem ical Corporation, Marathon Oil Corporation, Motiva Enterprises, L.L.C., Occidental Petroleum Corporation, Shell Oil Company, Sunoco, Inc., Tesoro Petroleum Corporation, The Williams Companies, Inc., Total Ho ldings USA, Inc., Valero Energy Corp., Western Refining, WRB Refining LLC, and XTO Energy, Inc.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-48 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 co mpanies. For U.S. petroleum-related business activities, oil and natural gas producti on was the most profitable line of business relative to refining/marketing and pipelines, sust aining 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 high ly profitable line of business for the FRS companies and declined significantly in 2009.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-49 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 and natural gas industry also produces significant tax revenues for local, state,
and federal authorities. Table 2-24 shows income and producti on tax trends from 1990 to 2009 for FRS companies. The column with U.S. federal, state, and local taxes pa id or accrued includes
deductions for the U.S. Federal Invest ment Tax Credit ($198 million in 2008) 13 and the effect of the Alternative Minimum Tax ($34 million in 2 008). 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.

13 Data was withheld in 2009 to avoid disclosure.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-50 Table 2-24 Income and Production Taxes, 1990-2009 (Million 2008 Dollars)

Year US Federal, State, and Local Taxes Paid or Accrued Total Current Total Deferred Total Income Tax Expense Other Production Taxes Paid 1990 9,568 25,056 -230 24,826 4,341 1991 6,672 18,437 -3,027 15,410 3,467 1992 4,994 16,345 -4,116 12,229 3,097 1993 3,901 13,983 -1,302 12,681 2,910 1994 3,348 13,556 887 14,443 2,513 1995 6,817 17,474 -510 16,965 2,476 1996 8,376 22,493 3,626 26,119 2,922 1997 7,643 20,764 3,141 23,904 2,743 1998 1,199 7,375 -1,401 5,974 1,552 1999 2,626 13,410 140 13,550 2,147 2000 14,308 36,187 6,674 42,861 3,254 2001 10,773 28,745 4,351 33,097 3,042 2002 814 17,108 46 17,154 2,617 2003 9,274 30,349 6,879 37,228 3,636 2004 19,661 50,185 4,024 54,209 3,990 2005 29,993 72,595 4,529 77,125 5,331 2006 29,469 85,607 9,226 94,834 5,932 2007 28,332 84,119 2,188 86,306 7,501 2008 23,199 95,590 2,866 98,456 12,507 2009* -1,655 35,478 -5,988 29,490 -173 Source: Energy Information Administration, Fo rm 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 countr ies. As can be seen in Table 2-24, foreign taxes paid far exceeds domestic taxes paid. Other non- income production taxes paid, which have risen almost three-fold between 1990 and 2008, include wi ndfall profit and severan ce taxes, as well as other production- related taxes.

2.7 References

Andrews, et al. 2009. Unconventional Gas Shales: Devel opment, Technology, and Policy Issues. Congressional Research Service. R40894.
Argonne National Laboratory. 2009. Produced Water Vo lumes 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.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-51 Independent Petroleum Association of Amer ica. 2009. Profile of Independent Producers.<http://www.ipaa.org/wpcontent/uploads/downloads/2011/12/2009Pro fileOfIndependentProducers.pdf> Accessed March 30, 2011.

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

Oil and Gas Journal . “US Pipeline Operators Sink Revenue Growth into Expansion.” September 2, 2013.

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

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

U.S. Energy Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial Link between Natural Gas Production and Its Transportation to Market. <http://www.eia.doe.gov/pub/oil_gas/natural_ga s/feature_articles/2006/ngprocess/ngproc ess.pdf> Accessed February 2, 2011.
U.S. Department of Energy. 2013. Modern Shale Gas Development in the United States: An Update. < http://www.netl.doe.gov/File20Lib rary/Research/Oil-Gas/shale-gas-primerupdate-2013.pdf> Accessed December 19, 2014.

U.S. Energy Information Administration (U.S . EIA). 2012. Annual Energy Review 2011 (AER). <http://www.eia.doe.gov/emeu/aer/contents.html>

U.S. Energy Information Administration (U.S . EIA). 2010. Oil and Gas Lease Equipment and Operating Costs 1994 through 2009 <http://www.eia.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_ production/current/coststudy.html> Accessed March 30, 2011.
U.S. Energy Information Administration (U.S. EIA). 2013. Summary: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves 2011. <http://www.eia.doe.gov/oil_gas/natural_gas/ data_publications/crude_oil_natural_gas_re serves/cr.html> Accessed September 15, 2013.

U.S. Energy Information Administration (U.S . EIA). 2011. Performance Profiles of Major Energy Producers 2009. <http://www.eia.gov/fina nce/performancepro files> Accessed September 15, 2013.
U.S. Energy Information Administration (U.S. EIA). 2014. Annual Energy Outlook 2014. <http://www.eia.gov/forecasts/aeo/> Accessed March 17, 2014.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

2-52 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/IP s/Oil20and20NG20Production20and20NG20Tra nsmission_IP.pdf> Accessed December 19, 2014.

U.S. Environmental Protection Agency (U.S . EPA). 2000. EPA Office of Compliance Sector Notebook Project: Profile of the Oil and Ga s Extraction Industry. EPA/310-R-99-006. <http://www.epa.gov/compliance/resources/public ations/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 Protection 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/oil_ natural_gas_final_neshap_nsps_ria.pdf> Accessed December 19, 2014.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-1 3 EMISSIONS AND ENGINEERING COSTS

3.1 Introduction

This chapter describes the emissions and e ngineering cost analysis for the proposed
NSPS. The first section discusse s the emissions points and contro l options. The following section describes each step in the emissi ons 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 reference to the more-det ailed Technical Support Do cument (TSD) prepared by the U.S. EPA for the reader interested in a greater level of detail. 14

3.2 Sector Emissions Overview

Before going into detail on emissions points a nd pollution controls, it is useful to provide
estimates of overall emissions from the crude o il 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 emissions are approximately 2.8 million to ns, according 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 2013 methane emissions from Petroleum and Natural Gas Systems (not including petroleum refineries a nd petroleum transportation) to be 182 MMt CO 2 Eq. In 2013, total methane emissions from the oil and gas industry represented nearly 29 percent
of the total methane emissions from all sour ces and account for about 3 percent of all CO 2 Eq. emissions in the U.S., with the combined petroleum and natural gas systems being the largest contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2015).

It is important to note that the 2013 GHG emissions estimates do not include methane emissions from hydraulically fractured and re-fra ctured oil well completions due to lack of available data when the 2013 GHG Inventory esti mate was developed. The estimate in this proposed rule includes an adjustment for hydr aulically fractured oil wells, and such an adjustment is also being considered as a pl anned improvement in the 2014 Inventory (to be published April 2016). This adjustment would increase the 2013 Inventory methane estimate by

14 U.S. EPA. 2015. Oil and Natural Gas Sector: Stan dards 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.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-2 about 3 MMt CO 2 Eq. The total methane emissions from Petroleum and Natural Gas Systems based on the 2013 GHG Inventory, adjust ed 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 evaluate d as part of the NSPS review. This section provides a basic description of emissions source s and the controls evaluated for each source to
facilitate the reader’s understa nding of the economic impact a nd benefit analyses. The reader
who is interested in more technical detail on th e engineering and cost ba sis 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 emissions are from venting of natural gas to the atmosphere during flowback. Flowback
emissions are short-term in natu re and occur as a specific even t during completion of a new well or during activities that involve re-drilling or re-fracturing an existing well. The TSD separately considers developmental wells and exploratory wells. Developmental wells are wells drilled within known boundaries of a proven oil or gas fi eld, while exploratory or “wildcat” wells are wells drilled in areas of new or unknown potential.

The EPA considered the same two techniques that have been proven to reduce emissions from well completions: reduced emissions comp letions (RECs) and completion combustion. The use of a REC not only reduces emissions but delive rs natural gas product that would typically be
vented to the sales meter. Co mpletion combustion destroys th e organic compounds. Three main
technical barriers limit the feasibi lity of RECs at some wells: proxi mity of pipelines, pressure of produced gas, and iner t 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 pressure and pressure or mechanical stresses can also cause components or equipment to leak. Potential source s of fugitive emissions include agitator seals, connector s, pump diaphragms, flanges, instruments, meters, open-ended*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-3 lines, pressure relief devices, pump seals, valves or improperly controlle d liquid storage tanks. These fugitive emissions do not include devices th at vent as part of normal operations, such as gas driven pneumatic controllers or gas driven pneumatic pumps.

The TSD considers fugitive emissions from production well sites, gathering line and boosting stations, and natural ga s transmission/storage compre ssor stations. There are two options for reducing methane and VOC emissions from leaking components: a leak monitoring program based on individual component monitoring using EPA Method 21 for leak detection combined with a leak correction, and a leak m onitoring program based on the use of OGI leak
detection combined w ith leak correction. The former option was evaluated during NSPS subpart
OOOO and was not found to be cost-effective. Th erefore, 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 determ ine the potential emission reductio ns and the cost of control. In addition, alternative frequenc ies for fugitive emissions surv eys were considered: annual, semiannual, and quarterly.

Pneumatic controllers : Pneumatic controllers are automated instruments used for maintaining a process condition such as liquid le vel, pressure, pressure different ial, and temperature. In many situations across all segments of the oil and na tural gas industry, pneumatic controllers make use of the available high-pressure na tural gas to operate or control a valve. In these “gas-driven” pneumatic controllers, natural gas may be re leased with every valve movement and/or continuously from the valve control pilot. Not all pneumatic controllers are gas driven. These “non-gas driven” pneumatic controll ers use sources of power other than pressurized natural gas. Examples include solar, electric, and instrument air. At oil and gas locations with electrical service, non-gas-driven c ontrollers are typically used. Contin uous bled pneumatic controllers can be classified into two types based on their emi ssions rates: (1) high-bl eed controllers and (2)
low-bleed controllers. A contro ller 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 bleed at a rate less than or equal to 6 scfh. EPA evalua ted the impact of replaci ng high-bleed controllers
with low-bleed controllers.

Pneumatic pumps : Pneumatic pumps are devices that use ga s pressure to drive a fluid by raising*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-4 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 read ily 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 wellbores, surface equipment, and pipelines. Typi cally, these pumps include plunger pumps with a diaphragm or large piston on the gas end and a sm aller piston on the liquid end to enable a high discharge pressure with a vari ed but much lower pneumatic supply gas pressure. They are typically used semi-continuously with some s easonal variation. Pneumatic diaphragm pumps are another type used widely in the onshore oil and ga s sector to move larger volumes of liquids per unit of time at lower discharge pr essures than chemical and meth anol injection pumps. The usage of these pumps is episodic including transferri ng bulk liquids such as motor oil, pumping out sumps, and circulation of heat trace medium at well sites in cold climat es 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 fill ing of the liquid chamber side of the diaphragm. Emissions are a function of the amount of fluid pumped, the pressu re of the pneumatic suppl y gas, the number of pressure ratio’s between the pneumatic supply gas pressure and the fluid discharge pressure, and the mechanical inefficiency of the pump. As disc ussed 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 th e impact of routing pump emissions to a preexisting on-site control device.

Centrifugal and Reciprocating Compressors: Compressors are mechanical devices that increase the pressure of natu ral gas and allow the natural ga s to be transported from the production site, through the supply ch ain, and to the consumer. The t ypes 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 na tural gas leaks around moving parts in the*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-5 compressor. In a reciprocating compressor, em issions occur when natural gas leaks around the piston rod when pressurized natura l gas is in the cylinder. Over time, during operation of the compressor, the rod packing system becomes wo rn and will need to be replaced to prevent excessive leaking from the compression cylinder. The potential control options reviewed for reducing emissions from reciprocating compresso rs include control techniques that limit the leaking of natural gas past the piston rod packi ng. 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 high pr essure, or “dry”, which use a thin gap of high pressure gas. The use of dry gas seals substantially reduces emi ssions. In addition, they significantly reduce operating costs and enhance compressor efficienc y. Limiting or reducing the emission from the rotating shaft of a centrifugal co mpressor using a mechanical dry seal system was evaluated. For centrifugal compressors equipped with wet seals, a flare was evaluated as an option for reducing emissions from centrifugal compressors.

3.4 Engineering Cost Analysis

In this section, we provide an overview of the engineering co st analysis used to estimate the additional private expenditu res industry may make to comp ly with the proposed NSPS. A detailed discussion of the methodology used to es timate 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 cate gory, including baseline emissions and control options. The regulator y alternatives include differe nt variations of regulatory requirements considered for inclusion in the prop osed standards. Then, pr ojections are made of the number of incrementally affected facilities fo r 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 options result in natura l gas recovery, which can 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.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-6 3.4.1 Control Options

For each emissions source, point, and control option, the TSD develops a representative facility. The characteristics of this facility in clude typical equipment, operating characteristics, and representative factors includ ing baseline emissions and the co sts, emissions reductions, and product recovery resulting from each control option.

Table 3-1 shows the emissions sources, point s, and controls analyzed in three NSPS regulatory options, which we term Option 1, Op tion 2, and Option 3. Option 2 was selected for proposal. The proposed Option 2 contains reduced emission co mpletion (REC) and completion combustion requirements for a subset of newl y completed oil wells that are hydraulically fractured or refractured. Option 2 also requires f ugitive emissions survey and repair programs be performed at newly drilled or refractured oil and natural gas well sites, new or modified gathering and boosting stations, and new or m odified transmission and storage compressor stations. Option 2 also requi res reductions from centrifuga l compressors, reciprocating compressors, pneumatic controllers, and pneuma tic pumps throughout the oil and natural gas source category.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-7 Table 3-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS

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

- bustion REC / Com

bustion
Hydraulically Fractured Wildcat and Delineation Oil Wells Combustion X X X X Fugitive Emissions

Well Pads Monitoring and Maintenance Semiannual with Low Production Exemption Annual Semiannual Quarterly

Gathering and Boosting Stations Monitoring and Maintenance Semiannual Annual Semiannual Quarterly

Transmission Compressor Stations Monitoring and Maintenance Semiannual 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 th e selected Option 2 with respect to the requirements f or or hydraulically fractured oil well completions and fugitive emissions at well
sites . While Option 2 requires the fugitive emissions program that all new and modified well sites, Option 1 does not have the fugiti ve requirements for low production sites. 15 A low

15 In the preamble to the proposed rule, EPA is soliciting comment on excluding low production sites from the fugitive emissions program.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-8 production site is defined by the average production the wells at the site producing less than 15 barrels of oil equivalent per day development oil well completions use RECs in all feasible circumstances, Option 1 requires flaring only

. 16 Fewer sites in the program leads to lower costs and emissions reductions than under the proposed Option 2. Meanwhile Flaring completion emissions is less costly than RECs, but results in more combustion-rela ted secondary emissions and does not recover the natural gas. Option 1 requ ires less frequent fugitive emissions surveys at well sites – on an annual schedule as opposed to the semiannual schedule in the selected option
, the more stringent while Option 3 requires quarterly monitoring for all sites under the fugitive emissions program, including low production sites . More frequent surveys result in higher costs, higher emissions reductions , and increased natural gas recovery.

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 facilities. Incrementally affected facilities are facilities that would be expected to change thei r emissions control activi ties as a result of the proposal. Facilities in states with similar st ate-level requirements are not included within incrementally affected 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 pr oposal over a longer period of time. Affected
facilities are facilities wh ich are new or modified since the e ffective year of the proposal. In 2020 affected facilities are those which are newly established or modified in 2020. Over time more facilities are newly established or mo dified 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 facili ties newly established or modified in 2025, but also facilities which were newly established or modified from 2020 through 2024 and are still operating in
2025.

The EPA has projected affected facilities using a combination of historical data from the U.S. GHG Inventory, and projec ted activity levels, taken from the Energy Information

16 Natural gas production is converted to barrels oil equiva lent using the conversion of 0.178 barrels of crude oil equals 1000 cubic feet natural gas*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-9 Administration (EIA’s) Annual En ergy Outlook (AEO). The EPA de rived typical counts for new compressors, pneumatic controllers, and pneum atic pumps by averaging the year-to-year increases over the past ten years in the Inventory. New hydr aulically fractured oil well completions and well sites are based on projections and growth rates consis tent with the drilling activity in the 2014 Annual Energy Ou tlook. If recent decreases in oi l prices lead to lower oil drilling activity in the United States, then the costs and emissions reductions resulting from the rule would also be reduced. [Placeholde r 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 require RECs for hydraulically fractured oil and gas wells. Colorado, Wyoming, Utah, and Ohio also require fugitive emissions monito ring at well sites and compressor stations. Applicable facilities
in these states are not included in the estimates of incrementally affected facilities presented in the RIA, as those states already have similar requirements to the federal standards. A more
detailed discussion on the derivation of the baselin e for the current proposal is presented for each
emissions source is the TSD. The estimated count s of hydraulically-fractur ed and re-fracture oil well completions also account for the wells antic ipated to be excluded from the proposed NSPS requirements because of a gas-to-o il ratio (GOR) of 300 or below.

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

Emissions Sources Incrementally Affected Sources
2020 2025 1 * Hydraulically Fractured and Re-fractured Oil Well Completions 15,000 15,000 Fugitive Emissions 2 22,000 140,000 Pneumatic Pumps 3,000 18,000 Compressors 68 410 Pneumatic Controllers 210 1,300 Total 40,000 180,000

1 * 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.
2 The number of incrementally affected sources under Optio n 1, which excludes low production well sites, includes about 14,000 fugitive emissions sources in 2020 and 86,000 fugitive emissions sources in 2025. Total incrementally affected sources under Option 1 are estimated at about 31,000 sources in 2020 and 120,000 sources in 2025.

Table 3-2 presents the estimates of the number of incrementally affected sources for this proposal after accounting for state regulations as described above. Note that hydraulically*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-10 fractured and re-fractured oil well completions do not grow significantly from 2020 to 2025, while other sources do. This is a result of comple tions being a one-time activity in a given year,
while other sources are affected and remain affe cted as they continue to operate, thus these
sources accumulate over time. The estimates for th at hydraulically fracture d and re-fractured oil well completions and fugitive emissions at well sites (a large fraction of the incrementally affected sources under the proposed rule fugiti ve emissions provisions) include both new and
modified sources. The estimates for other sour ces are based upon projections of new sources alone. While some of these sources, particularly pneumatic pumps and controllers, are likely to be predominantly new sources, the impact es timates may be under-estimated by the underrepresented modified sources. In the preamble to the proposed rule, the EPA solicits comments on these projection methods as well as solicits information that would improve our estimate of
the turnover rates or rates of m odification of relevant sources , as well as the number of wells on
well sites.

.

3.4.3 Emissions Reductions

Table 3-3 summarizes the national emissi ons reductions for the evaluated NSPS emissions 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. Ta ble 3-1 summarizes the applicable controls, and Table 3-2 summarizes the affected facilities, aggr egating multiple model plant types within each source category (e.g., oil well completions comb ine 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.

Table 3-3 Emissions Reductions fr om 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*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-11 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 annualized cost estimates presented belo w include revenue from additional natural gas recovery in the production and processing se gments. Several emission controls for the NSPS capture methane and VOC emissions that otherwis e would be vented to the atmosphere. A large proportion of the averted methane emissions can be directed into natural gas production streams
and sold. For environmental controls that avert the emission of sal eable natural gas, we base the estimated revenues from averted natural gas emi ssions on an estimate of the amount of natural gas that would not be emitted dur ing 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 compressors, and low-bleed pneumatic devices. The proposed requirements for completions at exploration and delineation wells, pneumatic pumps, and centrifugal compressors do not result in natural gas recovery. In some of these cases, alternative control stra tegies do result in natural gas recovery, but these alternative cont rols 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 pu mp 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 thousand cubic fe et (Mcf) for the recove red gas at the wellhead. The Energy Information Administration’s 2014 A nnual Energy Outlook forecasted wellhead*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-12 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 poi nt in the system provide bene fits to the energy system and to the public. However, due to contractual arrangements, transm ission and 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 excludes revenue from natural gas recovery in estimating compliance costs for the transmission and storage segment. This approach likely overes timates the long-term compliance cost of the
controls.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-13 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 $25,000,000 6,200,000 $25,000,000 Fugitive Emissions 1,900,000 $7,300,000 12,000,000 $47,000,000 Pneumatic Pumps 0 $0 0 $0 Compressors 76,000 $0 450,000 $0 Pneumatic Controllers 30,000 $0 180,000 $0 Total 8,200,000 $32,000,000 19,000,000 $72,000,000
As natural gas prices can increase or d ecrease rapidly, the estimated engineering compliance costs can vary when revenue from add itional natural gas recovery is included. There is also geographic variability in wellhead prices, which can also influence estimated engineering costs. For the proposed option, a $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $8.2 million in 2020 and $19 million in 2025,
in 2012 dollars.

3.4.5 Engineering Compliance Costs

Table 3-6 summarizes the capital and annua lized 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 ex pected lifetimes. This approach is mathematically equivalent to establishing an overall, representative pr oject time horizon and annualizing costs after consideration of control options that would need to be replaced periodically within the given
time horizon.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-14 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. Different emissions control options were annualized using expected lifetimes that were de termined to be most appropriate for individual options. For control options ev aluated for the NSPS, the fo llowing lifetimes were used:

 Reduced emissions completions and combusti on devices: 1 year (more discussion of the selection of a one-year lifetime follows in this section)

 Fugitive emissions monitori ng program design: 8 years

 Reciprocating compressors rod packing: 3.8 – 4.4 years

 Centrifugal compressors, pneumatic cont rollers, and pneumatic pumps: 10 years
Reporting and recordkeeping cost s were drawn from the inform ation collection requirements (ICR) in this proposed rule that have been s ubmitted 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 cost s in this RIA ($1.4 million) ar e based on the first year ICR cost estimates. Meanwhile, we drew upon the firs t year cost in the I CR 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 sta ndards for both methane and VOC reductions.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-15 As discussed in the preamble to this action, co st-effectiveness analysis allows comparisons of relative costs and outcomes (effects) of two or more options. In general, cost-effectiveness is a measure of the benefit produced by resources sp ent. 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 pollutant reductio ns realized annually. A costeffectiveness analysis is not intended to constitu te 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-effectiv eness values is relati vely straightforward when an abatement measure controls a singl e pollutant. Increasingly, however, air pollution reduction programs require reductions in emissions of multiple pollutants, and in such programs multipollutant controls may be employed. Conseque ntly, there is a need for determining costeffectiveness for a control option across multiple pollutants (or classes of multiple pollutants). This is the case for the current proposal wh ere EPA is proposing to directly regulate both
methane and VOC.

To assign the entire annualized cost to th e reduction in emissions of a single pollutant reduced by the multipollutant control option is appropriate when re ductions of the other pollutants are considered to cobenefits with no cost. However, under the current proposal, methane and VOCs are both directly regulated; ther efore, reductions of each pollutant must be properly considered benefits, not co-benefits, and consideration of only one of the regulated pollutants is not appropriate.

Alternatively, all annualized costs can be allocated to each of the pollutant emission reductions addressed by the multipollutant c ontrol option. Unlike the approach above, no emission reduction is treated as a co-benefit; each emission reduction is assessed based on the full cost of the control. However, this appr oach, which is often used for assessing singlepollutant controls, evaluates emission reduction of each pollutant separately, assuming that each bears the entire cost, and thus inflates the contro l cost in the multiple of the number of additional pollutants being reduced. This approach therefor e over-estimates the cost of obtaining emissions reductions with a multipollutant control as it does not recognize th e simultaneity of the reductions achieved by the application of the c ontrol option. Another ap proach allocates the*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-16 annualized cost to the sum of the individual pollutant emission reductions addressed by the multipollutant control option. The multipollutant co st-effectiveness approach may be appropriate when each of the pollutant reductions is simila r in value or impact. However, in the current proposal, methane and VOC have quite different health and environmental impacts, and therefore summing 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 assi gn all costs to the emission reduc tion of one pollutant and zero to all other concurrent reductions; if the cost is reasonable for reduci ng any of the targeted emissions alone, the cost of such control is clearly reasonable for th e concurrent emission reduction of all the other polluta nts because they are being redu ced at no additional cost. While this approach assigns all costs to only a por tion 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 ad dition, this approach is simp le and straight forward in application. If the multipollutant co ntrol is cost effective for reduc ing emissions of either of the targeted pollutant, it is clearly cost effective fo r reducing all other target ed emissions that are being achieved simultaneously.

A second approach, which we term a “multipollutant cost-effectiveness” approach, apportions the annualized cost across the pollutant reductions addressed by the control option in proportion to the relative percentage reducti on of each pollutant c ontrolled 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 allocated to methane, the other half to VOC. This appr oach similarly does not inflate the control cost nor requires unreasonable assumptions about th e equivalency of the impacts between a ton of methane and
VOC emission reduction.

We believe that both approaches discusse d above are appropriate for assessing the reasonableness of the multipollutant controls consid ered in this action. As such, in our analyses*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-17 below, if a device is cost effective under either of these two approaches, we find it to be cost effective. 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 appr opriate in other instances.

Under the single pollutant co st-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.

Table 3-6 Engineering Compliance Cos t-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 $1,100 $40 $900 $1,100 $39 Fugitive Emissions $1,400 $5,300 $62 $1,400 $5,100 $60 Pneumatic Pumps $160 $560 $7 $160 $560 $7 Compressors $160 $5,600 $7 $160 $5,600 $7
Pneumatic Controllers $9 $320 $0 $9 $320 $0

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

For the multipollutant cost-eff ectiveness approach, costs ar e allocated proportionally to methane and VOC reductions based on the percent reduction achieved in each pollutant (Table 3- 7). Because the relevant oil a nd gas controls reduce methane and VOC in equal proportion, 50 percent of costs are allo cated to each emission.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-18 Table 3-7 Engineering Compliance Cos t-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 $540 $20 $450 $530 $20 Fugitive Emissions $710 $2,700 $31 $680 $2,500 $30 Pneumatic Pumps $78 $280 $3 $78 $280 $3 Compressors $78 $2,800 $3 $78 $2,800 $3 Pneumatic Controllers $5 $160 $0 $5 $160 $0 Total $490 $690 $22 $530 $1,200 $24

3.4.7 Comparison of Regulatory Alternatives

Table 3-8 presents a comparis on of the regulatory alternatives through each step of the emissions analysis in 2020 and 2025. All three opti ons would affect the same number of sources.
The differences in methane and VOC reductions be tween the options result from differences 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 percen t, and 80 percent. Natural gas recovery also varies as a result of survey fr equency. 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 feasible in the proposed opt ion. Variation between th e options in capital costs are also due to oil well completions, because REC and flare costs are classified as capital

costs.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-19 Table 3-8 Comparison of Regulatory Alternatives Regulatory Alternative

Option 1 Option 2 (proposed) Option 3 Impacts in 2020 Affected Sources 31 40 ,000 40,000 40,000 Emissions Reductions Methane Emissions Reduction (short tons/year) 170,000 180,000 190,000 VOC Emissions Reduction (short tons/year) 120,000 120,000 130,000 Natural Gas Recovery (Mcf) 7 1 , 7 4 00,000 8,200,000 8,800,000 Compliance Costs

Capital Costs (2012$) $ 170 83 ,000,000 $180,000,000 $180,000,000 Annualized Costs (2012$) $ 150 85 ,000,000 $170,000,000 $210,000,000 Cost-Effectiveness (Single Pollutant Approach)

Methane (2012$ / short ton) $ 920 510 $980 $1,100 VOC (2012$ / short ton) $ 1,300 700 $1,400 $1,700 Cost-Effectiveness (Multipollutant Approach)

Methane (2012$ / short ton) $ 4 2 60 $490 $570 VOC (2012$ / short ton) $ 640 350 $690 $840

Impacts in 2025 Affected Sources 1 2 8 0,000 180,000 180,000 Emissions Reductions Methane Emissions Reduction (short tons/year) 3 4 3 0,000 400,000 470,000 VOC Emissions Reduction (short tons/year) 1 7 6 0,000 180,000 200,000 Natural Gas Recovery (Mcf) 16 8 , 0 9 00,000 19,000,000 23,000,000 Compliance Costs

Capital Costs (2012$) $2 8 3 0,000,000 $330,000,000 $330,000,000 Annualized Costs (2012$) $ 32 24 0,000,000 $420,000,000 $680,000,000 Cost-Effectiveness (Allocated Cost Approach)

Methane (2012$ / short ton) $ 94 73 0 $1,100 $1,400 VOC (2012$ / short ton) $1, 9 5 00 $2,300 $3,400 Cost-Effectiveness (Multipollutant Approach)

Methane (2012$ / short ton) $ 47 36 0 $530 $720 VOC (2012$ / short ton) $ 96 73 0 $1,200 $1,700

Because the fugitive emissions requirement s contribute a large proportion of the proposed rule’s costs and emissions reductions, Ta ble 3-9 presents additi onal analysis of the alternative survey and repair frequencies examin ed in the TSD. The TSD examines annual, semi-*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-20 annual (two times per year), and quarterly survey and repair requirements. Table 3-9 presents the
emissions reductions and costs for different combin ations of frequency of well-site provisions and provisions for compressor stations (gat hering and boosting, tran smission, and storage compressor stations).
Table 3-9 Detailed Comparison of Regulatory Alternatives for Fugitive Emissions at Well Sites and Compressor Stations
Frequency of Well Site Fugi tive Emissions Requirements Annual Frequency Semi-annual Frequency Quarterly Frequency 

### 2020 Methane VOC Methane VOC Methane VOC

Frequency of

Fugitive Emissions Requirements for Compressor

Stations Annual Frequency (short tons reduced) 22,000 5,800 31,000 8,200 39,000 11,000

Semi-annual Frequency (short tons reduced) 24,000 6,400 33,000 8,700 42,000 11,000

Quarterly Frequency (short tons reduced) 27,000 6,900 35,000 9,300 44,000 12,000

Annual Costs (2012$) Annual Frequency (annual costs) $27,000,000 $45,000,000 $83,000,000

Semi-annual Frequency (annual costs) $29,000,000 $47,000,000 $84,000,000

Quarterly Frequency (annual costs) $32,000,000 $49,000,000 $87,000,000

Frequency of Well Site Fugi tive Emissions Requirements Annual Frequency Semi-annual Frequency Quarterly Frequency 

### 2025 Methane VOC Methane VOC Methane VOC

Frequency of

Fugitive Emissions Requirements for Compressor

Stations Annual Frequency (short tons reduced) 140,000 38,000 200,000 54,000 260,000 70,000

Semi-annual Frequency (short tons reduced) 160,000 41,000 210,000 57,000 270,000 73,000

Quarterly Frequency (short tons reduced) 170,000 44,000 230,000 60,000 290,000 76,000

Annual Costs (2012$) Annual Frequency (annual costs) $170,000,000 $280,000,000 $520,000,000

Semi-annual Frequency (annual costs) $180,000,000 $290,000,000 $530,000,000

Quarterly Frequency (annual costs) $200,000,000 $310,000,000 $540,000,000*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-21 Three observations are worth noting. First, impacts fugitive emission requirements at well sites tend to outweigh impacts at compressor st ations. This is evident as cost and emissions impacts rise fast when increasi ng the frequency or inspections a nd repair at well sites than at compressor stations. Second, costs of the fugitive emissions program tend to scale linearly with increasing frequency. This results is largely explained by incr easing frequency not increasing capital costs but the increased frequency increases O&M type costs as a multiple of survey and repair visits. Last, the control efficiency increas ing from 40 to 60 to 80 percent for annual, semiannual, and quarterly, respectively, exhi bits decreasing returns to frequency.

3.5 Compliance Costs Estimated using 3 and 7 Percent Discount Rates

Table 3- 10 9 shows that the choice of discount rate ha s very minor effect on the nationwide annualized costs of the proposed option.

Table 3- 9 10 Annualized Costs using 3 and 7 Percent Discount Rates 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 $120,000,000 $120,000,000 $120,000,000 Fugitive Emissions $47,000,000 $46,000,000 $290,000,000 $290,000,000 Pneumatic Pumps $840,000 $690,000 $5,100,000 $4,200,000 Compressors $250,000 $230,000 $1,500,000 $1,400,000 Pneumatic Controllers $5,200 $4,000 $31,000 $24,000 Reporting and Recordkeeping $1,400,0 00 $1,400,000 $4,100,000 $4,100,000 Total $170,000,000 $170,000,000 $420,000,000 $420,000,000

The choice of discount rate has a small e ffect 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, compressors, and pneumatic controllers are sensitive to interest rate, but these constitute a relatively small part of th e total compliance cost estimates for the proposal.*** E.O. 12866 Review – Draft – Do Not C ite, Quote or Release During Review***

3-22 3.6 Detailed Impacts Tables
The following tables shows the full detail s of the costs and emissions reduction by
emissions sources for each re gulatory option in 2020 and 2025.*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***3-23Table 3-1011Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020Source/Emissions PointIncrementallyAffected UnitsNationwide Emissions Reductions National Costs (2012$)Methane (shorttons)VOC(short tons)HAP (shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,00014,000130,000130,000110,000110,00013132,900,0002,900,000$140,000,000$51,000,000$120,000,000$51,000,000Hydraulically FracturedWildcat and Delineation OilWells8708708,0008,0006,7006,70011180,000180,000$3,200,000$3,200,000$3,200,000$3,200,000Fugitive EmissionsWell Pads13,00022,00017,00017,0004,6004,800180180380,000390,000$11,000,000$18,000,000$26,000,000$25,000,000Gathering and BoostingStations2602605,5003,6001,5001,0005738120,00083,000$4,200,000$4,200,000$2,800,000$1,800,000Transmission CompressorStations21211,7001,10047311139,00026,000$340,000$340,000$440,000$260,000Pneumatic PumpsWell Pads3,000 5,400 1,500 57120,000 $5,900,000 $840,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations67 1,500 40 1 33,000 $470,000 $130,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations1 110 3 0 2,500 $72,000 $110,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations210 590 16 0 13,000 $48,000 $5,200Reporting and RecordkeepingAll 0 0 0 0 $0 $1,400,000TOTAL31,00040,000170,000170,000120,000120,0003102903,800,0003,700,000$170,000,000$83,000,000$150,000,000$85,000,000*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***3-24Table 3-1192Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025Source/Emissions PointIncrementallyAffected UnitsNationwide Emissions Reductions National Costs (2012$)Methane(short tons)VOC(short tons) HAP (short tons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs WithAddl. RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,00014,000130,000130,000110,000110,00013132,900,0002,900,000$140,000,000$51,000,000$120,000,000$51,000,000Hydraulically FracturedWildcat and DelineationOil Wells1,2001,20011,00011,0009,0009,00011240,000240,000$4,300,000$4,300,000$4,300,000$4,300,000Fugitive EmissionsWell Pads84,000140,000110,000110,00031,00032,0001,2001,2002,500,0002,600,000$68,000,000$110,000,000$160,000,000$160,000,000Gathering and BoostingStations1,6001,60033,00022,0009,1006,100340230740,000500,000$25,000,000$25,000,000$17,000,000$11,000,000Transmission CompressorStations13013010,0006,80028019086230,000150,000$2,100,000$2,100,000$2,600,000$1,600,000Pneumatic PumpsWell Pads18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations400 8,800 240 7 200,000 $2,800,000 $790,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations6 670 18 1 15,000 $430,000 $680,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations1,3003,500 97 3 80,000$290,000 $31,000Reporting and RecordkeepingAll 0 0 0 0 $0 $4,100,000TOTAL120,000180,000340,000330,000170,000160,0001,9001,8007,700,0007,400,000$280,000,000$230,000,000$320,000,000$240,000,000*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***3-25*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***3-26Table 3-1123Incrementally Affected Units, Emissions Reductions and Costs, Selected Option 2, 2020Source/Emissions PointIncrementallyAffectedUnitsNationwide Emissions Reductions National Costs (2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and Delineation OilWells870 8,000 6,700 1 180,000$3,200,000 $3,200,000Fugitive EmissionsWell Pads22,000 26,000 7,200 270 590,000 $18,000,000 $43,000,000Gathering and BoostingStations260 5,500 1,500 57 120,000$4,200,000 $2,800,000Transmission CompressorStations21 1,700 47 1 39,000 $340,000 $440,000Pneumatic PumpsWell Pads3,000 5,400 1,500 57120,000 $5,900,000 $840,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations67 1,500 40 1 33,000 $470,000 $130,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations1 110 3 0 2,500 $72,000 $110,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations210 590 16 0 13,000 $48,000 $5,200Reporting and RecordkeepingAll 0 0 0 0 $0$1,400,000TOTAL 40,000 180,000 120,000 4004,000,000 $180,000,000 $170,000,000*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***3-27Table 3-1134Incrementally Affected Units, Emissions Reductions and Costs, Selected Option 2, 2025Source/Emissions PointIncrementallyAffected UnitsNationwide Emissions Reductions National Costs (2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and DelineationOil Wells1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000Fugitive EmissionsWell Pads140,000 170,000 48,000 1,8003,900,000 $110,000,000 $270,000,000Gathering and BoostingStations1,600 33,000 9,100 340 740,000 $25,000,000 $17,000,000Transmission CompressorStations130 10,000 280 8 230,000 $2,100,000 $2,600,000Pneumatic PumpsWell Pads18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations400 8,800 240 7 200,000 $2,800,000 $790,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations6 670 18 1 15,000 $430,000 $680,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations1,300 3,500 97 3 80,000 $290,000 $31,000Reporting and RecordkeepingAll 0 0 0 0 $0$4,100,000TOTAL 180,000 400,000 180,000 2,5009,000,000 $330,000,000 $420,000,000*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***3-28Table 3-1415Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020Source/Emissions PointIncrementallyAffectedUnitsNationwide Emissions Reductions National Costs (2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and Delineation OilWells870 8,000 6,700 1 180,000$3,200,000 $3,200,000Fugitive EmissionsWell Pads22,000 34,000 9,600 360 780,000 $18,000,000 $81,000,000Gathering and BoostingStations260 7,300 2,000 76 170,000$4,200,000 $5,400,000Transmission CompressorStations21 2,300 63 2 52,000 $340,000 $780,000Pneumatic PumpsWell Pads3,000 5,400 1,500 57120,000 $5,900,000 $840,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations67 1,500 40 1 33,000 $470,000 $130,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations1 110 3 0 2,500 $72,000 $110,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations210 590 16 0 13,000 $48,000 $5,200Reporting and RecordkeepingAll 0 0 0 0 $0$1,400,000TOTAL 40,000 190,000 130,000 5104,200,000 $180,000,000 $210,000,000*** E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***3-29Table 3-1615Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025SourceIncrementallyAffected UnitsNationwide Emissions Reductions National Costs (2012$)Methane(short tons)VOC(short tons)HAP(shorttons)Methane (metrictons CO2Eq.) Capital CostsAnn. Costs With Addl.RevenuesWell CompletionsHydraulically FracturedDevelopment Oil Wells14,000 130,000 110,000 13 2,900,000 $140,000,000 $120,000,000Hydraulically FracturedWildcat and DelineationOil Wells1,200 11,000 9,000 1 240,000 $4,300,000 $4,300,000Fugitive EmissionsWell Pads140,000 230,000 64,000 2,4005,200,000 $110,000,000 $510,000,000Gathering and BoostingStations1,600 44,000 12,000 460 990,000 $25,000,000 $32,000,000Transmission CompressorStations130 14,000 380 11 310,000 $2,100,000 $4,700,000Pneumatic PumpsWell Pads18,000 32,000 9,000 340 740,000 $36,000,000 $5,100,000Gathering and BoostingStations0 0 0 0 0 $0 $0Transmission and StorageCompressor Stations0 0 0 0 0 $0 $0Pneumatic Controllers -Natural Gas Transmissionand Storage Stations400 8,800 240 7 200,000 $2,800,000 $790,000Reciprocating CompressorsNatural Gas Transmissionand Storage Stations6 670 18 1 15,000 $430,000 $680,000Centrifugal CompressorsNatural Gas Transmissionand Storage Stations1,300 3,500 97 3 80,000 $290,000 $31,000Reporting and RecordkeepingAll 0 0 0 0 $0$4,100,000TOTAL 180,000 470,000 200,000 3,20011,000,000 $330,000,000 $680,000,000***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-1 4 BENEFITS OF EMISSIONS REDUCTIONS

4.1 Introduction

The proposed NSPS amendments are expected to prevent new emissions from the oil and gas sector. For the proposed NSPS, there 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 pr event 180,000 tons of methane, 120,000 tons of VOC, and 400 tons of HAP from new sources in 2020. In 2025, the NSPS would prevent 400,000 tons of methane, 180,000 tons of VOC, and 2,500 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 metric tons in 2025. As described in the subsequent sections, these pollutants are associated with substantial climate, health, and welfare effects. The 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 propos ed NSPS are anticipated to have minor emissions disbenefits (e.g., in creases in emissions of carbon dioxide (CO 2 ), nitrogen oxides (NO X ), PM, carbon monoxide (CO), and to tal hydrocarbons (THC)) and emission changes associated with the energy system impacts.

While we expect that the avoided VOC emissions will also result in improvements in air quality and reduce health and welfare effects asso ciated with exposure to ozone, fine particulate matter (PM 2.5 ), and HAP, we have determined that quantification of the VOC-related health benefits cannot be accomplished for this rule in a defensible way. This is not to imply that these benefits do not exist; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. With the data available, we are not able to provi de a credible health benefits estimates for this rule, due to the differences in the locations of oil and natural gas emission points relative to existing information and the highly localized natu re of air quality responses associated with HAP***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-2 and VOC reductions. 17 In this chapter, we pr ovide a qualitative assessmen t of the health benefits associated with reducing exposure to these polluta nts, as well as visi bility impairment and ecosystem benefits. Table 4-1 summarizes the quantified and unquantified benefits in this analysis.

Table 4-1 Climate and Human Health Effe cts of Emission Reductions from this Proposal

Category Specific Effect Effect Has Been Quantified Effect Has Been Monetized More Information Improved Environment

Reduced climate effects Global climate impacts from methane and carbon dioxide (CO 2 ) — 1  Marten et al. (2015), 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 elicit ation 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 as thma (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 da ys (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

17 Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the effect that those emissi ons 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, the benefit-per-ton estimates for VOC emission reductions in that study are derived from total VOC emissions across a ll sectors. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 and the highly localized nature of air quality responses associated with VOC reductions, thes e factors lead us to conclude that the available VOC benefit-per-ton estimates are not appropriate to calcu late monetized benefits of these ru les, even as a bounding exercise.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-3 Category Specific Effect Effect Has Been Quantified Effect Has Been Monetized More Information Reproductive and developmental effects (e.g., low birth weight, pre- term births, etc) — — PM ISA 2,4 Cancer, mutagenicity, and genotoxicity effects — — PM ISA 2,4

Reduced incidence of mortality from exposure to ozone Premature mortality based on short-term study estimates (all ages) — — Ozone ISA 3 Premature mortality based on long-term study estimates (age 30–99) — — Ozone ISA 3

Reduced incidence of morbidity from exposure to ozone Hospital admissions—respiratory causes (age > 65) — — Ozone ISA 3 Hospital admissions—respiratory causes (age <2) — — Ozone ISA 3 Emergency department vi sits for asthma (all ages) — — Ozone ISA 3 Minor restricted-activity da ys (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 sy stem effects — — Ozone ISA 2 Reproductive and developmen tal 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 ornament al 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 chang es in CO 2 emissions. 2 We assess these benefits qualitatively because we do not have sufficient confidence in available data or methods. 3 We assess these benefits qualitatively due to data limitations fo r this analysis, but we have quantified them in other analyse s. 4 We assess these benefits qualitatively because current evidence is only suggestive of causality or there are other significant concerns over the strength of the association.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-4 4.2 Emission Reductions from the Proposed NSPS

As described in Section 2 of this RIA, oil a nd natural gas operations in the U.S. include a variety of emission points for methane, VOC, a nd HAP, including wells, well sites, processing plants, compressor stations, stor age equipment, and transmissi on and distribution lines. These emission points are located throughout much of th e country with significa nt concentrations in particular regions. For example, wells and processi ng plants are largely conc entrated 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 custom ers are frequently located within areas of high population density.

In implementing this rule, emission controls may lead to reductions in ambient PM 2.5 and ozone below the National Ambient Air Quality St andards (NAAQS) in some areas and assist other areas with attaining th e 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 attainme nt status without air quality modeling data. 18 Because the NAAQS RIAs also calculate ozone a nd PM benefits, there are important differences worth noting in the design and analytical objec tives of each RIA. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control stra tegies for different sources. 19 In short, NAAQS RIAs hypothesize, but do not predict, the control st rategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly re sult in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not in tended to be added to the costs and benefits of other regulations that result in specific co sts of control and emissi on 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.

18 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. 19 In short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not intend ed to be added to the costs and benefits of other regulations that result in specific costs of control and emission 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-5 By contrast, the emission reduc tions for implementation rules , including this rule, are generally from a specific class of well-characterized sources. In ge neral, EPA is more confident in the magnitude and location of the emission re ductions for implementation rules rather than illustrative NAAQS analyses. Emission reductions achieved under these and other promulgated rules will ultimately be reflected in the baseli ne of future NAAQS anal yses, which would reduce
the incremental costs and benefits as sociated with attaining the NAAQS. EPA remains forward looking towards the next iteration of the 5-year review cycle for the NAAQS, and as a result does not issue updated RIAs for existing NAAQS that retroactively update the baseline for NAAQS implementation. For more informati on on the relationship between the NAAQS and rules such as analyzed here, please see Sec tion 1.3.4 of the PM NAAQS RIA (U.S. EPA, 2012c).

Table 4-2 shows the direct emission reductio ns anticipated for this rule, across the regulatory options examined in th e rule. It is important to note that these benefits accrue at different spatial scales. HAP em ission reductions reduce exposure to carcinogens and other toxic pollutants primarily near the emission source. Reducing VOC emissions would reduce precursors to secondary formation of PM 2.5 and ozone, which reduces expos ure to these pollutants on a regional scale. Climate effects associated with long-lived greenhous e gases like methane generally do not depend on the lo cation of the emission of the ga s, and have global impacts. Methane is also a precursor to glob al background concentrations of ozone.

Table 4-2 Direct Emission Reductions from the Proposed NSPS in 2020 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) 310 290 400 510 Methane (metric tons) 150,000 160,000 170,000 Methane (metric tons CO 2 Eq.) 3, 8 7 00,000 4,000,000 4,200,000 2025 Methane (short tons/year) 3 4 3 0,000 400,000 470,000 VOC (short tons/year) 1 7 6 0,000 180,000 200,000 HAP (short tons/year) 1, 9 8 00 2,500 3,200 Methane (metric tons) 3 1 0 0,000 360,000 430,000 Methane (metric tons CO 2 Eq.) 7, 7 4 00,000 9,000,000 11,000,000***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-6 4.3 Methane

4.3.1 Methane climate effects and valuation
Methane is the principal component of natura l gas. Methane is also a potent greenhouse gas (GHG) that once emitted into the atmosphere absorbs terrestrial infr ared radiation that contributes to increased global warming and continuing climate ch ange. Methane reacts in the atmosphere to form ozone and ozone also impact s global temperatures. Me thane, in addition to other GHG emissions, contributes to warming of the atmosphere, which over time leads to increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of global glaciers and ice, increasingly severe we ather events, such as hurricanes of greater intensity, and sea level rise, among other impacts.

According to the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report (AR5, 2013), changes in methane con centrations since 1750 contributed 0.48 W/m 2 of forcing, which is about 17 percent of all globa l forcing due to increa ses in anthropogenic GHG concentrations, and which makes methane the se cond leading long-lived climate forcer after
CO 2 . However, after accounting for changes in othe r 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 about 30 percent of the contemporaneous forcing due to historical gree nhouse gas emissions.

Processes in the oil and gas category emit significant amounts of methane. The Inventory
of U.S. Greenhouse Gas Emissions and Sinks : 1990-2013 (published April 2015) estimates 2013
methane emissions from Petroleum and Natural Ga s Systems (not includi ng petroleum refineries and petroleum transporta tion) to be 182 MMt CO 2 Eq. In 2013, total methane emissions from the oil and gas industry represented nearly 29 perc ent 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 larg est contributor to U.S. anthropogenic methane emissions (U.S. EPA, 2015c).

It is important to note that the 2013 GHG em issions estimates do not include methane emissions from hydraulically fractured and re-fra ctured oil well completions due to lack of available data when the 2013 GHG Inventory esti mate was developed. The estimate in this***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-7 proposed rule includes an adjustment for hydr aulically fractured oil wells, and such an adjustment is also being considered as a pl anned 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 hydrau lically fractured and re -fractured oil well completions, is approximately 185 MMt CO 2 Eq.

Actions taken to comply with the proposed N SPS are anticipated to significantly decrease methane emissions from the oil and natural gas sector in the United St ates. The proposed NSPS is expected to reduce methane emissions by about 180,000 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 400,000 short tons or approximate ly 360,000 metric tons methane (or 9.0 MMt CO 2 Eq.). These reductions in 2020 an d 2025 represent about 2 percent and 5 percent, respectively, of the GHG emissions for this sector (excludi ng petroleum refineries and petroleum transportation) reported in the 1990-2013 U.S. GHG Inventory (182 MMt CO 2 Eq.).

We calculated the global social benefits of methane emissions reductions expected from the proposed NSPS using estimates of the social cost of methane (SC-CH 4 ), a metric that estimates the monetary value of impacts associat ed with marginal changes in methane emissions in a given year. It includes a wide range of antic ipated 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 for heating and increased costs for air conditioning. The SC-CH 4 estimates applied in this anal ysis were developed by Marten et al. (2014) and are discussed in greater detail below.

A similar metric, the social cost of CO 2 (SC-CO 2 ), provides important context for understanding the Marten et al. SC-CH 4 estimates. Estimates of the SC-CO 2 have been used by EPA and other federal agencies to value the impacts of CO 2 emissions changes in benefit cost analysis for GHG-related rule makings since 2008. The SC-CO 2 is a metric that estimates the monetary value of impacts associat ed with marginal changes in CO 2 emissions in a given year.
Similar to the SC-CH 4 , it includes a wide range of anticipat ed climate impacts, such as net***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-8 changes in agricultural productiv ity, property damage from increas ed flood risk, and changes in energy system costs, such as reduced costs for heating and increased costs for air conditioning. It is used to quantify the benefits of reducing CO 2 emissions, or the disbenefit from increasing emissions, in regulatory impact analyses.

The SC-CO 2 estimates were developed over many year s, using the best science available, and with input from the public. Specifically, an interagency working gr oup (IWG) that included EPA and other executive branch agencies 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 versions of each IAM. The 2013 update did not revisit the 2010 modeling decisions with regards to the discount rate, refe rence case socioeconomic and emission scenarios, and equilibrium climate sensitivity distributi on. Rather, improvements in the way damages are
modeled are confined to those that have been inco rporated 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 discussion of the methods used to develop these estimates and the current SC-CO 2 TSD presents and discusses the 2013 update (including recent minor techni cal corrections to the estimates). 20

The 2010 SC-CO 2 TSD noted a number of limitations to the SC-CO 2 analysis, including the incomplete way in which the IAMs capture cat astrophic and non-catastr ophic impacts, their incomplete treatment of adaptation and technologi cal change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk aversion. Currently IAMs do not assign value to all of the important physical, eco logical, and economic impacts of climate change recognized in the climate change literature due to a lack of precise info rmation on the nature of damages and because the science incorporated in to these models understandably lags behind the most recent research. Nonetheless, these esti mates and the discussion of their limitations represent the best availa ble information about the social benefits of CO 2 reductions to inform

20 Both the 2010 SC-CO 2 TSD and the current SC-CO 2 TSD are available at:https://www.whitehouse.gov/omb/oira/social-cost-ofcarbon https://www.whitehouse.gov/omb/inforeg_regpol_agency_review***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-9 benefit-cost analysis. Th e new versions of the models offer some improvements in these areas, although further work is warranted.

Accordingly, EPA and other agencies conti nue 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 supporting 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 develop the
SC-CO 2 estimates through a separate comment period that ended on February 26, 2014. 21

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 analys is. With the release 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. 22 The NRC review will be informed by the public comments received and focus on the t echnical 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 comments on SC-CO 2 and announcement of the NRC process, OMB poste d a revised TSD that includes two minor
technical corrections to the current estimates. On e technical correction addressed an inadvertent omission of climate change damages in the last year of analysis (2300) in one model and the second addressed a minor indexing error in an other model. On average the revised SC-CO 2 estimates are one dollar less than the mean SC-CO 2 estimates reported in the November 2013 TSD. The change in the estimates associated wi th the 95th percentile estimates when using a 3

21 For the IWG’s response to comments, see https://w ww.whitehouse.gov/sites/de fault/files/omb/inforeg/sccresponse-to-comments-final-july-2015.pdf.
22 See https://www.whitehouse.gov/blog/2015/07/02/esti mating-benefits-carbon-dioxide-emissions-reductions.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-10 percent discount rate is slightly larger, as thos e estimates are heavily in fluenced by the results
from the model that was aff ected by the indexing error.

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). 23 The first three values are based on the average SC-CO 2 from the three IAMs, at discount ra tes of 5, 3, and 2.5 percent, resp ectively. Estimates of the SC-CO 2 for several discount rates are included becau se the literature s hows 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 different generations). The fourth value is the 95 th percentile of the SC-CO 2 across all three models at a 3 percent discount rate. It is incl uded to represent higher-than-exp ected impacts from temperature change further out in the tails of the SC-CO 2 distribution. The SC-CO 2 increases over time because future emissions are expected to produce larger incremental damages as economies grow and physical and economic systems become more stre ssed in response to greater climate change.

A challenge particularly releva nt 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 radiativ e 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 mainly reflects differences in the radiative e fficiency of gases and differences in their atmospheric lifetimes. While the 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 purely physical basis,
there are several well-documented lim itations in using it to value non-CO 2 GHG benefits, as
discussed in the 2010 SC-CO 2 TSD and previous rulemaki ngs (e.g., U.S. EPA 2012b, 2012d). 24

23 The current version of the SC-CO 2 TSD is available at: <link to be ad ded when available>. The TSDs present SC-CO 2 in $2007. The estimates were adjusted to 2012$ using the GDP Implicit Price Deflator (1.0804) . Also available at: http://www.bea.gov/iTable/index_nipa.cfm http://www.gpo.gov/fdsys/pkg/ECONI-2013- 02/pdf/ECONI-2013-02-Pg3.pdf . The SC-CO 2 values have been rounded to two significant digits. Unrounded numbers from the 2013 SCC TSD were adjusted to 2012$ and used to calculate the CO 2 benefits.
24 See also Reilly and Richards, 1993; Schmalensee, 1993; Fankhauser, 1994; Marten and Newbold, 2012.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-11 In particular, several recent studies found that GWP-weighted benefit estimates for methane are likely to be lower than the estimates derived us ing directly modeled social cost estimates for these gases. Gas comparison metrics, such as the GWP, are designed to measure the impact of
non-CO 2 GHG emissions relative 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. 2015 Figure 4-1 Path from GHG Emis sions to Monetized Damages

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

Also of concern is the fact that the assu mptions made in estimating the GWP are not
consistent with the assu mptions underlying SC-CO 2 estimates in general, and the SC-CO 2 estimates developed by the IWG more specificall y. For example, the 100-year time horizon usually used in estimating the GWP is less th an the approximately 300-year horizon the IWG used in developing the SC-CO 2 estimates. The GWP approach also treats all impacts within the time horizon equally, independent of the time at wh ich they occur. This is inconsistent with the role of discounting in econom ic analysis, which accounts for a basic preference for earlier over later gains in utility and expecta tions regarding future levels of economic growth. In the case of methane, which has a relatively short lifetime compared to CO 2 , the temporal independence of***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-12 the GWP could lead the GWP appr oach to underestimate the SC-CH 4 with a larger downward bias under higher discount ra tes (Marten and Newbold, 2012). 25

EPA sought public comments on the valuation of non-CO 2 GHG impacts in previous rulemakings (e.g., U.S. EPA 2012b, 2012d) . In general, the comment ers 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 wi th the GWP-approach, as discussed above, and encouraged the use of directly -modeled estimates of the SC-CH 4 to overcome those challenges.

EPA had cited several researchers that had di rectly 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 literatu re. EPA found considerable variation among these published estimates in terms of th e models and input assumptions they employ (U.S. EPA, 2012d). These studies differed in the emissions perturbation year, employed a wide range of constant and variable di scount rate specifica tions, and considered a range of baseline
socioeconomic and emissions scenarios that ha ve been developed over the last 20 years. Furthermore, at the time, none of the other pub lished 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 unde rlying science since their publication.

Therefore, EPA concluded that the GWP appro ach would serve as an interim method of analysis until directly modeled social cost estimates for non-CO 2 GHGs, consistent with the SCCO 2 estimates developed by the IWG, were deve loped. EPA presented GWP-weighted estimates in sensitivity analyses rather than the main benefit-cost analyses. 26

25 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. 26 For example, the 2012 New Sour ce Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutant s 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 jo intly 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 metric tons in 2050, see http://www .gpo.gov/fdsys/pkg/FR-2012-10-15/pdf/2012-21972.pdf***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-13 Since then, a paper by Marten et al. (2014) provided the first set of published SC-CH 4 estimates in the peer-reviewed literature that are consistent with the modeling assumptions underlying the SC-CO 2 estimates. 27 Specifically, the estimati on approach of Marten et al. used the same set of three IAMs, five socioeconomic and emissions scenarios, equilibrium climate sensitivity distribution, three cons tant discount rates, and aggrega tion approach used by the IWG to develop the SC-CO 2 estimates. The aggregation method i nvolved distilling the 45 distribution s of the SC-CH 4 produced for each emissions year into four estimates: the mean across all models and scenarios using a 2.5 percent, 3 percen t, and 5 percent discount rate, and the 95 th percentile of the pooled estimates from all models and scenarios using a 3 per cent discount rate. The atmospheric lifetime and radiative ef ficacy of methane used by Marten et al. is based on the estimates reported by the IPCC in their Fourth Assessment Re port (AR4, 2007), including an adjustment in the radiative efficacy of methane to account for its role as a precursor for tropospheric ozone and stratospheric water. Thes e 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 updates GWP estimates with each new assessment, and in the most recen t assessment, AR5, the latest estimate of the methane GWP ranged from 28-36, compared to a GW P 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 change s in the correction factor applied to methane’s
GWP to reflect the effect of methane emissions on other climatically impo rtant substances such as tropospheric ozone and stratos pheric water vapor. In addition, the range presented in the latest IPCC report reflects different ch oices regarding whether to acc ount for how biogenic and fossil methane have different carbon cycle effects, a nd for whether to account for climate feedbacks on the carbon cycle for both methane and CO 2 (rather than just for CO 2 as was done in AR4). 28 , 29

27 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. 28 Climate Change 2013: The Physical 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 (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA. 29 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).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-14 Marten et al. (2014) discuss these estimates, (SC-CH 4 estimates presented below in Table 4-3), and compare them with other recent estimates in the literature. 30 The authors noted that a direct comparison of their estimates with all of the other published estima tes 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 th an 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 comparison 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. , 2015 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 described above. See Corrigendum to Marten et al . (2014) , erratum for more details http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550

.

30 Marten et al. (2015) estimates are presented in 2007 dollars. Th ese estimates were adjusted for inflation using National Income and Product Accounts Tables, Table 1.1.9, Implicit Price Deflators for Gross Domestic Product (US Department of Commerce, Bureau of Economic Analysis), http://www.bea.gov/iT able/index_nipa.cfm (1.0804) Accessed 3/3/15.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-15 The application of directly modeled estimates from Marten et al. (2014) to benefit-cost analysis of a regulatory action is analogous to the use of the SC-CO 2 estimates. Specifically, the
SC-CH 4 estimates in Table 4-3 are used to mone tize the benefits of reductions in methane emissions expected as a result of the proposed rulemaking. Forecast changes in methane emissions in a given year, expected as a resu lt of the proposed regulat ory action, are multiplied by the SC-CH 4 estimate for that year. To obtain a present value estimate, the monetized stream
of future non-CO 2 benefits are discounted back to the an alysis year using the same discount rate
used to estimate the so cial 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. (2014) nonCO 2 social cost estimates in regulatory analys is and received respons es that supported this application. Three reviewers cons idered seven charge questions that covered issues such as EPA’s interpretation of the Marten et al. estimates, the consistency of the estimates with the SCCO 2 estimates, EPA’s characterization of the li mits of the GWP-approach to value non-CO 2 GHG impacts, and the appropria teness 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 c onsistent 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 revi ewers briefly considered the limitations in the
SC-CO 2 methodology (e.g., those discussed earlier in this section) and not ed that because the
SC-CO 2 and SC-CH 4 methodologies are similar, the limitati ons also apply to the resulting SCCH 4 estimates. Two of the reviewers concl uded 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, si milar to the discussion provided for SC-CO 2 and other economic analyses. All three reviewers encour aged continued 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 improvement 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. The fact that the re viewers agree that the SC-CH 4 estimates are generally consistent***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-16 with the SC-CO 2 estimates that are recommende d by OMB’s guidance on valuing CO 2 emissions reductions, leads EPA to concl ude that use of the SC-CH 4 estimates is an analytical improvement over excluding methane emissions from the monetiz ed 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. (2014) SC-CH 4 estimates to value methane impacts expected from this proposed rulemaking and has included those benefits in the main benefits analysis. EPA seek s comments on the use of these directly modeled estimates, from the peer-reviewed literat ure, for the social cost of non-CO 2 GHGs in this RIA.

The methane benefits are presented belo w in Table 4-4 for years 2020 and 2025 across regulatory options. Applying this approach to the methane reducti ons estimated for the proposed NSPS option, the 2020 methane benefits vary by discount rate and range from about $93 million to approximately $550 million; the mean SC-CH 4 at the 3 percent disco unt rate results in an estimate of about $210 million in 2020. The methane benefits increase for the proposed option in 2025 and likewise vary by discount rate, rangi ng from about $250 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 $550 million in 2025.

Table 4-4 Estimated Global Benefits of Me thane 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 0.3 1 0 0.16 0.36 0.17 0.43

Million metric tonnes of CO 2 Eq. 3. 8 7 7. 7 4 4.0 9.0 4.2 11 5% (average) $8 8 7 $2 2 1 0 $93 $250 $99 $300 3% (average) $ 200 190 $4 6 5 0 $210 $550 $220 $640 2.5% (average) $260 $ 60 58 0 $280 $700 $290 $830 3% (95 th percentile) $520 $1,200 $550 $1,400 $590 $1,700
*The SC-CH 4 values are dollar-year and em issions-year specific. SC-CH 4 values represent only a partial accounting of climate impacts.
The vast majority of this pr oposal’s climate-related benefits are associated with methane reductions, but some climate-related impacts ar e expected from the proposal’s secondary air impacts. The secondary impacts are discussed in Section 4.7.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-17 Methane is also a precursor to ozone. In remote areas, methane is a dominant precursor to tropospheric ozone formation (U.S. EPA, 2013). A pproximately 40 percent of the global annual mean ozone increase since preindustrial times is believed to be due to anthropogenic methane (HTAP, 2010). Projections of futu re emissions also indicate that methane is likely to be a key
contributor to ozone concentrations in the future (HTAP, 2010). Unlike NO X and VOCs, which affect ozone concentrations regionally and at hour ly time scales, methane emissions affect ozone concentrations globally and on decadal time scal es given methane’s relatively long atmospheric lifetime (HTAP, 2010). Reducing methane emissi ons, 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 concentra tions 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 gr eater reductions in local ozone concentrations (West and Fiore, 2005; West et al. , 2006; Fiore et al. , 2008; Dentener et al. , 2005; Shindell et al.
, 2005, 2012; UNEP/WMO, 2011). The health, welfare, a nd climate effects associated with ozone are described in the preceding se ctions. Without detailed air qua lity modeling, we are unable to estimate the effect that reducing methane will have on ozone concentrations at particular
locations.

Recently, a paper was published in the peer-revi ewed scientific literature that presented a range of estimates of the monetized ozone-rel ated 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. fi nd 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 mode ling underlying the SC-CO2 and SC-CH4 estimates discussed above, and required a number of additi onal assumptions such as baseline mortality rates and mortality response to ozone concentra tions. The Sarofim et al. (2015) study may have implications for this benefits analysis as it pr ovides a potential approach to estimating the ozone related mortality benefits resulting from the me thane reductions expected from this proposed***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-18 rulemaking. The EPA requests comment on Sarofim et al.’s approach to estimating the ozone related mortality benefits of methane emissions reductions, including techni cal 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 por tion of VOC emission contributes
to ambient PM 2.5 levels as organic carbon aerosols (U.S. EPA, 2009a). Therefore, reducing these
emissions would reduce PM 2.5 formation, human exposure to PM 2.5 , and the incidence of PM 2.5
- related health effects. However, we have not quantified the PM 2.5 -related benefits in this analysis. Analysis of organic carbon measurements suggest only a fraction of secondarily formed organic carbon aerosols are of anthropogenic origin. The current state of the science of secondary organic carbon aerosol formation indicates that anthropogenic VOC contribution to secondary organic carbon aerosol is often lower than the biogenic (natur al) contribution. Given that a fraction of secondarily formed organic carbon ae rosols is from anthropogenic VOC emissions and the extremely small amount of VOC emissions from this sect or relative to the entire VOC inventory it is unlikely this sect or has a large contribution to ambient secondary organic carbon aerosols. Photochemical models typically estima te secondary organic carbon from anthropogenic VOC emissions to be less than 0.1 μg/m 3

. Due to data limitations regarding potentia l locations of new and modified sources affected by this rulemaking, we did not perform air quality modeling for this rule needed to quantify the PM 2.5 benefits associated with reducing VOC emissions. Due to the high degree of variability in the responsiveness of PM 2.5 formation to VOC emission reductions, we are unable to estimate the effect that reducing VOC will have on ambient PM 2.5 levels without air quality modeling. However, we provide the discussion below for cont ext 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 av oiding mortality and respiratory morbidity.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-19 Researchers have associated PM 2.5 - exposure with adverse hea lth effects in numerous toxicological, clinical and epid emiological studies (U.S. EPA, 2009a). When adequate data and resources are available, EPA gene rally quantifies several health e ffects associated with exposure
to PM 2.5 (e.g., U.S. EPA (2011g)). 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; wh ich result in hospital and ER visits, lost work days, restricted activity days, and respirator y symptoms. Although EPA has not quantified these effects in previous benefits an alyses, 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 resp iratory effects (U.S. EPA, 2009a).

When EPA quantifies PM 2.5 -related benefits, the Agency as sumes that all fine particles, regardless of their chemical composition, are eq ually potent in causing premature mortality because the scientific evidence is not yet sufficien t to allow differentiation of effect estimates by particle type (U.S. EPA, 2009a). Based on our review of the current body of scientific 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 underlying epidemiology studies.

Previous studies have estimated the m onetized 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, a nd Hubbell, 2009), and these estimates can provide useful context for this ru lemaking. Using the estimat es in Fann, Fulcher, and Hubbell (2009), the monetized benefit-per-ton of reducing VOC emissions in nine urban areas of the U.S. ranges from $560 in Seattle, WA to $5,700 in San Joaquin, CA, with a national average of $2,400. These estimates assume a 50 percent reducti on in VOC, the Laden et al. (2006) mortality function (based on the Harvar d Six Cities study, a large cohort epidemiology study in the Eastern U.S., an analysis year of 2015, a 3 percent di scount rate, and 2006$). Additional benefit-per-ton estimates are available from this dataset using alternate assumptions regarding the relationship between PM 2.5 exposure and premature mortality from empirical studies and supplied by experts (e.g., Pope et al. , 2002; Laden et al. , 2006; Roman et al. , 2008).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-20 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 bot h well-designed and extensively peer reviewed, and EPA provides the benefit esti mates derived from expert opinions in Roman et al. (2008) as a characterization of uncertainty. As shown in Table 4-5, the range of VOC benefits that reflects the range of epid emiology studies and the range of the urban areas is $300 to $7,500 per ton of VOC reduced (2012$). 31 Since these estimates were presented in the 2012 Oil and Gas NSPS RIA (U.S. EPA, 2012b), we updated our met hods 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 population data. 32 Because these updates would not lead to significant changes in the benef it-per-ton estimates for VOC, we have not updated them here.

While these ranges of benefit- per-ton estimates provide usef ul context, the geographic
distribution of VOC emissions fr om 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 derive d from total VOC emissions across all sectors. 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 pe r ton estimates are not appropriate to calculate moneti zed benefits of this rule, even as a bounding exercise.

31 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 in formation regarding EPA’s current VSL estimate, please see Section 5.6.5.1 of the RIA for the PM NAAQS RIA (U.S. EPA, 2012c). EPA continues to work to update its guidance on valuing mortality risk reductions.

32 For more information regarding these updates, please s ee Section 5.3 of the RIA for the final PM NAAQS (U.S. EPA, 2012c).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***4-21Table 4-5 Monetized Benefits-per-Ton Estimatesfor VOC based on Previous Modeling in 2015 (2012$)AreaPopeet al.(2002)Ladenet al.(2006)ExpertAExpertBExpertCExpertDExpertEExpertFExpertGExpertHExpertIExpertJExpertKExpertLAtlanta $660 $1,600 $1,700 $1,300 $1,300 $920 $2,100 $1,200 $780 $980 $1,300 $1,000 $260 $1,000Chicago $1,600 $4,000 $4,200 $3,300 $3,200 $2,300 $5,300 $3,000 $1,900 $2,400 $3,200 $2,600 $640 $2,500Dallas $320 $790 $830 $650 $630 $450 $1,000 $580 $380 $480 $630 $510 $130 $490Denver $770 $1,900 $2,000 $1,500 $1,500 $1,100$2,400 $1,400 $910 $1,100 $1,500 $1,200 $300 $910NYC/ Philadelphia $2,300 $5,600 $5,900$4,600 $4,500 $3,200 $7,300 $4,100 $2,700 $3,400 $4,500 $3,600 $890 $3,300Phoenix $1,100 $2,700 $2,800 $2,200 $2,100 $1,500 $3,500 $2,000 $1,300 $1,600 $2,100 $1,700 $420 $1,600Salt Lake $1,400 $3,300 $3,500 $2,700 $2,700 $1,900 $4,400 $2,500 $1,600 $2,000 $2,700 $2,200 $570 $2,100San Joaquin $3,100 $7,500 $7,900 $6,100 $6,000 $4,300 $9,700 $5,500 $3,600 $4,500 $6,000 $4,900 $1,400 $4,600Seattle $300 $730 $770 $570 $590 $420 $950 $540 $350 $440 $580 $470 $120 $350National average $1,300 $3,200 $3,400 $2,600 $2,600 $1,800 $4,200 $2,300 $1,500 $1,900 $2,500 $2,100 $520 $1,900* These estimates assumed a 50 percent reduction in VOC emissions, an analysis year of 2015, and a 3 percent discount rate. Allestimates are rounded to twosignificant digits. These estimates have been adjusted from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currencyyear and EPA’s current VSLestimate. 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 estimateswould be approximately 9 percent lower. Assuming a 75 percentreduction in VOC emissionswould increase the benefit-per-ton estimates by approximately 4 percent to 52 percent. Assuming a 25 percent reduction in VOC emissions would decrease thebenefit-per-ton estimates by 5 percent to 52 percent. EPA generallypresents a range of benefits estimates derived from the expert functions from Romanet al.(2008) as a characterization of uncertainty.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-22 4.4.2 Organic PM welfare effects
According to the previous residual risk a ssessment for this sector (U.S. EPA, 2012a), persistent and bioaccumulative HAP reported as emissions from oil and gas operations include polycyclic organic matter (POM). POM defines a broad class of com pounds that includes polycyclic aromatic hydrocarbon compounds (PAHs). Several significant eco logical effects are associated with deposition of or ganic particles, including persiste nt 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 bioaccu mulate in freshwater, flora, and fauna. The uptake of organics depends on the plant species, site of deposition, physical and chemical properties of the organic compound and prevailing environmental conditions (U.S. EPA, 2009a). PAHs can accumulate to high enough concentrations in some coastal environments to pose an
environmental health threat that includes cancer in fish populations , toxicity to organisms living in the sediment and risks to those (e.g., migr atory birds) that consume these organisms. Atmospheric deposition of particle s is thought to be the major s ource 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 atmospherica lly-associated pollutant burden can then be toxic to aquatic biota. The cont ribution of atmospherically deposited PAHs to aquatic food webs was demonstrated in hi gh elevation mountain lakes with 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 com ponents (air, snow, water, sediment, lichen, conifer needles, and fish) in eight core nationa l parks. The study concluded that bioaccumulation of semi-volatile organic com pounds occurred throughout park ecosystems, an elevational gradient in PM deposition exists with greater accumulation in higher altitude areas, and contaminants accumulate in proximity to indivi dual agriculture and industry sources, which is***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-23 counter to the original working hypothesis that most of the cont aminants would originate from Eastern Europe and Asia.

4.4.3 Visibility Effects
Reducing secondary formation of PM 2.5 from VOC emissions would improve visibility throughout the U.S. Fine particles with significant light-e xtinction efficiencies include sulfates, nitrates, organic carbon, elemental carbon, and so il (Sisler, 1996). Suspended particles and gases degrade visibility by scattering and absorbing ligh t. Higher visibility impairment levels in the East are due to generally higher co ncentrations of fine particles, particularly sulfates, and higher average relative humidity levels. Vi sibility has direct significance to people’s enjoyment of daily
activities and their overall sense of wellbeing. Good visibility increases the quality of life where individuals live and work, and wh ere they engage in recreational activities. Previous analyses (U.S. EPA, 2006b; U.S. EPA, 2011a; U.S. EPA, 2011g; U.S. EPA, 2012c) show that visibility benefits are a significant welfar e benefit category. Without air qua lity modeling, we are unable to estimate visibility related benefits, nor are we able to determine whether VOC emission reductions would be likely to ha ve a significant impact on visibil ity in urban areas or Class I

areas.

4.5 VOC as an Ozone Precursor
This rulemaking would reduce emissions of VOC , which are also precursors to secondary
formation of ozone. Ozone is not em itted 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 ozone formation, but biogenic VOC emitted fr om vegetation tend to be more important compounds in non-urban vegetated areas (U.S. EPA, 2013). Therefor e, reducing these emissions would reduce ozone formation, hu man exposure to ozone, and the incidence of ozone-related health effects. However, we ha ve not quantified the ozone-related benefits in this analysis for several reasons. First, previous rules have shown that the monetiz ed benefits associated with reducing ozone exposure are generally smaller than PM-related benefits, even when ozone is the pollutant targeted for control (U.S. EP A, 2010a, 2014b). Second, the complex non-linear chemistry of ozone formation introduces uncerta inty to the development and application of a***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-24 benefit-per-ton estimate, particul arly for sectors with substantia l new growth. Third, the impact of reducing VOC emissions is sp atially heterogeneous dependi ng on local air chemistry. Urban areas with a high population concentration are often VOC-limited, which means that ozone is most effectively reduced by lowering VOC. Rura l areas and downwind suburban areas are often
NO X -limited, which means that ozone concentrati ons are most effectively reduced by lowering
NO X emissions, rather than lowering emissions of VOC. Between these areas, ozone is relatively insensitive to marginal changes in both NO X and VOC.

Due to data limitations regarding potentia l locations of new and modified sources affected by this rulemaking, we did not perform air quality modeling for this rule needed to quantify the ozone benefits asso ciated with reducing VOC emissi ons. Due to the high degree of variability in the re sponsiveness 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 mo rbidity (U.S. EPA, 2010a). Researchers have associated ozone exposure with adverse health ef fects in numerous toxico logical, clinical and epidemiological studies (U.S. EPA, 2013). When ad equate data and resources are available, EPA generally quantifies several health effects as sociated with exposure to ozone (e.g., U.S. EPA, 2010a; U.S. EPA, 2011a). These health effects in clude respiratory morbidity such as asthma attacks, hospital and emergency department vi sits, school loss days, as well as premature mortality. The scientific literature is also suggestive that exposure to ozone is also associated with chronic respiratory damage a nd 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 mone tized benefits from reduced ozone exposure (U.S. EPA, 2011b). 33 After updating the currency year to 2012$, this implies a

33 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-25 benefit-per-ton for ozone of $260 to $1,070 per to n of VOC reduced. Since EPA conducted the analysis of industrial bo ilers, 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, wh ile current at that time, do not reflect the most updated literature available. The selection of ozone mortality studi es 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 with in the range shown here . While these ranges of benefit-per-ton estimates provide useful context, the geographi c 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 estimate s to provide useful estim ates of the monetized benefits of this rule, even as a bounding exercise.

4.5.2 Ozone vegetation effects
Exposure to ozone has been associated with a wide array of vegetation and ecosystem effects in the published literature (U.S. EPA, 2013). Sensitivity to ozone is highly variable across species, with over 66 vegetation species identified as “ozone-sensitive”, many of which occur in state and national parks and forests. These eff ects 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 tr ees, reduced yield and quality of crops, visible foliar injury, species composition shift, and changes in ecosystems and associated ecosystem services.

4.5.3 Ozone climate effects

Ozone is a well-known short-liv ed climate forcing greenhouse 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) radiati on. In contrast, tropospheric ozone (ozone in the lower atmosphere) is a harmful air pollutant that adversely affects human health and the environment and contributes significantly to regi onal and global climate change. Due to its short atmospheric lifetime, tropospheric ozone concen trations exhibit large spatial and temporal variability (U.S. EPA, 2009b). A recent Unite d Nations Environment Programme (UNEP) study***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-26 reports that the threefold increase in ground le vel ozone during the past 100 years makes it the third most important contri butor to human contributed climate change behind CO 2 and methane. This quantifiable influence of ground level ozone on climate leads to increases in global surface temperature and changes in hydrological cycles.

4.6 Hazardous Air Pollutant (HAP) Benefits
When looking at exposures from all air toxic so urces 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-Scale Air Toxics Asse ssment (NATA) predicts that most Americans are exposed to ambient concentrations of air toxi cs at levels that have the potential to cause adverse health effects (U.S. EPA, 2011d). 34 The levels of air toxics to which people are exposed vary depending on where they live and work and th e kinds of activities in which they engage. In order to identify and prioritize ai r toxics, emission source types a nd locations that are of greatest potential concern, U.S. EPA conducts the NATA. 35 The most recent NATA was conducted for calendar year 2005 and was released in March 2011. NATA includes four steps:

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

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

35 The NATA modeling framework has a number of limitations that prevent its use as the sole basis for setting regulatory standards. These limitations and uncertaintie s are discussed on the 2005 NATA website. Even so, this modeling framework is very useful in identifying air toxic pollutants and s ources 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/***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-27 cancer risks are formaldehyde and benzene. 36,37 Secondary formation (e.g., formaldehyde forming from other emitted pollutants) was the largest contributor to cancer risks, while stationary, mobile and background sources contri bute almost equal portions of the remaining
cancer risk.

Noncancer health effects can result from chronic, 38 subchronic, 39 or acute 40 inhalation exposure to air toxics, and include neurological, cardiovascular, liver, kidney, and respiratory
effects as well as effects on the immune a nd reproductive systems. According to the 2005 NATA, about three-fourths of the U.S. popul ation was exposed to an average chronic concentration of air toxics that has the potential for adverse noncancer respiratory health effects.
Results from the 2005 NATA indicate that acro lein 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 resp iratory hazard from the assessment. It is important to note that large reductions in HAP em issions may not necessarily tran slate into significant reductions in health risk because toxicity varies by pollu tant, and exposures may or may not exceed levels of concern. For example, acetaldehyde mass em issions were more than double acrolein
emissions on a national basis in EPA’s 2005 Nationa l Emissions Inventory (NEI). However, the Integrated Risk Information System (IRIS) re ference concentration (RfC) for acrolein is considerably lower than that fo r acetaldehyde, suggesting that acrol ein could be potentially more

36 Details on EPA’s approach to characterization of can cer risks and uncertainties asso ciated with the 2005 NATA risk estimates can be found at http://www.epa.gov/ttn/atw/nata1999/riskbg.html#Z2. 37 Details about the overall confidence of certainty ranking of the individual pieces of NATA assessments including both quantitative (e.g., model-to-monitor ratios) and qua litative (e.g., quality of data, review of emission inventories) judgments can be found at h ttp://www.epa.gov/ttn/atw/nata/roy/page16.html. 38 Chronic exposure is defined in the glossary of the Integrated Risk Information System (IRIS) database (http://www.epa.gov/iris) as repeated exposure by the oral, dermal, or inhalation route for more than approximately 10 of the life span in humans (more than approximately 90 days to 2 years in typically used laboratory animal species).

39 Defined in the IRIS database as repeated exposure by the oral, dermal, or inhalation route for more than 30 days, up to approximately 10 of the life span in humans (more than 30 days up to approximately 90 days in typically used laboratory animal species).

40 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-28 toxic than acetaldehyde. 41 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 Carcinogeni c Risk from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics Inventory

41 Details on the derivation of IRIS values and available supporting documentation for individual chemicals (as well as chemical values comparisons) can be fo und at http://cfpub.epa. gov/ncea/iris/compare.cfm.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-29 Figure 4-3 2005 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk from HAP Exposure from All Outdoor Sou rces 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 reduc tions in HAP, EPA has quan tified the benefits of potential reductions in the in cidences of cancer and noncancer risk (e.g., U.S. EPA, 1995). In those analyses, EPA relied on unit risk factors (URF) and re ference 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 re present the high end of
the distribution of risk rather th an a best or most likely estimate of risk. An RfC is an estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-30 to the human population (including sensitive su bgroups) that is likel y to be without an appreciable risk of deleterious noncancer health effects during a lifetime. As the purpose of a benefit analysis is to describe the benefits most likely to occu r from a reduction in pollution, use of high-end, conservative risk esti mates would overestimate the be nefits of the regulation. While we used high-end risk estimates in past analys es, advice from the EPA’s Science Advisory Board (SAB) recommended that we avoid using high-e nd estimates in benefit analyses (U.S. EPASAB, 2002). Since this time, EPA has continued to develop 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 analys is of the health eff ects associated with reducing exposure to benzene in Houston from implementation of the Clean Air Act (IEc, 2009). While reviewing the draft report, EPA’s Adviso ry 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 pollu tants (HAP) are daunting...due to a lack of exposure-response functions, uncertainties in em issions inventories and background levels, the difficulty of extrapolating risk estimates to low doses and the challenges of tracking health progress for diseases, such as cancer, that have long latency periods ” (U.S. EPA-SAB, 2008).

In 2009, EPA convened a workshop to address th e inherent complexities, limitations, and uncertainties in current methods to quantify the benefits of reducing HAP. Recommendations from this workshop included identifying rese arch priorities, focu sing on susceptible and vulnerable populations, and improving dos e-response relationships (Gwinn et al. , 2011).

In summary, monetization of the benefits of reductions in cancer incidences requires several important inputs, includi ng central estimates of cancer risk s, estimates of exposure to carcinogenic HAP, and estimates of the value of an avoided case of cance r (fatal and non-fatal). Due to methodology and data limitations, we did not attempt to monetize th e health benefits of reductions in HAP in this analysis. Instead, we provi de a qualitative analysis of the health 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-31 Available emissions data show that several different HAP are emitted from oil and natural gas operations, either from equipment leaks, processing, compressing, transmission and distribution, or storage tanks. Em issions of eight HAP make up a large percentage of the total HAP emissions by mass from the oil and gas sector : toluene, hexane, ben zene, xylenes (mixed), ethylene glycol, methanol, ethyl benzene, and 2, 2,4-trimethylpentane (U.S. EPA, 2012a). In the subsequent sections, we describe the health e ffects associated with th e main HAP of concern from the oil and natural gas sector: benzene, toluene, carbonyl sulfide, ethyl benzene, mixed xylenes, and n-hexane. This rule is anticipat ed to avoid or reduce 2,500 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 ex posure is associated with additional health effects, including genetic changes in both human s and animals and increa sed proliferation of
bone marrow cells in mice. 42,43,44 EPA states in its IRIS databa se that data indicate a causal relationship between benzene exposure and acute lymphocytic leukemia and suggest a relationship between benzene exposure and ch ronic non-lymphocytic leukemia and chronic lymphocytic leukemia. The International Agen cy 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. 45 , 46 A number of adverse

42 U.S. Environmental Protection Agency (U.S. EPA). 2000. In tegrated 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.

43 International Agency for Research on Cancer, IARC monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 29, Some industrial chemicals and dyestuffs, International Agen cy for Research on Cancer, World Health Organization, Lyon, France, p. 345-389, 1982.

44 Irons, R.D.; Stillman, W.S.; Colagiova nni, D.B.; Henry, V.A. (1992) Synergis tic 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.

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

46 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens available at: http://ntp.niehs.nih.gov/go/16183.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-32 noncancer health effects includi ng blood disorders, such as preleukemia and aplastic anemia,
have also been associated with long-term exposure to benzene. 47,48 The most sensitive noncancer effect observed in humans, based on current data , is the depression of the absolute lymphocyte
count in blood. 49,50 In addition, recent work, including studi es sponsored by the Health Effects Institute (HEI), provides evidence that biochemi cal responses are occurri ng at lower levels of benzene exposure than previously known. 51,52,53,54 EPA’s IRIS program has not yet evaluated these
new data.

4.6.2 Toluene 55
Under the 2005 Guidelines for Carcinogen Risk Assessment, there is inadequate information to assess the carcinogenic potential of toluene because studies of humans chronically exposed to toluene are inconclusive, toluene wa s not carcinogenic in ad equate 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 or al bioassay.

The central nervous system (CNS) is the pr imary target for toluene toxicity in both
humans and animals for acute and chronic exposures. CNS dysfunction (which is often

47 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197.

48 Goldstein, B.D. (1988). Be nzene toxicity. Occupational medicine. St ate of the Art Reviews. 3: 541-554.

49 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.

50 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene (Noncancer Effects). Research and Development, Nationa l Center for Environmental Assessment, Washington, DC. This material is available electronically at: http://www.epa.gov /iris/subst/0276.htm.

51 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.; Me ng, 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.

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

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

54 Turtletaub, K.W. and Mani, C. (2003). Benzene metabolism in rodents at doses relevant to human exposure from Urban Air. Research Reports Hea lth Effect Inst. Report No.113.

55 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, In tegrated Risk Information System (IRIS), Office of Health and Environmental Assessment, Environmental Criteria and Assessment Office, Cincinnati, OH. Available on the Internet at < http://www.epa.gov/iris/subst/0118.htm >.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-33 reversible) and narcosis have been frequently ob served in humans acutely exposed to low or moderate levels of toluene by inhalation: sympto ms include fatigue, sleepiness, headaches, and nausea. Central nervous system depression has been reported to occur in chronic abusers exposed to high levels of toluene. Symptoms include ataxia, tremors, cerebral atrophy, nystagmus (involuntary eye movements), and impaired spe ech, hearing, and vision. Chronic inhalation exposure of humans to toluene also causes irritati on of the upper respirator y tract, eye irritation, dizziness, headaches, and difficulty with sleep.

Human studies have also re ported developmental effects, such as CNS dysfunction, attention deficits, and minor cr aniofacial and limb anomalies, in the children of women who abused toluene during pregnancy. A substantial da tabase examining the effects of toluene in subchronic and chronic occupati onally exposed humans exists. The weight of evidence from these studies indicates neurological effects (i.e., impaired color vision, impaired hearing, decreased performance in neurobehavioral an alysis, changes in motor and sensory nerve conduction velocity, headache, and dizzi ness) as the most sensitive endpoint.

4.6.3 Carbonyl sulfide

Limited information is available on the health effects of carbonyl sulfide. Acute (shortterm) inhalation of high concentrat ions of carbonyl sulfide may cause narcotic effects and irritate the eyes and skin in humans. 56 No information is available on the chronic (long-term), reproductive, developmental, or carcinogenic eff ects of carbonyl sulfide in humans. Carbonyl sulfide has not undergone a complete evaluati on and determination under U.S. EPA's IRIS program for evidence of human carcinogenic potential. 57

4.6.4 Ethylbenzene
Ethylbenzene is a major industr ial chemical produced by alkyla tion of benzene. The pure chemical is used almost exclusively for styr ene production. It is also a constituent of crude

56 Hazardous Substances Data Bank (HSDB), online database). US National Library of Medicine, Toxicology Data Network, available online at http ://toxnet.nlm.nih.gov/. Carbonyl hea lth effects summary available at http://toxnet.nlm.nih.gov/cgi-bin/sis/sear ch/r?dbs+hsdb:@term+@rn+@rel+463-58-1.

57 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-34 petroleum and is found in gasoline and diesel fuel s. 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 su ch as dizziness. Chronic (long-term) exposure of humans to ethylbenzene may cause eye and lung irritation, with possible adverse effects on the blood. Animal studies have repor ted effects on the blood, liver, and kidneys and endocrine system from chronic inhalation exposure to et hylbenzene. No information is available on the developmental or reproductive effects of ethyl benzene in humans, but animal studies have reported developmental effects, including birth defects in animal s exposed via inhalation. Studies in rodents reported increases in the percentage of animals with tumors of the nasal and oral cavities in male and female rats expos ed to ethylbenzene via the oral route. 58 , 59 The reports of
these studies lacked detailed information on the in cidence of specific tumors, statistical analysis, survival data, and information on historical controls, thus the results of these studies were considered inconclusive by the International Agency for Resear ch on Cancer (IARC, 2000) and the National Toxicology Program (NTP). 60 , 61 The NTP (1999) carried out a chronic inhalation bioassay in mice and rats and found clear evidence of carcinogenic ac tivity in male rats and some evidence in female rats, based on increased incide nces of renal tubule adenoma or carcinoma in
male rats and renal tubule adenoma in females. NTP (1999) also noted increases in the incidence
of testicular adenoma in male rats. Increased in cidences of lung alveolar /bronchiolar adenoma or
carcinoma were observed in male mice and liver he patocellular adenoma or carcinoma in female mice, which provided some evidence of carcinogen ic activity in male and female mice (NTP, 1999). IARC (2000) classified ethylbenzene as Group 2B, possibly carcinogenic to humans,
based on the NTP studies.

58 Maltoni C, Conti B, Giuliano C and Belpoggi F, 1985. Experimental studies on benzene carcinogenicity at the Bologna Institute of Oncology: Current results and ongoing research. Am J Ind Med 7:415-446.

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

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

61 National Toxicology Program (NTP), 1999. Toxicology and Carcinogenesis Studies of Ethylbenzene (CAS No. 100-41-4) in F344/N Rats and in B6C3F1 Mice (Inhala tion Studies). Technical Report Series No. 466. NIH Publication No. 99-3956. U.S. Department of Health and Human Services, Public Health Service, National Institutes of Health. NTP, Research Triangle Park, NC.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-35 4.6.5 Mixed xylenes
Short-term inhalation of mixed xylenes (a mi xture of three closely-related compounds) in humans may cause irritation of the nose and throat, nausea, vo miting, gastric irritation, mild transient eye irritation, a nd neurological effects. 62 Other reported effects include labored breathing, heart palpitation, impaired function of the lungs, and possible e ffects in the liver and kidneys. 63 Long-term inhalation exposure to xylene s in humans has been associated with a number of effects in the nervous system incl uding headaches, dizziness, fatigue, tremors, and impaired motor coordination. 64 EPA has classified mixed xylenes in Category D, not classifiable with respect to human carcinogenicity.

4.6.6 n-Hexane

The studies available in both hum ans and animals indicate that the nervous system is the primary target of toxicity upon e xposure of n-hexane via inhalati on. There are no data in humans and very limited information in animals about the pot ential effects of n-hexa ne via the oral route. Acute (short-term) inhalation exposure of humans to high levels of hexane causes mild central nervous system effects, including dizziness, gi ddiness, slight nausea, and headache. Chronic (long-term) exposure to hexane in air causes nu mbness in the extremities, muscular weakness, blurred vision, headache, and fatigue. Inhalation studies in rodents have reported behavioral effects, neurophysiological changes and neuropa thological effects upon inhalation exposure to nhexane. Under the Guidelines for Carcinogen Ri sk Assessment (U.S. EPA, 2005), the database for n-hexane is considered inadequate to asse ss human carcinogenic poten tial, therefore the EPA has classified hexane in Group D, not cl assifiable as to human carcinogenicity. 65

62 U.S. Environmental Protection Agency (U.S. EPA). 2003 . Integrated Risk Information System File for Mixed Xylenes. Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at http://www.epa.gov/iris/subst/0270.htm.

63 Agency for Toxic Substances and Disease Registry (A TSDR), 2007. The Toxicological Profile for xylene is available electronically at http://www.atsdr. cdc.gov/ToxProfiles/TP.asp?id=296&tid=53.

64 Agency for Toxic Substances and Disease Registry (A TSDR), 2007. The Toxicological Profile for xylene is available electronically at http://www.atsdr. cdc.gov/ToxProfiles/TP.asp?id=296&tid=53.

65 U.S. EPA. 2005. Guidelines for Carcinogen Risk A ssessment. EPA/630/P-03/001B. Risk Assessment Forum, Washington, DC. March. Available on the Internet at <http://www.epa.gov/ttn/atw/cancer_guidelines_final_3- 25-05.pdf>.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-36 4.6.7 Other Air Toxics
In addition to the compounds described above , other toxic compounds might be affected by this rule, includi ng hydrogen sulfide (H 2 S). Information regarding th e health effects of those compounds can be found in EPA’s IRIS database. 66

4.7 Secondary Air Emissions Impacts

The control techniques to meet the standards ar e associated with several types of secondary emissions impacts, which may partially offset the di rect benefits of this rule. Table 4-7 shows the estimated secondary emissions impacts. Relative to the direct emission reductions anticipated from this rule, the magnitude of these secondary 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 THCTotal Hydraulically Fractured and Refractured Oil Well Completions 580,000 300 10 1,600 620 Fugitive Emissions minimal minimal mini mal minimal minimal Pneumatic Pumps 24,000 12 0 66 25 Pneumatic Controllers 0 0 0 0 0 Compressors 550 0 0 2 1 Total 2020 610,000 310 10 1,700 640

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

EPA has estimated that an increase in flari ng of methane in respons e to this rule will produce a variety of emissions, including about 580,000 short tons (about 530,000 metric tons)

66 U.S. EPA Integrated Risk Information System (IR IS) database is available at: www.epa.gov/iris***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-37 of CO 2 in 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 s econdary emissions impacts across regulatory options. Note that the secondary emision impacts for all three the proposed option s are the same as for the more stringent option 3 . This result holds because the only requirements varied across the options is the coverage (Option 1 excludes low production well sites) or frequency (Option 3 requires annual monitoring) under the fugitive emissions program 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 Poll utant Impacts Associated with Controls, across Regulatory Options (short tons per year)
Option 1 Option 2 (proposed) Option 3

Pollutant 2020 2025 2020 2025 2020 2025 CO 2 610 1,100 ,000 750 1,200 ,000 610,000 750,000 610,000 750,000 NO X 31 55 0 38 63 0 310 380 310 380
PM 1 0 9 11 20 10 11 10 11 CO 1,7 3,0 00 2,1 3,4 00 1,700 2,100 1,700 2,100
THC 64 1,10 0 79 1,30 0 640 790 640 790

We are not estimating the monetized disben efits of the second ary emissions of CO 2 because much of the methane that would have be en released in the absence of the flare would have eventually oxidized into CO 2 in the atmosphere. Note that the CO 2 produced from the methane oxidizing in the atmosphere is not included in the calculation of the SC-CH 4
.
However, EPA does recognize that becau se 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 disbenef it associated with flaring. Assuming an average methane oxidation period of 8.7 years, consiste nt with the lifetime used in IPCC AR4, the disbenefits associated with destroying one metric ton of methan e 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 CH 4 depending on the SC-CO 2 value or 0.7 percent to***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

4-38 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 CH 4 or 0.8 percent to 1.0 percent of the SC-CH 4 estimates per metric
ton for 2025. 67 While EPA is not accounting for the CO 2 disbenefits at this time, we request comment on the appropriateness of the mone tization of such imp acts using the SC-CO 2 and aspects of the calculation.

Table 4-8 provides a summary of the direct and secondary emissions changes. Based on this summary and analysis above, the net impact of both the direct and secondary impacts of this proposal would be an improvement in ambien t air quality, which would reduce potency of greenhouse gas emissions, reduce exposure to vari ous harmful pollutants, improve visibility impairment, and reduce vegetation damage.

Table 4-8 Summary of Emissions Changes (s hort tons per year, except where noted) Option 1 Option 2 (proposed) Option 3 Pollutant 2020 2025 2020 2025 2020 2025

Change in Direct Emissions Methane 170,000 3 4 3 0,000 180,000 400,000 190,000 470,00 0 VOC 120,000 1 7 6 0,000 120,000 180,000 130,000 200,00 0 HAP 31 29 0 1, 9 8 00 400 2,500 510 3,200

Change in Secondary Emissions CO 2 610,000 1, 100,000 750,000 1, 200,000 610,000 750,000 610,000 750,00 0 NO X 310 550 380 630 310 380 310 380 PM 10 19 11 20 10 11 10 11

CO 1,700 3,00 0 2,100 3,40 0 1,700 2,100 1,700 2,100

THC 640 1,100 790 1,300 640 790 640 790

Change in CO 2 Eq. Emissions CO 2 Eq. (million short tons) 4.3 4.1 8. 5 2 4.4 9.9 4.6 12

CO 2 Eq. (million

metric tons) 3.8 3.7 7.7 7.4 4.0 9.0 4.2 11

Note: Totals may not sum due to independent rounding.

67 To calculate the disbenefits associated 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 ye ars 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 SCCO 2 8.7 years after flaring was estimated by linear ly interpolating between the annual SC-CO 2 estimates reported in the TSD and inflated to 2012 dollars.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

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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-Access, Open Assessment EJournal . 8(31): 1-33. http://dx.doi.org/10.5018/econom ics-ejournal.ja.2014-31 . Accessed April 3, 2014.

West et al. 2006. “Global health benef its of mitigating ozone pollution with methane emission controls.” Proceedings of the Natio nal Academy of Sciences 103(11):3988-3993.
West, J.J., A.M. Fiore. 2005. “Managemen t of tropospheric ozone by reducing methane emissions.” Environmental Science & Technology 39:4685-4691.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

5-1 5 STATUTORY AND EXECUT IVE ORDER REVIEWS

5.1 Executive Order 12866, Regulatory Planni ng and Review and Executive Order 13563, Improving Regulation and Regulatory Review

Under section 3(f)(1) Execu tive Order 12866 (58 FR 51735, Oct ober 4, 1993), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more. Accordingly, 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 recommendations have been
documented in the docket for this action. Tables 6- 1 through 6-4 shows the results of the cost and benefits analysis for this proposed rule.

5.2 Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for approval to the Office of Management and B udget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. The ICR document prep ared by the EPA has been assigned EPA ICR Numbers ####.## (40 CFR part 60, subpart OOOOa). You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here.

The information to be collected for th e proposed NSPS is based on notification, recordkeeping and reporting requirements in th e NSPS which are mandatory for all operators subject to national emission standards. These recordkeeping and repor ting requirements are specifically authorized by section 114 of th e 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 requ ire maintenance inspections of the control devices, but would not require any notificati ons or reports beyond those re quired by the General Provisions. The recordkeeping requirements require only th e specific information needed to determine compliance. For sources subject to the proposed NSPS, burden changes associated with these amendments result from the respondents’ annua l reporting and recordkeeping burden associated***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

5-2 with this proposed rule for this collection (avera ged 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 $3,156,605 per year. The average hours and cost per regulated en tity subject to the NSPS for oil and natural gas affected facilities would be 3.9 hours per respon se 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, a nd a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9.

Submit your comments on the Agency’s need fo r this information, the accuracy of the provided burden estimates and any suggested me thods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule . You may also send your ICRrelated comments to OMB’s Office of Inform ation and Regulatory Affairs via email to RIA_submissions@omb.eop.gov, Attention: Desk Of ficer for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after receipt, OMB must receive comments no later than [insert date 30 days afte r publication in the Federal Register]. The EPA will respond to any ICR-related comments in the final rule.

5.3 Regulatory Flexibility Act

[Placeholder for Initial 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 aff ect small governments. The action imposes no enforceable duty on any state, local or tribal governments or the private sector.

5.5 Executive Order 13132: Federalism

This action does not have federalism implica tions. It will not have substantial direct***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

5-3 effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities am ong 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 a nd Coordination with Indian Tribal Governments

This action has tribal implications. Howeve r, 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 rulemaki ng on tribal lands are owned by private entities, and tribes will not be 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 authority to enforce the rulemaking.

The EPA consulted with tribal official s under the EPA Policy on Consultation and Coordination with Indian Tribes early in the pr ocess of developing this regulation to permit them to have meaningful and timely input into its development. Additionally, the EPA has conducted meaningful involvement with tribal stake holders 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 section 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 actions affecti ng 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 soli cits additional comment on this proposed action from tribal
officials.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

5-4 5.7 Executive Order 13045: Protection of Ch ildren from Environmental Health Risks and Safety Risks

This action is subject to Executive Orde r 13045 (62 FR 19885, April 23, 1997) because it is an economically significan t regulatory action as defined by Executive Order 12866, and the
EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on child ren. Accordingly, the agency ha s evaluated the environmental
health and welfare effects of climate change on children.

GHGs including methane contribute to climat e change and are emitted in significant quantities by the oil and gas sector. The EPA believes that the GHG emission reductions resulting from implementation of these final gui delines will further improve children’s health.

The assessment literature c ited in the EPA’s 2009 Endangerm ent Finding concluded that certain populations and life st ages, including children, the el derly, and the poor, are most
vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed fi ndings regarding 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 vul nerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and wate rborne illnesses, and mental health effects resulting from extreme weathe r events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with ch ildren, if climate change reduces f ood availability and increases prices, leading to food insecurity within households.

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 Office of Information and Regulatory Affairs, Office of***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

5-5 Management and Budget, a Statement of Energy Effects for certain actions identified as “significant energy actions.” S ection 4(b) of Executive Order 13211 defines “significant energy actions” as any action by an agency (norma lly published in the Federal Register) that promulgates or is expected to lead to the pr omulgation 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 Orde r 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distri bution, or use of energy; or (2) that is designated by the Administrator of the Office of In formation and Regulatory Affairs as a significant energy action.

This action is not a “significant energy ac tion” 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.

The EPA used the National Energy Modeling Sy stem (NEMS) to estimate the impacts of the proposed rule on the United States energy syst em. The NEMS is a pub lically-available model of the United States energy economy develope d and maintained by th e Energy Information
Administration of the DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecas ts of the United States energy economy.

We estimate that natural gas and crude oil production levels remains essentially unchanged in 2020, while slight declines are es timated 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 pr ices for onshore lower 48 production are not estimated to change in 2020, but are estimated to increase about $0.007 per Mcf or 0.14 percent in 2025. Meanwhile, well crude oil prices for ons hore lower 48 production are not estimated to change, despite the incidence of new complian ce 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.

Additionally, the NSPS establishes several pe rformance standards that give regulated entities flexibility in dete rmining how to best comply with the regulation. In an industry that is***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

5-6 geographically and economically heterogeneous, this flexibility is an important factor in reducing regulatory burden. For more informa tion on the estimated energy effects of this proposed rule, please see Section 7 of this RIA.

5.9 National Technology Transfer and Advancement Act

Section 12(d) of the Nati onal 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 activiti es unless to do so would be inconsistent with applicable law or otherwise impractical. VC S 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 t echnical standards. Therefor e, the requirements of the NTTAA apply to this action. We are proposi ng 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 only and not the instrumental portion. This standard is available from the Amer ican 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, invites the public to identify poten tially-applicable VCS and to explain why such
standards should be used in this regulation.

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

The EPA believes the human health or envir onmental risk addresse d by this action will not have potential disproportionate ly high and adverse human health or environmental effects on minority, low-income or indige nous populations. The EPA has determined this because the rulemaking increases the level of environmental protection for all affect ed populations without***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

5-7 having any disproportionately hi gh and adverse human health or environmental effects on any population, including any minority, low-income or indigenous populations. The EPA has provided meaningful participation opport unities for minority, low-income, indigenous populations and tribes during the pre-proposal period by conducting community calls and webinars. Additionally, the EPA will conduct outr each for communities after the rulemaking is
finalized.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

6-1 6 COMPARISON OF BENEFITS AND COSTS

Tables 6-1 though Table 6-3 present the summary of the benefits, costs, and net benefits for the NSPS across regulatory options, where Ta ble 6-1 presents the proposed option, Table 6-2 presents a less stringent regulat ory option, and Table 6-3 presents a more stringent regulatory option. Table 6-4 provides a summary of the dire ct and secondary emissions changes for each regulatory option.

Table 6-1 Summary of the Monetized Bene fits, 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 $420 million
Net Benefits 3 $35 million $120 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, an d 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 bene fits 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 an nualized 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 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

6-2 Table 6-2 Summary of the Monetized Benefi ts, Costs, and Net Benefits for the Less Stringent Option for the NSPS in 2020 and 2025 (2012$)
2020 2025
Total Monetized Benefits 1 $200 million $190 million $460 million $450 million Total Costs 2 $150 million $80 million $320 million $240 million Net Benefits $42 million $110 million $150 million $210 million

Non-monetized Benefits Non-monetized climate benefits Nonmonetized climate benefits Non-monetized climate benefits Nonmonetized 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 120,000 tons of VOC reduced Health effects of PM 2.5 and ozone exposure from 170,000 tons of VOC reduced Health effects of PM 2.5 and ozone exposure from 160,000 tons of VOC reduced Health effects of HAP exposure from 310 tons of HAP reduced Health effects of HAP exposure from 290 tons of HAP reduced Health effects of HAP exposure from 1,900 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 170,000 tons of methane Health effects of ozone exposure from 340,000 tons of methane Health effects of ozone exposure from 330,000 tons of methane Visibility impairment Visibility impairment Visibility impairment Visibility impairment Vegetation effects Vegetation effects 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, an d 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 bene fits calculated using all four SC-CH4 estimates; the additional benefit estimates range from $8 8 7 million to $520 million in 2020 and $ 210 220 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 8 million metric tons in 2020 and 7. 4 7 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.
2 The engineering compliance costs are an nualized 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 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

6-3 Table 6-3 Summary of the Monetized Benefi ts, 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 million Net Benefits $7.6 million -$35 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 510 tons of HAP reduced Health effects of HAP exposure from 3,200 tons of HAP reduced Health effects of ozone exposure from 190,000 tons of methane Health effects of ozone exposure from 470,000 tons of methane Visibility impairment Visibility impairment Vegetation effects Vegetation effects

1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4) (model average at 2.5 percent discount rate, 3 percent, an d 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 bene fits calculated using all four SC-CH4 estimates; the additional benefit estimates range from $99 million to $590 million in 2020 and $300 million to $1,700 million in 2025 for this more stringent option, as shown in Section 4.3. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 4.2 million metric tons in 2020 and 10.6 11 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticip ated to have minor secondary disbenefits.
2 The engineering compliance costs are an nualized 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 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

6-4 Table 6-4 Summary of Emissions Changes across Option for the NSPS in 2020 and 2025 (short tons per year, unless otherwise noted) Option 1 Option 2 (proposed) Option 3

Pollutant 2020 2020 2025 2025 2020 2025 2020 2025

Change in Direct Emissions Methane 170,000 17 0,000 340,000 33 0,000 180,000 400,000 190,000 470,000

VOC 120,000 12 0,000 170,000 16 0,000 120,000 180,000 130,000 200,000

HAP 310 290 1,900 1,80 0 400 2,500 510 3,200

Change in Secondary Emissions CO 2 610,000 1,1 00,000 750,000 1, 200,000 610,000 750,000 610,000 750,000

NO X 310 550 380 630 310 380 310 380

PM 10 19 11 20 10 11 10 11

CO 1,700 3,000 2,100 3,40 0 1,700 2,100 1,700 2,100

THC 640 1,100 790 1,300 640 790 640 790

Change in CO 2 Eq. Emissions CO 2 Eq. (million short tons) 4.3 4.1 8.5 8.2 4.4 9.9 4.6 11.7

CO 2 Eq. (million metric tons) 3.8 3.7 7.7 7.4 4 9 4.2 11***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-1 7 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS

7.1 Introduction

This section includes three sets of analyses for the proposed NSPS:

 Energy System Impacts

 Initial Regulatory Flexibility Analysis

 Employment Impacts

 Small Entity Impacts Analysis

7.2 Energy System Impacts Analysis

We use the National Energy Modeling System (NEMS) 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 produc tion and consumption of crude oil and natural gas, and changes in international trade of crude oil and natural ga s. We evaluate whether and to what extent the increased production costs impos ed by the proposed rule might alter the mix of
fuels consumed at a national le vel. A brief conceptual disc ussion about our energy system impacts modeling approach is necessary be fore going into detail on NEMS, how we implemented the regulatory imp acts, and presenting results.

Economically, it is possible to view the recove red natural gas as an explicit output or as contributing to an efficiency ga in in production at the producer le vel. For example, the analysis for the proposed rule shows that performing reduced emissions completions on hydraulicallyfractured oil wells contributes a bout 75 percent of the natural gas captured by emissions controls in 2020 and about 32 percent of captured natural gas in 2025. The fugitive emissions program at well sites is expected to capture about 18 pe rcent of the natural ga s captured by emissions controls in 2020 and about 52 percen t of captured natural gas in 2025.

The assumed $4/Mcf price for natural gas is the price paid to producers at the wellhead. In the natural gas industry, production is metered at or very near to the wellhead, and producers are paid based upon this metere d production. Depending on the situ ation, the gas captured by a REC is sent through a temporary or permanent me ter. Payments for the gas are typically made***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-2 within 30 days.

In the engineering cost analysis, it is n ecessary to estimate the expected costs and revenues from implementing emissions controls at the unit level. Because of this, we estimate the net costs as expected costs minus expected revenues for representative units. On the other hand, NEMS models the profit maximizing behavior of representative project developers at a drilling project level. The net costs of the regulation alte r the expected discounted cash flow of drilling and implementing oil and gas projects, and the beha vior of the representa tive drillers adjusts accordingly. While in the regulat ory case natural gas drilling has become more efficient because of the gas recovery, project de velopers still interact with markets for which supply and demand are simultaneously adjusting. Consequently, proj ect development adjusts to a new equilibrium.
While we believe the cost savings as measured by reve nues from selling recovered gas (engineering costs) and measured by cost savings from averted production through efficiency gains (energy economic modeling) are approximatel y the same, it is import ant to note that the engineering cost analysis and the national-leve l cost estimates do not incorporate economic feedbacks such as supply and demand adjustments.

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

NEMS is a model of U.S. energy economy developed and maintained by the Energy Information Administration of the U.S. Departme nt of Energy (DOE). NEMS is used to produce the Annual Energy Outlook, a referen ce publication that provides detailed forecasts of the energy economy from the current year to 2040. DOE firs t 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, legi slative analyses, and respond to Congressional inquiries.

EIA is legally required to make the NEMS system source code available and fully documented for the public. The source code and accompanying documentation is released annually when a new Annual Energy Outlook is pr oduced. Because of the availability of the NEMS model, numerous agencies, national labora tories, 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 inte ractions with the broader***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-3 U.S. economy. The system projects the production of energy resources such as oil, natural gas, coal, and renewable fuels, the conversion of resources through processes such as refining and electricity generation, and the quantity and pric es for final consumption across sectors and regions. The dynamics of the energy system ar e governed by assumptions about energy and environmental policies, technological devel opments, 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 Gauss-Seidel methods (Gabriel et al. 2001). What this means is that NEMS solves a single module, holding all else constant at provisional solutions , then moves to the next mode l after establishing an updated provisional solution.

NEMS provides what EIA refers to as “mid-t erm” projections to the year 2040. For this RIA, we draw upon the same assumptions a nd model used in the Annual Energy Outlook 2014. 68
The RIA baseline is consistent with that of the Annual Energy Outlook 2014 which is used extensively in Section 2 in the Industry Profile.

7.2.2 Inputs to National Energy Modeling System

To model potential impacts associated with the proposed rule, we modified oil and gas production costs within the Oil and Gas Suppl y Module (OGSM) of NEMS and domestic and Canadian natural gas producti on within the Natural Gas Tran smission and Distribution Module (NGTDM). The OGSM projects domestic oil and gas production from onshore, offshore, Alaskan wells, as well as having a smaller-scal e treatment of Canadian oil and gas production (U.S. EIA, 2014). The treatment of oil and gas res ources is detailed in that oil, shale oil, conventional gas, shale gas, tight sands gas, an d coalbed methane (CBM) are explicitly modeled. New exploration and development is pursued in the OGSM if the expected net present value of extracted resources exceeds expect ed costs, including costs associat ed with capital, exploration,

68 Assumptions for the 2014 Annual Energy Outlook can be found at
< http://www.eia.gov/for ecasts/aeo/assumptions/ >.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-4 development, production, and taxes. Detail ed technology and reservoir-level production economics govern finding and success rates and costs.

The structure of the OGSM is amenable to analyzing potential impacts of the proposed NSPS. We are able to target additional expenditu res for environmental co ntrols required by the NSPS on new exploratory and developmental oil and gas production activities. We model the impacts of additional environmental costs, as we ll as the impacts of additional product recovery. We explicitly model the additional natural gas re covered when implementing the proposed rule.

While the oil production simulated by the OGS M is sent to the refining module (the Liquid Fuels Market Module), si mulated 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 consumption to determine a regional equilibrium between supply, demand and prices, including imports and expor ts via pipeline or LNG. Natural gas is transported through a simplified arc-node represen tation of pipeline infrastructure based upon pipeline economics.

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 evaluates the profit ability of new projects. Additio nal NSPS costs associated with reduced emission completions for hydraulically fr actured oil well completions are added to the drilling and completion costs of oil wells in the OGSM.

Other costs are operations and maintenance-t ype 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, de pending 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 includ e revenues from additional product recovery in these costs. This approach is appropriate gi ven the structure of the NEMS algorithm that estimates the net present value of drilling projects.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-5 One caveat in introducing new cost requirements into the model is that potential barriers to obtaining capital may not be adequately incorp orated in the model. However, in general, potential barriers to obtaining additional capital should be reflected in the annualized cost via these barriers increasing the cost of capital. With this in mind, assuming the estimates of capital costs and product recovery are valid, the NEMS results will reflect barriers to obtaining the required capital. A caveat to this is that the estima ted unit-level capital cost s of controls that are newly required at a national-leve l as a result of the regulati on may not incorporate potential
additional transitional costs as the supply of control equipment adjusts to new demand.

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

Based on the baseline projections of succe ssful 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 point by the appropriate number of expected new wells in the year of analysis. The result yields an approximation of per well compliance costs. We assume this approximation is representative of the incremental cost faced by a producer when evaluating a prosp ective drilling proj ect (Table 1).

Hydraulically fractured oil wells completions and fugitives at oil and natural gas well sites differ slightly from this approach. Dr illing and completion costs of new hydraulically fractured oil wells are incremented by the weight ed average of the cost of performing a REC with completion combustion and completion co mbustion alone. The resulting cost 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 tw o 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-6***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-7 Table 7-1 Per Well Costs for Environmenta l 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 We lls $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 assume d 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 em issions from oil and natural gas production
is that methane that would otherwise be lost to the atmosphere can be di rected into the natural gas production stream. We chose to model methane capture in NEMS as an increase in natural gas industry productivity, ensuri ng that, within the model, natural ga s reservoirs are not decremented by production gains from methane captu re. We add estimates of the quantities of methane captured (or otherwise not vented or co mbusted) to the base quantities that the OGSM model supplies to the NGTDM model. We subdivi de the estimates of commercially valuable averted emissions by region and well type in orde r to more accurately portray the economics of implementing the environmental technology. Addi ng the averted methane emissions in this***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-8 manner has the effect of moving the natural gas s upply curve to the right an increment consistent with the technically achievable emissions transf erred into the production st ream as a result of the proposed NSPS.

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

7.2.3 Energy System Impacts

As mentioned earlier, we estimate impacts to drilling activity, price and quantity changes in the production of crude oil and natural gas, an d changes in internationa l trade of crude oil and natural gas. In each of these estimates, we pr esent estimates for the baseline years of 2020 and 2025 and predicted results for 2020 and 2025 under the proposal. We also presented impacts over the 2020 to 2025 time period. For context, we provide estimates of production activities in 2012. With the exception of examining crude oil a nd natural gas trade, we focus the analysis on onshore oil and natural gas producti on activities in the co ntinental (lower 48) U.S. We do this because off-shore production is not affected by the proposed NSPS and the bulk of the proposed rule’s impacts are expected in the continental U.S.

We first report estimates of impacts on crude oil and natural gas drilling activities and production. Table 7-2 presents estimates of succe ssful onshore natural gas and crude oil wells
drilled in the continental U.S.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-9 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 show that the proposed NSPS will have a relatively small impact on onshore well drilling in the lower 48 states. Drilling remains essentially unch anged 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 somewhat counter-intu itive 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 period decreases but about 120 wells tota l. Crude oil drilling, over the same six-year, period remains at the same levels.

Table 7-3 shows estimates of the changes in the domestic producti on of natural gas and crude oil under the proposed NSPS.

Table 7-3 Annual Domestic Natural Gas an d 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%***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-10 As indicated by the estimated change in the new well drilling activities, the analysis shows that the proposed NSPS will have a relati vely small impact on onshore natural gas and crude oil production in the lower 48 states. Again, production levels Drilling remains essentially unchanged in 2020, while slight declines are es timated 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). Total production over the 2 020 to 2025 is also estimated to decline for natural gas (by about 9 bcf or 0.01 percent) a nd 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 anticipated to be used in response to the proposed rule capture natural gas that would otherwise be emitted (8.2 bcf in 2020 and 19 bcf in 2025). There are two sources for this difference. First, we were unable to incorpor ate 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. S econd, NEMS models the adjustment of energy markets to the new slightly more costly natural gas and crude oil productive activities. At the new post-rule equilibrium, producers implementing emissions contro ls are still anticipated to capture and sell the captured natural gas, and this natural gas might offset other production, but not so much as to make overall production increase fr om the baseline projections.

Table 7-4 presents estimates of national aver age wellhead natural gas and crude oil prices for onshore production 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%***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-11 Wellhead natural gas prices for onshore lowe r 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 pri ce over the 2020 to 2025 period is estimated to increase by $0.003 per Mcf or about 0.06 percent. Meanwhile, well crude oil prices for onshore lower 48 production are not estimated to change, despite th e incidence of new compliance costs from the proposed NSPS. This is likely result of both the re latively small scale of the costs of the new compliance requirements, as well as the fact that oil prices are more a fu nction of global prices that are natural gas prices.

Meanwhile, as shown in Table 7-5, net imports of natural gas are estimated to decline slightly in 2020 (by about 1 bcf or 0.05 per cent), 2025 (by about 3 bcf or 0.09 percent), and across the 2020 to 2025 period (by a bout 4 bcf total or about 0.03 pe rcent). Crude oil imports are estimated to not change in 2020, increase by ab out 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 Initial Regulatory Flexibility Analysis
[Placeholder]

7.4 Employment Impact Analysis

In addition to addressing the costs and bene fits of the proposed rule, EPA has analyzed***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-12 the impacts of this rulemaking on employmen t, which are presented in this section. 69 While a standalone analysis of employment impacts is no t included in a standard cost-benefit analysis, such an analysis is of particular concern in th e current economic climate given continued interest in the employment impact of regulations such as this proposed rule. Executive Order 13563, states, “Our regulatory system mu st protect public health, welfar e, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation.” 70 A discussion of compliance costs, including reporting and recordkeep ing requirements, is included in Section 3of this RIA. This analysis us es detailed engineering information on labor requirements for each of the control strategies identified in this propos ed rule in order to estimate partial employment impacts for affected entit ies in the oil and gas industry. These bottom-up, engineering-based estimates repr esent 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 th e various ways that envi ronmental regulation can affect employment. EPA continues to explore the relevant theoreti cal and empirical literature and to seek public comments in order to ensure that the way EPA characterizes the employment effects of its regulations is vali d and informative. The section c oncludes with partial employment impact 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 produc ing goods and services; if a regulation requires that more la bor be used to produce a given amount of output, that additional
labor is reflected in an increase in the cost of production. Moreove r, when the economy is at full employment, we would not expect an environmen tal 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.

69 The employment analysis in this RIA is part of EPA’s ongoing effort to “conduct continuing evaluations of potential loss or shifts of employment which may result from the administration or enforcement of [the Act]” pursuant to CAA section 321(a). 70 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.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-13 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 sect or to help meet new requirements (e.g., to install new equipment) or by the environmental protection sector to produce new abatement capital resulting in hi ring previously unemployed workers. When significant numbers of workers ar e unemployed, the opportunity cost s associated with displacing jobs in other sectors are likely to be higher. And, in general, if a regulation imposes high costs and does not increase the demand for labor, it may lead to a decrease in employment. The responsiveness of industry labor demand depends on how these forces all interact. Economic theory indicates that the responsiveness of industry labor demand depends on a number of factors: price elasticity of demand for the product , substitutability of ot her factors of production, elasticity of supply of other f actors 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 industr y are faced with the sa me compliance costs of regulation and product demand is inelastic, then industry output may not change much at all.

Regulations set in motion new orders for po llution control equipmen t and services. New categories of employment have been created in the process of implementing environmental regulations. When a regulation is promulgated, one typical res ponse of industry 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 comply and remain in operation - occur after the compliance date, or earlier in anticipation of th e compliance obligation. Environmental regulation may increase revenue and employme nt in the environmental technology industry. While these increases represent gains for that indu stry, they translate into costs to the regulated industries required to in stall the equipment.

Environmental regulations suppor t employment in many basic industries. Regulated firms either hire workers to design and build pollution controls directly or pu rchase pollution control devices from a third party for installation. Once the equipment is installed, regulated firms hire workers to operate and maintain the pollution co ntrol equipment—much like they hire workers to produce more output. In addition to the in crease in employment in the environmental protection industry (via increas ed orders for pollution control equipment), environmental***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-14 regulations also support employ ment in industries that provide intermediate goods to the environmental protection industry. The equipment manufacturers, in turn, order steel, tanks, vessels, blowers, pumps, and chemicals to manufact ure and install the equi pment. Currently in most cases there is no scientifically defensible wa y to generate sufficiently reliable estimates of the employment impacts in these intermediate goods sectors.

Berman and Bui (2001) demonstrate using st andard neoclassical microeconomics that environmental regulations have an ambiguous eff ect on employment in the regulated sector. The theoretical 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 innovative 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 incor porates 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 loca l air quality regulations, Berman and Bui identify the effect of environmental regulations on net em ployment in the regulated industries. 71 The authors find that “while regulations do impose large costs, they have a limited effect on employment” (Berman and Bui, 2001, p. 269). Their conclusion is that local air quality regulation “probably increased labor demand slightly” but that “the 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). 72

While there is an extensive empirical, 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 employmen t, but this area of the literature has been growing. As stated previously in this RIA sectio n, empirical results from Berman and Bui (2001) suggest that new or more string ent environmental regulations do not have a substantial impact on

71 Berman and Bui include over 40 4-di git SIC industries in their sample. 72 Including the employment effect of exiting plants and plants dissuaded from opening will increase the estimated impact of regulation on employment.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-15 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 sect or. Furthermore, Gray et al ( 2014) find that pulp mills that had to comply with both the air a nd water regulations in EPA’s 1998 “Cluster Rule” experienced relatively small and not always st atistically significant, decrease s in employment. Nevertheless, other empirical research suggest s that more highly regulated c ounties may generate fewer jobs than less regulated ones (Greenstone 2002, Wa lker 2011). However, the methodology used in these two studies cannot estimate whether aggregat e employment is lower or higher due to more stringent environmental regulati on, it can only imply that relative employment growth in some
sectors differs between more a nd less regulated areas. List et al. (2003) find some evidence that this type of geographic relocation, from more re gulated areas to less re gulated 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 pos itive) 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 guideline s, important differences in the markets and regulatory settings analyzed in th eir study and the setting presented he re lead us to conclude that it is inappropriate to utilize their quantitative es timates to estimate the employment impacts from this proposed regulation. In part icular, the industries used in th ese two studies as well as the timeframe (late 1970’s to early 1990’s) are quite different than those in this proposed NSPS. Furthermore, the control strategies analyzed for this RIA include implementing RECs, reducing fugitive emissions, and reducing emissions from pne umatic controllers, pumps, and reciprocating and centrifugal compressors, which are very differe nt than the control strategies examined by
Berman and Bui. 73 For these reasons we conclude there are too many uncertainties as to the transferability of the quantitativ e estimates from Berman and Bui to apply their estimates to quantify the employment impacts within the regul ated sectors for this regulation, though these studies have usefulness for qualitative assessment of employment impacts.

The preceding sections have outlined the ch allenges associated with estimating net

73 More detail on how emission reductions expected from comp liance with this rule can be obtained can be found in Section 3 of this RIA.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-16 employment effects in the regulated sector a nd in the environmental 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 th e macro-economy. Given the difficulty with estimating national impacts of regulations, EP A has not generally estimated economy-wide employment impacts of its regulations in its be nefit-cost analyses. However, in its continuing effort to advance the evaluation of costs, be nefits, 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
economic models to evaluate th e impacts of its regulations, in cluding the impact on net national employment. 74 Once EPA receives guidance from this pa nel it will carefully c onsider this input and then decide if and how to proceed on econom y-wide modeling of employment 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 ga s industry. As well as producing much of the U.S. energy supply, the oil and natural gas indus try 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. 75 The overall trend shows a decline in to tal 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 S upport Activities for Oil and Gas Operations (NAICS 213112) employ the majority of worker s in the industry. From 1990 to 2013, average wages for the oil and natural gas industry have increased. Table 2-18 shows real wages (in 2012 dollars) from 1990 to 2013 for the NAICS codes associ ated with the oil and natural gas industry.

The focus of this part of the analysis is on labor requirements related to the compliance actions for the proposed rule, of the affected enti ties within the oil and natural gas sector. We do

74 For further information see: http://yosemite.epa.gov/sab/sabproduct.nsf/0/07E67CF77B54734285257BB0004F87ED?OpenDocument 75 NAICS 211111, 21112, 213111, 213112, 486110, and 486210.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-17 not estimate any potential change s in labor outside of the affected sector, and, due to data and methodology limitations, we do not estimate net empl oyment impacts for the affected sector, apart from the partial estimate of the labor re quirements related to control strategies. This analysis estimates the labor required to the inst all, operate, and maintain control equipment and activities, as well as to perform new re porting and recordkeeping requirements.

It is important to highlight that unlike the typical case wh ere to reduce ou tput negative production externality (i.e., emissions) a firm often has to reduce production, many of the emission controls required by the proposed N SPS will simultaneously increase production and reduce negative externalities. That is, these controls jointly produce environmental improvements and increase output in the regu lated sector. New labor associated with implementing these controls to comply with the ne w regulations can also be viewed as additional labor increasing output while redu cing undesirable emissions. To th e extent, however, that these 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 an input. This RIA does not include quantified estimates of these pot ential adverse effects on the la bor market due to data and theoretical challenges , as described above.

No estimates of the labor used to manufactur e or assemble pollution control equipment or to supply the materials for manufacture or assemb ly are included because EPA does not currently have this information. The labor requirements analysis uses a bottom-up engineering-based methodology to estimate employment impacts. Th e engineering cost analysis summarized in Chapter 3 of this RIA includes estimates of the labor requirements associ ated with implementing the regulations. Each of these labo r changes may either be required as part of an initial effort to comply with the new regulation or required as a continuous or annual effort to maintain compliance. We estimate up-front and continua l, annual labor requirements by estimating hours of labor required and converti ng 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 th e specific number of peopl e involved or whether new jobs are created for new employees.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-18 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 individua l sources regulated under this proposal. Table 7-10 presents summary-level labor impact s for all sources. The tables break down the installation, operation, and maintena nce estimates by type of pollu tion control evaluated in the RIA and present both the estimated hours required and the conversion of this estimate to FTE. The labor information is based upon the cost anal ysis presented in the TSD that supports this proposal, based upon analysis presented in the RIA developed for the 2012 NSPS and NESHAP
Amendments for the Oil and Natu ral Gas Sector (U.S. EPA, 2012) . In addition, for the proposed NSPS, reporting and recordkeeping requirements were estimated for the entire rule rather than by anticipated control requirements; the reporting and recordkeeping estimates are consistent with estimates EPA submitted as part of its Information Collection Request (ICR), the estimated costs
of which are included in the cost estimates presented in Chapter 3.

Table 7-6 presents estimate s labor requirements for hydrau lically fractured oil well completions. The REC and completion combustion re quirements are associated with certain new and existing oil well completions. While indivi dual completions occur over a short period of time (days to a few weeks), new wells and othe r 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 re quirements associated with implementing RECs and completion combustion are drawn fr om the labor requirements estimated for implementing RECs on hydraulical ly fractured well completions in U.S. EPA (2012). However, the labor requirements in that report were based upon a completion th at 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-da y requirements by 3/7 (93 hours per completion for a REC or 9 hours labor per comple tion for completion combustion).***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-19 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 UnitOnetime Labor

Est. (hrs) Per Unit Annual Labor

Est. (hrs) TotalOneTime Labor Estimate

(hrs) Total Annual Labor Estimate

(hrs) Onetime FTE Annual FTE
2020 Hydraulically Fractured and Re -fractured Oil Well Completions Development Oil Wells Reduced Emission Completion 6,903 0 93 0 644,937 0 310

Wildcat and Delineation Oil Wells Completion Combustion 7,773 0 9 0 73,289 0 35

Total 14,676 N/A N/A 0 718,227 0 345

2025 Hydraulically Fractured and Re -fractured Oil Well Completions Development Oil Wells Reduced Emission Completion 6,901 0 93 0 644,751 0 310

Wildcat and Delineation Oil Wells Completion Combustion 8,066 0 9 0 76,055 0 37

Total 14,967 N/A N/A 0 720,806 0 347 Note: Full-time equivalents (FTE) are estimated by first mu ltiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding. Table 7-7 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 ac tivities and activities at field sites. Companylevel activities include one time activities such as planning the company’s fugitive emissions program and annual requirements such as repor ting and recordkeeping. Field-level activities include semiannual inspection and re pair of leaks as proposed. It is important to note, however, that the compliance costs estimates for leak in spection were based upon an estimate of the costs to hire a contractor to provide the inspection service, but the source providing this information does not have a breakdown of the labor componen t of the rental cost. As a result, the labor requirements for the fugitives program are likely underestimates.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-20 Table 7-7 Estimates of Labor Required to Co mply with Proposed NSPS for Fugitive Emissions, 2020 and 2025

Emissions Source/ Emissions Control Projected No. of Incr. Affected

Units Per UnitOnetime Labor (hrs) Per Unit Annual Labor (hrs) TotalOneTime Labor (hrs) Total Annual Labor (hrs) Onetime FTE Annual FTE 2020 Well Sites Company-level Activities Semiannual Monitoring/ Maintenance 1,004 118.0 0.0 118,429 0 57 0
Site-level Activities 22,080 0.0 14.1 0 311,569 0 150 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 mu ltiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-21 Most labor required for fugitive emissions is needed at well sites in the field, which
number in the thousands. Note that the labor requirements esti mates increase from 2020 to 2025 as the number of sites regulated under the proposed NSPS accumulates.

Table 7-8 presents labor requirement estim ates 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 la bor is required for reciprocati ng compressors and relatively few affected centrifugal compressors are expected in the future, the estimates of both one-time and on-going labor requirements for compre ssor 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 UnitOnetime Labor

Est. (hrs) Per Unit Annual Labor

Est. (hrs) TotalOneTime Labor Estimate

(hrs) Total Annual Labor Estimate

(hrs) Onetime FTE Annual FTE

2020 Compressors
Reciprocating Monitoring and Maintenance 67 1 1 67 67 0.0 0.0

Centrifugal Route to Control 1 355 0 355 0 0.2 0.0
Total 68 N/A N/A 422 67 0.2 0.0

2025 Compressors
Reciprocating Monitoring and Maintenance 402 1 1 67 402 0.0 0.2

Centrifugal Route to Control 6 355 0 355 0 0.2 0.0
Total 408 N/A N/A 422 402 0.2 0.2 Note: Full-time equivalents (FTE) are estimated by first mu ltiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding. Table 7-9 presents the labor requirement estimates for requirements applying to pneumatic controllers and pneumatic pumps. Note that pneumatic contro llers have no one-time or continuing labor requirements. While the c ontrols do require labor for installation, operation, and maintenance, the required labor is less than th at of the controllers that would be used absent***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-22 the regulation (U.S. EPA, 2012). In this instance, we assume the incremental labor requirements are zero. Meanwhile, we are currently 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 UnitOnetime Labor

Est. (hrs) Per Unit Annual Labor

Est. (hrs) TotalOneTime Labor Estimate

(hrs) Total Annual Labor Estimate

(hrs) Onetime FTE Annual FTE

2020 Pneumatic Controllers Emissions Limit 210 0 0 0 0 0 0

Pneumatic Pumps Route to Control 2,962 N/A N/A N/A N/A N/A N/A

2025
Pneumatic Controllers Emissions Limit 1,260 0 0 0 0 0 0

Pneumatic Pumps Route to Control 17,772 N/A N/A N/A N/A N/A N/A Note: Full-time equivalents (FTE) are estimated by first mu ltiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding. Table 7-10 presents the labor estimates acros s all emissions sources. Two main categories contain the majority of the labor requiremen ts 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 proposed NSPS is estimated at 73 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 ar e created for new employees, vers us displacing jobs from other sectors of the economy.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-23 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 OneTime Labor

Estimate (hours) Total Annual Labor Estimate (hours) One-time FTE Annual FTE

2020Hydraulically Fractured and Refractured 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

2025Hydraulically Fractured and Refractured 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 mu ltiplying the projected number of affected units by the per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to independent rounding.

7.5 References
Berman, E. and L. T. M. Bui. 2001. “Environm ental 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. Wolvert on. 2014. “The Effect of En vironmental Regulation on Power Sector Employment: Phase I of the Title IV SO 2 Trading Program.” Journal of the Association of Environm ental and Resource Economists 5:173-193.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-24 Gray, W.B., R.J. Shadbegian, C. Wang, and M. Meral. 2014. “Do EPA Regul ations 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 Environm ental 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. Fred riksson, and W. W. McHone. 2003. “Effects of Environmental Regulations on Manufacturi ng Plant Births: 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: M odel 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 Pollutants 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 Pres ident’s Small Business Agenda and Executive Order 13272

. Walker, R. 2011. “Environmental Regulation and Labor Reallocation." American Economic Review : 101(3):442-447.***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review***

7-25 United States Environmental Protection Agency Office of Air Quality Planning and Standards Health and Environmental Impacts Division Research Triangle Park, NC Publication No. EPA-452/R-15-002 August 2015