Regulatory Impact Analysis of the Proposed
Emission Standards for New and Modified
Sources in the Oil and Natural Gas Sector
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EPA-452/R-15-002, August 2015
Regulatory Impact Analysis of the Proposed Emission Standards for New and
Modified Sources in the Oil and Natural Gas Sector
U.S. Environmental Protection Agency
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, NC 27711
in
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CONTACT INFORMATION
This document has been prepared by staff from the Office of Air and Radiation, U.S.
Environmental Protection Agency. Questions related to this document should be addressed to
Alexander Macpherson, U.S. Environmental Protection Agency, Office of Air and Radiation,
Research Triangle Park, North Carolina 27711 (email: macpherson.alex@epa.gov).
ACKNOWLEDGEMENTS
In addition to U.S. EPA staff from the Office of Air and Radiation, personnel from the U.S. EPA
Office of Policy, EC/R Incorporated, and ICE International contributed data and analysis to this
document.
IV
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TABLE OF CONTENTS
TABLE OF CONTENTS v
LIST OF TABLES vm
LIST OF FIGURES x
1 EXECUTIVE SUMMARY 1-1
1.1 BACKGROUND 1-1
1.2 MARKET FAILURE 1-3
1.3 REGULATORY OPTIONS ANALYZED IN THIS RIA 1-3
1.4 SUMMARY OF RESULTS 1-5
1.5 ORGANIZATION OF THIS REPORT 1-10
2 INDUSTRY PROFILE 2-1
2.1 INTRODUCTION 2-1
2.2 PRODUCTS OF THE CRUDE OIL AND NATURAL GAS INDUSTRY 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 OIL AND NATURAL GAS PRODUCTION PROCESSES 2-4
2.3.1 Exploration and Drilling 2-4
2.3.2 Production 2-5
2.3.3 Natural Gas Processing 2-7
2.3.4 Natural Gas Transmission and Distribution 2-8
2.4 RESERVES AND MARKETS 2-8
2.4.1 Domestic Proved Reserves 2-9
2.4.2 Domestic Production 2-13
2.4.3 Domestic Consumption 2-20
2.4.4 International Trade 2-24
2.4.5 Forecasts 2-26
2.5 INDUSTRY COSTS 2-30
2.5.1 Finding Costs 2-30
2.5.2 Lifting Costs 2-32
2.5.3 Operating and Equipment Costs 2-33
2.6 FIRM CHARACTERISTICS 2-35
2.6.1 Ownership 2-36
2.6.2 Size Distribution of Firms in Affected NAICS 2-36
2.6.3 Trends in National Employment and Wages 2-37
2.6.4 Horizontal and Vertical Integration 2-39
2.6.5 Firm-level Information 2-41
2.6.6 Financial Performance and Condition 2-45
2.7 REFERENCES 2-49
3 EMISSIONS AND ENGINEERING COSTS 3-1
3.1 INTRODUCTION 3-1
3.2 SECTOR EMISSIONS OVERVIEW 3-1
3.3 EMISSIONS POINTS AND POLLUTION CONTROLS ASSESSED IN THE RIA 3-2
3.4 ENGINEERING COST ANALYSIS 3-5
3.4.1 Regulatory Options 3-5
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3.4.2 Projection of Incrementally Affected Facilities 3-8
3.4.3 Emissions Reductions 3-11
3.4.4 Product Recovery 3-12
3.4.5 Engineering Compliance Costs 3-13
3.4.6 Cost-Effectiveness 3-14
3.4.7 Comparison of Regulatory Alternatives 3-18
3.4.8 Capital and Annualized Compliance Costs Compared to Industry-level Capital Expenditures and
Revenues 3-20
3.5 COMPLIANCE COSTS ESTIMATED USING 3 AND 7 PERCENT DISCOUNT RATES 3-24
3.6 DETAILED IMPACTS TABLES 3-24
4 BENEFITS OF EMISSIONS REDUCTIONS 4-1
4.1 INTRODUCTION 4-1
4.2 EMISSION REDUCTIONS FROM THE PROPOSED NSPS 4-4
4.3 METHANE 4-5
4.3.1 Methane climate effects and valuation 4-5
4.4 VOC AS A PM2.s PRECURSOR 4-17
4.4.1 PM2.s health effects and valuation 4-18
4.4.2 Organic PM welfare effects 4-22
4.4.3 Visibility Effects 4-23
4.5 VOC AS AN OZONE PRECURSOR 4-23
4.5.1 Ozone health effects and valuation 4-24
4.5.2 Ozone vegetation effects 4-25
4.5.3 Ozone climate effects 4-25
4.6 HAZARDOUS AIR POLLUTANT (HAP) BENEFITS 4-26
4.6.1 Benzene 4-31
4.6.2 Toluene 4-32
4.6.3 Carbonyl sulfide 4-33
4.6.4 Ethylbenzene 4-34
4.6.5 Mixed xylenes 4-35
4.6.6 n-Hexane 4-35
4.6.7 Other Air Toxics 4-36
4.7 SECONDARY AIR EMISSIONS IMPACTS 4-36
4.8 REFERENCES 4-39
5 STATUTORY AND EXECUTIVE ORDER REVIEWS 5-1
5.1 EXECUTIVE ORDER 12866, REGULATORY PLANNING AND REVIEW AND EXECUTIVE ORDER 13563,
IMPROVING REGULATION AND REGULATORY REVIEW 5-1
5.2 PAPERWORK REDUCTION ACT 5-1
5.3 REGULATORY FLEXIBILITY ACT (RFA) 5-2
5.4 UNFUNDED MANDATES REFORM ACT 5-5
5.5 EXECUTIVE ORDER 13132: FEDERALISM 5-5
5.6 EXECUTIVE ORDER 13175: CONSULTATION AND COORDINATION WITH INDIAN TRIBAL GOVERNMENTS.... 5-5
5.7 EXECUTIVE ORDER 13045: PROTECTION OF CHILDREN FROM ENVIRONMENTAL HEALTH RISKS AND SAFETY
RISKS 5-6
5.8 EXECUTIVE ORDER 13211: ACTIONS CONCERNING REGULATIONS THAT SIGNIFICANTLY AFFECT ENERGY
SUPPLY, DISTRIBUTION, OR USE 5-7
5.9 NATIONAL TECHNOLOGY TRANSFER AND ADVANCEMENT ACT (NTTAA) AND 1 C.F.R. PART 51 5-8
5.10 EXECUTIVE ORDER 12898: FEDERAL ACTIONS TO ADDRESS ENVIRONMENTAL JUSTICE IN MINORITY
POPULATIONS AND LOW-INCOME POPULATIONS 5-9
6 COMPARISON OF BENEFITS AND COSTS 6-1
7 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS 7-1
7.1 INTRODUCTION 7-1
VI
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7.2 ENERGY SYSTEM IMPACTS ANALYSIS 7-1
7.2.1 Description of the Department of Energy National Energy Modeling System 7-2
7.2.2 Inputs to National Energy Modeling System 7-3
7.2.2.1 Compliance Costs for Oil and Gas Exploration and Production 7-4
7.2.2.2 Adding Averted Methane Emissions into Natural Gas Production 7-6
7.2.3 Energy System Impacts 7-7
7.3 INITIAL REGULATORY FLEXIBILITY ANALYSIS 7-10
7.3.1 Reasons why Action is Being Considered 7-11
7.3.2 Statement of Objectives and Legal Basis for Proposed Rules 7-11
7.3.3 Description and Estimate of Affected Small Entities 7-13
7.3.4 Compliance Cost Impact Estimates 7-17
7.3.4.1 Methodology for Estimating Impacts on Small Entities 7-17
7.3.4.2 Results 7-19
7.3.5 Caveats and Limitations 7-21
7.3.6 Projected Reporting, Recordkeeping and Other Compliance Requirements 7-21
7.3.7 Related Federal Rules 7-22
7.3.8 Regulatory Flexibility Alternatives 7-23
7.3.8.1 Oil Well Exemptions 7-23
7.3.8.2 Fugitives - Leak Detection Methods 7-28
7.3.8.3 Fugitives- Survey Frequency 7-29
7.3.8.4 Fugitive Emissions at Well Sites 7-30
7.3.8.5 Fugitive Emissions at Production and Processing Sites, and Compressor Stations at
Transmission and Storage Sites 7-30
7.3.8.6 Well Site Compressors 7-31
7.3.8.7 Pneumatic Pumps 7-31
7.3.8.8 Reciprocating Compressors 7-31
7.3.8.9 Centrifugal Compressors 7-32
7.3.8.10 Pneumatic Controllers 7-32
7.3.8.11 Recordkeeping and Reporting for High Bleed Controllers 7-33
7.3.8.12 Liquids Unloading 7-33
7.4 EMPLOYMENT IMPACT ANALYSIS 7-33
7.4.1 Employment Impacts of Environmental Regulation 7-34
7.4.2 Labor Estimates Associated with Proposed Requirements 7-38
7.5 REFERENCES 7-46
vn
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LIST OF TABLES
Table 1-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS 1-4
Table 1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 2020 and 2025 (2012$).
1-8
Table 1-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 (Proposed Option) in 2020
and 2025 (2012$) 1-9
Table 1-4 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in 2020 and 2025 (2012$).
1-10
Table 2-1 Technically Recoverable Crude Oil and Natural Gas Resource 2-10
Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Production, Proved Reserves, and Proved Ultimate
Recovery, 1977-2013 2-11
Table 2-3 Crude Oil and Dry Natural Gas Proved Reserves by State, 2013 2-13
Table 2-4 Crude Oil Domestic Production, Wells, Well Productivity, and 2-14
Table 2-5 Natural Gas Production and Well Productivity, 1990-2013 2-15
Table 2-6 Crude Oil and Natural Gas Exploratory and Development Wells and Average Depth, 1990-2010 2-17
Table 2-7 U.S. Onshore and Offshore Oil, Gas, and Produced Water Generation, 2007 2-18
Table 2-8 U.S. Oil and Natural Gas Pipeline Mileage, 2010-2013 2-20
Table 2-9 Crude Oil Consumption by Sector, 1990-2012 2-20
Table 2-10 Natural Gas Consumption by Sector, 1990-2012 2-23
Table 2-11 Total Crude Oil and Petroleum Products Trade (Million Bbl), 2-25
Table 2-12 Natural Gas Imports and Exports, 1990-2013 2-26
Table 2-13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2040 2-27
Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2011-2040 2-28
Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price 2-30
Table 2-16 SBA Size Standards and Size Distribution of Oil and Natural Gas Firms 2-37
Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-2013 2-38
Table 2-18 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2013 (2012 dollars) 2-39
Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012 2-43
Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009 2-44
Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2012 2-45
Table 2-22 Selected Financial Items from Income Statements (B illion 2008 Dollars) 2-47
Table 2-23 Return on Investment for Lines of Business (all FRS), for 1998, 2003, 2008, and 2009 (percent). 2-48
Table 2-24 Income and Production Taxes, 1990-2009 (Million 2008 Dollars) 2-49
Table 3-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS 3-7
Table 3-2 Number of Incrementally Affected Sources for the NSPS 3-10
Table 3-3 Emissions Reductions for Proposed NSPS Option 2, 2020 and 2025 3-11
Table 3-4 Estimated Natural Gas Recovery (Mcf) for Proposed NSPS Option 2 in 2020 and 2025 3-13
Table 3-5 Engineering Compliance Cost Estimates for Proposed NSPS Option 2 in 2020 and 2025 (millions
2012$) 3-14
Table 3-6 Single Pollutant Approach to Engineering Compliance Cost-Effectiveness Estimates in 2020 and
2025 for Proposed NSPS Option 2 (High Impact Case for Well Site Fugitive Emissions Requirements) 3-17
Table 3-7 Multipollutant Approach to Engineering Compliance Cost-Effectiveness Estimates for Proposed
NSPS Option 2 in 2020 and 2025 (High Impact Case for Well Site Fugitive Emissions Requirements) 3-18
Table 3-8 Comparison of Regulatory Alternatives 3-19
Table 3-9 NAICS-Based Capital Expenditure Data 3-20
Table 3-10 NAICS-Based Revenue Data 3-21
Table 3-11 Comparison of Proposed NSPS Nationwide Cost by Affected Facility Cost to Industry-wide Capital
Expenditures and Revenues 3-23
Table 3-12 Annualized Costs using 3 and 7 Percent Discount Rates for Proposed NSPS Option 2 in 2020 and
2025 (millions 2012$) 3-24
Table 3-13 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020 3-25
Table 3-14 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025 3-26
Table 3-15 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact
Case, 2020 3-27
Vlll
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Table 3-16 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact
Case, 2025 3-28
Table 3-17 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact
Case, 2020 3-29
Table 3-18 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact
Case, 2025 3-30
Table 3-19 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020 3-31
Table 3-20 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025 3-32
Table 4-1 Climate and Human Health Effects of Emission Reductions from this Proposal 4-2
Table 4-2 Direct Emission Reductions across NSPS Regulatory Options in 2020 and 2025 4-5
Table 4-3 Social Cost of Methane (SC-CH4), 2012 - 2050a [in 2012$ per metric ton] (Source: Marten et al,
2014b) 4-14
Table 4-4 Estimated Global Benefits of Methane Reductions* (in millions, 2012$) 4-16
Table 4-5 Monetized Benefits-per-Ton Estimates for VOC based on Previous Modeling in 2015 (2012$).... 4-21
Table 4-6 Secondary Air Pollutant Impacts (short tons per year) 4-37
Table 4-7 Summary of Emissions Changes (short tons per year, except where noted) 4-38
Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 2020 and 2025 (2012$).
6-1
Table 6-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 (Proposed Option) in 2020
and 2025 (2012$) 6-2
Table 6-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in 2020 and 2025 (2012$).
6-3
Table 6-4 Summary of Emissions Changes across Options for the NSPS in 2020 and 2025 (short tons per year,
unless otherwise noted) 6-4
Table 7-1 Per Well Costs for Environmental Controls Entered into NEMS (2012$) 7-6
Table 7-2 Successful Oil and Gas Wells Drilled (Onshore, Lower 48 States) 7-8
Table 7-3 Annual Domestic Natural Gas and Crude Oil Production (Onshore, Lower 48 States) 7-8
Table 7-4 Average Natural Gas and Crude Oil Wellhead Price (Onshore, Lower 48 States, 2012$) 7-9
Table 7-5 Net Imports of Natural Gas and Crude Oil 7-10
Table 7-6 SB A Size Standards by NAICS Code 7-13
Table 7-7 Distribution of Estimated Compliance Costs across Sources 7-15
Table 7-8 No. of Completions in 2012 by Preliminary Firm Size 7-16
Table 7-9 No. of Completions in 2012 by Firm Size 7-16
Table 7-10 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, Low Impact Fugitive
Emissions Case 7-17
Table 7-11 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, High Impact Fugitive
Emissions Case 7-18
Table 7-12 Distribution of Estimated Compliance Costs1 across Firm Size Classes 7-18
Table 7-13 Compliance Costs-to-Sales1 Ratios (Fugitive Emissions Requirements Low Impact Case) across Firm
Size Classes for Primary Scenario and Low Oil Price Scenario2 7-20
Table 7-14 Compliance Costs-to-Sales1 Ratios (Fugitive Emissions Requirements Low Impact Case) across Firm
Size Classes for Primary Scenario and Low Oil Price Scenario2 7-20
Table 7-15 Estimates of Labor Required to Comply with Proposed NSPS for Hydraulically Fractured Oil Well
Completions, 2020 and 2025 7-41
Table 7-16 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, Low Impact
Case, 2020 and 2025 7-42
Table 7-17 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive Emissions, High Impact
Case, 2020 and 2025 7-43
Table 7-18 Estimates of Labor Required to Comply with Proposed NSPS for Reciprocating and Centrifugal
Compressors, 2020 and 2025 7-44
Table 7-19 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic Controllers and Pumps,
2020 and 2025 7-45
Table 7-20 Estimates of Labor Required to Comply with Proposed NSPS, 2020 and 2025 7-46
IX
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LIST OF FIGURES
Figure 2-1 A) Domestic Crude Oil Proved Reserves and Cumulative Production, 1990-2013. B) Domestic
Natural Gas Proved Reserves and Cumulative Production, 1990-2013 2-12
Figure 2-2 A) Total Producing Crude Oil Wells and Average Well 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 Practice, 2007 2-19
Figure 2-4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990-2011 2-21
Figure 2-5 Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-2012 2-24
Figure 2-6 Forecast of Domestic Crude Oil Production and Net Imports, 2010-2040 2-29
Figure 2-7 Costs of Crude Oil and Natural Gas Wells Drilled, 1981-2008 2-31
Figure 2-8 Finding Costs for FRS Companies, 1981-2009 2-32
Figure 2-9 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2009 (3-year Running Average)..
2-33
Figure 2-10 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976
dollars), 1976-2009 2-34
Figure 2-11 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas Price, 1976-2009
2-35
Figure 4-1 Path from GHG Emissions to Monetized Damages 4-10
Figure 4-2 2005 NATA Model Estimated Census Tract Carcinogenic Risk from HAP Exposure from All
Outdoor Sources based on the 2005 National Toxics 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
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1 EXECUTIVE SUMMARY
1.1 Background
The action analyzed in this regulatory impact analysis (RIA) proposes to amend the new
source performance standards (NSPS) for the oil and natural gas source category by setting
standards for both methane and volatile organic compounds (VOC) for certain equipment,
processes and activities across this source category.
The Environmental Protection Agency (EPA) is including requirements for methane
emissions in this proposal because methane is a greenhouse gas (GHG), and the oil and natural
gas category is currently one of the country's largest emitters of methane. In 2009, the EPA
found that by causing or contributing to climate change, GHGs endanger both the public health
and the public welfare of current and future generations.
The EPA is proposing to amend the NSPS to include standards for reducing methane as
well as VOC emissions across the oil and natural gas source category. Specifically, we are
proposing both methane and VOC standards for several emission sources not currently covered
by the NSPS (i.e., hydraulically fractured oil well completions, fugitive emissions from well sites
and compressor stations, pneumatic pumps). In addition, we are proposing methane standards for
certain emission sources that are currently regulated for VOC (i.e., hydraulically fractured gas
well completions, equipment leaks at natural gas processing plants). However, we do not expect
any incremental benefits or costs as a result from regulating methane for currently regulated
VOC sources.
With respect to certain equipment that are used across the source category, the current
NSPS regulates only a subset of these equipment (pneumatic controllers, centrifugal
compressors, reciprocating compressors). The proposed amendents would establish methane
standards for these equipment across the source category and extend the current VOC standards
to the remaining unregulated equipment. Lastly, amendments to the current NSPS are being
proposed that improve several aspects of the current standards related to implementation. These
improvements result from reconsideration of certain issues raised in petitions for reconsideration
that were received by the Administrator on the August 16, 2012, final NSPS for the oil and
1-1
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natural gas sector and related amendments. Except for these implementation improvements and
the setting of standards for methane, these amendments do not change the requirements for
operations already covered by the current standards.
As part of the regulatory process, the EPA is required to develop a regulatory impact
analysis (RIA) for rules that have costs or benefits that exceed $100 million annually. The EPA
estimates the proposed NSPS will have costs that exceed $100 million, so the Agency has
prepared an RIA. This RIA includes an economic impact 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 impacts 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 illustrate how new and modified sources accumulate over time under
the proposed NSPS. The regulatory impact estimates for 2025 include sources newly affected in
2025 as well as the accumulation of affected sources from 2020 to 2024 that are also assumed to
be in continued operation in 2025, thus incurring compliance costs and emissions reductions in
2025.
Several emission controls for the NSPS, such as reduced emissions completions (RECs)
of hydraulically-fractured oil wells, capture methane and VOC emissions that otherwise would
be vented to the atmosphere. The averted methane 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 implementing 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.
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The baseline used for the impacts analysis of our NSPS takes into account emissions
reductions conducted pursuant to state regulations covering the relevant operations. More
detailed discussion on the derivation of the baseline is presented in Section 3 of this RIA.
1.2 Market Failure
Many regulations are promulgated to correct market failures, which lead to a suboptimal
allocation of resources within the free market. Air quality and pollution control regulations
address "negative externalities" whereby the market does not internalize the full opportunity cost
of production borne by society as public goods such as air quality are unpriced.
Greenhouse Gas (GHG) and VOC emissions impose costs on society, such as negative
climate, health, and welfare impacts that are not 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 oil, natural gas, and other hydrocarbon products.
These social costs associated with the climate, health, and welfare impacts are referred to as
negative externalities. If an oil 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 producing the products. All else equal, given this externality, the
quantity of oil and natural gas produced in a free market will not be at the socially optimal level.
More oil and natural gas will be produced than would occur if the power producers had to
account for the full opportunity cost of production including the negative externality.
Consequently, absent a regulation on emissions, the marginal social cost of the last units of oil
and natural gas produced will exceed its marginal social benefit.
1.3 Regulatory Options Analyzed in this RIA
In this RIA, we examine three broad regulatory options.2 Table 1-1 shows the emissions
2 See Chapter 3 for a detailed discussion of the comparative impacts of the regulatory options. The EPA also
analyzed a variant of proposed Option 2 where only emissions combustion is required for hydraulically fractured
and re-fracture oil well completions, rather than require reduced emissions completions (RECs) in combination
with combustion. This variation of the proposed Option 2 would achieve direct emission reduction that are
equivalent to requiring RECs and combustion, but at an approximately $70 million per year lower cost.
1-3
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sources, points, and controls for the three NSPS regulatory options analyzed in this RIA, which
we term Option 1, Option 2, and Option 3. Option 2 was selected for proposal. Option 1 was
selected for co-proposal.
Table 1-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS
Emissions Point
Emissions Control Option 1
Option 2
(proposed)
Option 3
Well Completions and Recompletions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured Wildcat
and Delineation Oil Wells
Fugitive Emissions
Well Pads
Gathering and Boosting Stations
Transmission Compressor Stations
Pneumatic Pumps
Well Pads
Gathering and Boosting Stations
Transmission and Storage
Compressor Stations
Pneumatic Controllers -
Natural Gas Transmission and
Storage Stations
Reciprocating Compressors
Natural Gas Transmission and
Storage Stations
Centrifugal Compressors
Natural Gas Transmission and
Storage Stations
RFC / Combustion
Combustion
Monitoring and
Maintenance
Monitoring and
Maintenance
Monitoring and
Maintenance
Route to control
Route to control
Route to control
Emissions limit
Annual Monitoring
and Maintenance
Route to control
X
X
X
X
X
X
X
X
X
Annual Semiannual Quarterly
Semiannual Semiannual Quarterly
Semiannual Semiannual Quarterly
XXX
XXX
XXX
X
X
X
X
The proposed Option 2 contains reduced emission completion (REC) and completion
combustion requirements for a subset of newly completed oil wells that are hydraulically
fractured or refractured. Option 2 also requires fugitive emissions survey and repair programs be
However, as explained in Section VIII.F of the preamble to the proposed NSPS, the EPA determined RECs and
combustion to be the best system of emissions reduction. Section 4 of the Technical Support Document for the
proposal presents the detailed technical analysis of the regulatory options for hydraulically fractured and re-
fractured oil well completions.
1-4
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performed semiannually (twice per year) at newly drilled or refractured oil and natural gas well
sites, new or modified gathering and boosting stations, and new or modified transmission and
storage compressor stations. However, low production well sites are exempt from the well site
fugitive requirements. A low production site is defined by the average combined oil and natural
gas production for the wells at the site being less than 15 barrels of oil equivalent (boe) per day.3
Option 2 also requires reductions from centrifugal compressors, reciprocating compressors,
pneumatic controllers, and pneumatic pumps throughout the oil and natural gas source category.
While the EPA is proposing an exclusion from fugitive emission requirements for low
production well sites, there is uncertainty in how many well sites this exclusion might affect in
the future. As a result, the analyses in this RIA presents a "low" impact case and "high" impact
case for fugitive emissions requirements at well sites. The low impact case excludes from
analysis an estimate low production sites, assuming that the fraction of wells meeting the low
production criteria in the future will be the same as in 2012 (based on the first month of
production data from wells newly completed or modified in 2012).The high impact case includes
all forecasted well sites providing a bounding case where no newly completed or modified wells
meet the low production criteria. Summary results for option 2, then, are presented as ranges.
Options 1 and 3 differ from the Option 2 with respect to the requirements for fugitive
emissions. Meanwhile, the co-proposed Option 1 requires annual monitoring for well sites,
including low production sites, while maintaining semiannual requirements for others sites. The
more stringent 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 over the co-proposed Option 2.
1.4 Summary of Results
For the proposed NSPS, the key results of the RIA follow and are summarized in Table
1-2 through Table 1-4. Note all dollar estimates are in 2012 dollars:
• Emissions Analysis: The proposed NSPS is anticipated to prevent significant new
emissions, including 170,000 to 180,000 tons of methane, 120,000 tons of VOCs and 310
3 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels of crude oil
equals 1000 cubic feet natural gas.
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to 400 tons of hazardous air pollutants (HAP) in 2020, increasing to 340,000 to 400,000
tons of methane, 170,000 to 180,000 tons of VOCs, and 1,900 to 2,500 tons of HAP
prevented in 2025.4 The CCh-equivalent (CO2 Eq.) methane emission reductions are 3.8
to 4.0 million metric tons in 2020 and 7.7 to 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-CH4).5 The
EPA estimates that, in 2020, the proposal will yield monetized climate benefits of $88
million to approximately $550 million; the mean SC-CH4 at the 3% discount rate results
in an estimate of about $200 to $210 million in 2020. In 2025, the EPA estimates
monetized climate benefits of $220 million to approximately $1.4 billion; the mean SC-
CH4 at the 3% discount rate results in an estimate of about $460 to $550 million in 2025.6
While we expect that the avoided emissions will result in improvements in ambient air
quality and reductions in health effects associated with exposure to HAP, ozone, and
particulate matter (PM), we have determined that quantification of those benefits cannot
be accomplished for this rule.7 This is not to imply that there are no health benefits
anticipated from the proposed rule; rather, it is a reflection of the difficulties in modeling
the direct and indirect impacts of the reductions in emissions for this industrial sector
with the data currently available. In addition to health improvements, there will be
improvements in visibility effects, ecosystem effects, as well as additional natural gas
recovery. The specific control technologies for the proposed NSPS are anticipated to
have minor secondary disbenefits.
Engineering Cost Analysis: The EPA estimates the total capital cost of the proposed
NSPS to be $170 to $180 million in 2020 and $280 to $330 million in 2025. The estimate
of total annualized engineering costs of the proposed NSPS is $180 to $200 million in
2020 and $370 to $500 million in 2025 when using a 7 percent discount rate. When
estimated revenues from additional natural gas are included, the annualized engineering
costs of the proposed NSPS are estimated to be $150 to $170 million in 2020 and $320 to
$420 million in 2025, assuming a wellhead natural gas price of $4/thousand cubic feet
(Mcf). The estimated engineering compliance costs that include the product recovery are
sensitive to the assumption about the price of the recovered product. There is also
geographic variability in wellhead prices, which can also influence estimated engineering
costs. For example, $l/Mcf change in the wellhead price causes a change in estimated
4 Estimates are presented in short tons.
5 The social cost of methane (SC-CH4) is the monetary value of impacts associated with a marginal change in
methane emissions in a given year.
6 The range of estimates reflects four SC-CH4 estimates are associated with different discount rates (model average
at 2.5, 3 and 5 percent; 95th percentile at 3 percent). See Section 4.3 for a complete discussion.
7 Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the
effect that those emissions have on ambient PM2.s levels and the health effects associated with PM2.s 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 all sectors. Coupled with the larger uncertainties about
the relationship between VOC emissions and PM2.s and the highly localized nature of air quality responses
associated with VOC reductions, these factors lead us to conclude that the available VOC benefit-per-ton
estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding exercise.
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engineering compliance costs of about $8 million in 2020 and $16 to $19 million in 2025,
given the EPA estimates that about 8 million Mcf in 2020 and 16 to 19 million Mcf of
natural gas will be recovered by implementing the NSPS. When using a 3 percent
discount rate, the estimate of total annualized engineering costs of the proposed NSPS is
$200 million in 2020 and $490 million in 2025, or $150 to $170 million in 2020 and $310
to $420 million in 2025, when estimated revenues from additional natural gas are
included.8
• Energy System Impacts Analysis: The EPA used the National Energy Modeling System
(NEMS) to estimate the impacts of the proposed rule on the United States energy
system.9 We estimate that natural gas and crude oil production levels remains essentially
unchanged in 2020, while slight declines are estimated for 2025 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. Meanwhile, well crude oil prices for onshore
lower 48 production are not estimated to change, despite the incidence of new
compliance costs from the proposed NSPS. Meanwhile, net imports of natural gas are
estimated to decline slightly in 2020 (by about 1 bcf or 0.05 percent) and in 2025 (by
about 3 bcf or 0.09 percent). Crude oil imports are estimated to not change in 2020 and
increase by about 1,000 barrels per day (or 0.02 percent) in 2025.
• Small Entity Analyses: To understand the potential impact of the proposed rule of small
entities the EPA conducted a screening analysis of the potential impacts by estimating the
ratio of potential compliance costs to firm sales (i.e. a cost-to-sales test). Based on the
results of this screening analysis, the EPA concluded it is not able to certify that the
proposed rule will not have a Significant Impact on a Substantial Number of Small
Entities (SISNOSE). As a result, the EPA initiated a Small Business Advisory Review
panel and completed an Initial Regulatory Flexibility Analysis.
• Employment Impacts Analysis: The EPA estimated the labor impacts due to the
installation, operation, and maintenance of control equipment and control activities, as
well as the labor associated with new reporting and recordkeeping requirements. We
estimated one-time and continual, annual labor requirements by estimating hours of labor
required for compliance and converting this number to full-time equivalents (FTEs) by
dividing by 2,080 (40 hours per week multiplied by 52 weeks). The one-time labor
requirement to comply with the proposed NSPS is estimated at about 50 to 70 FTEs in
2020 and in 2025. The annual labor requirement to comply with proposed NSPS is
estimated at about 470 to 530 FTEs in 2020 and 1,100 to 1,400 FTEs in 2025. We note
that this type of FTE estimate cannot be used to identify the specific number of people
8 The choice of discount rate has a small effect on nationwide annualized costs. The compliance costs related to oil
well completions and fugitive emissions surveys occur in each year, so the interest rate has little impact on
annualized costs for these sources. The annualized costs for pneumatic pumps, 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.
1 The EPA only modeled the high impact case of the proposed NSPS with respect the low production exemption
from the well site fugitive emissions requirements. As such the NEMS-based estimates of energy system impacts
are likely high end estimates.
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involved or whether new jobs are created for new employees, versus displacing jobs from
other sectors of the economy.
Table 1-2 presents the summary results for co-proposed Option 1, Table 1-3 presents
summary results for the co-proposed Option 2, and Table 1-4 presents summary results for
Option 3. The summary results for Option 2 reflects the range from the low impacts to high
impacts case with respect the well site fugitive emissions requirements.
Table 1-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in
2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$200 million
$150 million
$43 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 120,000 tons of VOC
reduced
Health effects of HAP exposure from
310 tons of HAP reduced
Health effects of ozone exposure from
170,000 tons of methane
Visibility impairment
Vegetation effects
$470 million
$310 million
$160 million
Non-monetized climate benefits
Health effects of PM2.s and ozone
exposure from 170,000 tons of VOC
reduced
Health effects of HAP exposure from
1,900 tons of HAP reduced
Health effects of ozone exposure from
340,000 tons of methane
Visibility impairment
Vegetation effects
1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4)
(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes of
this table, we show the benefits associated with the model average a 3 percent discount rate. However, we
emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the
additional benefit estimates range from $89 million to $530 million in 2020 and $220 million to $1,200 million in
2025 for the proposed option, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission
reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control
technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for
details.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue
from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for
the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not
change when using a 3 percent discount rate.
3 Estimates may not sum due to independent rounding.
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Table 1-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2
(Proposed Option) in 2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$200 to $210 million
$150 to $170 million
$35 to $42 million
Non-monetized climate benefits
Health effects of PM2.s and ozone
exposure from 120,000 tons of VOC
reduced
Health effects of HAP exposure from
310 to 400 tons of HAP reduced
$460 to $550 million
$320 to $420 million
$120 to $150 million
Non-monetized climate benefits
Health effects of PM2.s and ozone
exposure from 170,000 to 180,000
tons of VOC reduced
Health effects of HAP exposure from
1,900 to 2,500 tons of HAP reduced
Health effects of ozone exposure from Health effects of ozone exposure from
170,000 to 180,000 tons of methane 340,000 to 400,000 tons of methane
Visibility impairment
Vegetation effects
Visibility impairment
Vegetation effects
1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4)
(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes of
this table, we show the benefits associated with the model average a 3 percent discount rate. However, we
emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the
additional benefit estimates range from $88 million to $550 million in 2020 and $250 million to $1,400 million in
2025 for the proposed option, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission
reductions are 3.8 to 4.0 million metric tons in 2020 and 7.7 to 9.0 million metric tons in 2025. Also, the specific
control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7
for details.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue
from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for
the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not
change when using a 3 percent discount rate.
3 Estimates may not sum due to independent rounding.
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Table 1-4 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in
2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$220 million
$210 million
$7.6 million
Non-monetized climate benefits
Health effects of PMi.s and ozone
exposure from 130,000 tons of VOC
reduced
Health effects of HAP exposure from
510 tons of HAP reduced
Health effects of ozone exposure from
190,000 tons of methane
Visibility impairment
Vegetation effects
$640 million
$680 million
-$35 million
Non-monetized climate benefits
Health effects of PMi.5 and ozone
exposure from 200,000 tons of VOC
reduced
Health effects of HAP exposure from
3,200 tons of HAP reduced
Health effects of ozone exposure from
470,000 tons of methane
Visibility impairment
Vegetation effects
1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4)
(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes
of this table, we show the benefits associated with the model average at a 3 percent discount rate. However we
emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the
additional benefit estimates range from $99 million to $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 COi-equivalent (COi Eq.) methane emission
reductions are 4.2 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control
technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.
2 The engineering compliance costs are annualized 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.
1.5 Organization of this Report
The remainder of this report details the methodology 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 presents the benefits analysis. Section 5 presents
statutory and executive order analyses. Section 6 presents a comparison of benefits and costs.
Section 7 presents energy system impact, employment impact, and small entity impact analyses.
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2 INDUSTRY PROFILE
2.1 Introduction
The oil and natural gas industry 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 products and processes of the drilling and extraction
of crude oil and natural gas, natural gas processing, and natural gas transportation segments.
Most crude oil and natural gas production facilities are classified under NAICS 211:
Crude Petroleum and Natural Gas Extraction (211111) and Natural Gas Liquid Extraction
(211112). The drilling of oil and natural gas wells is included in NAICS 213111. Most natural
gas transmission and storage facilities are classified under NAICS 486210—Pipeline
Transportation of Natural Gas. While other NAICS (221210—Natural Gas Distribution,
486110—Pipeline Transportation of Crude Oil, and 541360—Geophysical Surveying and
Mapping Services) are often included in the oil and natural gas sector, these are not discussed in
detail in the Industry Profile because they are not directly affected by the proposed NSPS.
The outputs of the oil and natural gas industry are inputs for larger production processes
of gas, energy, and petroleum products. As of 2013, the Energy Information Administration
(EIA) estimates that about 490,000 producing natural gas wells operated in the U.S. The latest
available information from EIA indicates there were about 360,000 producing oil wells in the
U.S. as of 2009. Domestic dry natural gas production 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 crude oil production in
2013 was 2,716 million barrels (bbl), the highest annual level in the U.S. since 1991. The leading
five crude oil producing states are Texas, North Dakota, California, Alaska, and Oklahoma.
The Industry Profile provides a brief introduction to the components of the oil and natural
gas industry that are relevant to the proposed NSPS. The purpose is to give the reader a general
understanding of the geophysical, engineering, and economic aspects of the industry that are
addressed in subsequent economic analysis in this RIA. The Industry Profile relies heavily on
background material from the EPA's "Economic Analysis of Air Pollution Regulations: Oil and
Natural Gas Production" (1996), the EPA's "Sector Notebook Project: Profile of the Oil and Gas
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Extraction Industry" (2000), and the 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 natural gas and reservoir characteristics are likely to be different
from that of any other reservoir.
2.2.1 Crude Oil
Crude oil can be broadly classified as paraffinic, naphthenic (or asphalt-based), or
intermediate. Generally, paraffinic crudes are used in the manufacture of lube oils and kerosene.
Paraffinic crudes have a high concentration of straight chain hydrocarbons and are relatively low
in sulfur compounds. Naphthenic crudes are generally used in the manufacture of gasolines and
asphalt and have a high concentration of olefin and aromatic hydrocarbons. Naphthenic crudes
may contain a high concentration of sulfur compounds. Intermediate crudes are those that are not
classified in either of the above categories.
Another classification measure of crude oil and other hydrocarbons is by API gravity.
API gravity is a weight per-unit volume measure of a hydrocarbon liquid as determined by a
method recommended by the American Petroleum Institute (API). A heavy or paraffinic crude
oil is typically one with API gravity of 20° or less, while a light or naphthenic crude oil, which
typically flows freely at atmospheric conditions, usually has API gravity in the range of the high
30's to the low 40's.
Crude oils recovered in the production phase may be referred to as live crudes. Live
crudes contain entrained or dissolved gases which may be released during processing or storage.
Dead crudes are those that have gone through various separation and storage phases and contain
little, if any, entrained or dissolved gases.
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2.2.2 Natural Gas
Natural gas is a mixture of hydrocarbons and varying quantities of non-hydrocarbons that
exists in a gaseous phase or in solution with crude oil or other hydrocarbon liquids in natural
underground reservoirs. Natural gas may contain contaminants, such as hydrogen sulfide (fhS),
COi, mercaptans, and entrained solids.
Natural gas may be classified as wet gas or dry gas. Wet gas is unprocessed or partially
processed natural gas produced from a reservoir that contains condensable 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 HiS are classified as sour
gases. Those with threshold concentrations of CO2 are classified as acid gases. The process by
which these two contaminants are removed from the natural gas stream is called sweetening. The
most common sweetening method is amine treating. Sour gas contains a HiS concentration of
greater than 0.25 grain per 100 standard cubic feet, along with the presence of COi.
Concentrations of HiS and COi, along with organic sulfur compounds, vary widely among sour
gases. A majority of total onshore natural gas production and nearly all offshore natural gas
production is classified as sweet.
2.2.3 Condensates
Condensates are hydrocarbons in a gaseous state under reservoir conditions, but become
liquid in either the wellbore or the production process. Condensates, including volatile oils,
typically have an API gravity of 40° or more. In addition, Condensates may include hydrocarbon
liquids recovered from gaseous streams from various oil and natural gas production or natural
gas transmission and storage processes and operations.
2.2.4 Other Recovered Hydrocarbons
Various hydrocarbons may be recovered through the processing of the extracted
hydrocarbon streams. These hydrocarbons include mixed natural gas liquids (NGL), natural
gasoline, propane, butane, and liquefied petroleum gas (LPG).
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2.2.5 Produced Water
Produced water is the water recovered from a production well. Produced water is
separated from the extracted hydrocarbon streams in various production processes and
operations.
2.3 Oil and Natural Gas Production Processes
2.3.7 Exploration and Drilling
Exploration involves the search for rock formations associated with oil or natural gas
deposits and involves geophysical prospecting and/or exploratory drilling. Well development
occurs after exploration has located an economically recoverable field and involves the
construction of one or more wells from the beginning (called spudding) to either abandonment if
no hydrocarbons are found or to well completion if hydrocarbons are found in sufficient
quantities.
After the site of a well has been located, drilling commences. A well bore is created by
using a rotary drill to drill into the ground. As the well bore gets deeper sections of drill pipe are
added. A mix of fluids called drilling mud is released down into the drill pipe then up the walls
of the well bore, which removes drill cuttings by taking them to the surface. The weight of the
mud prevents high-pressure reservoir fluids from pushing their way out ("blowing out"). The
well bore is cased in with telescoping steel piping during drilling to avoid its collapse and to
prevent water infiltration into the well and to prevent crude oil and natural gas from
contaminating the water table. The steel pipe is cemented by filling the gap between the steel
casing and the wellbore with cement.
Horizontal drilling technology has been available since the 1950s. Horizontal drilling
facilitates the construction of horizontal wells by allowing for the well bore to run horizontally
underground, increasing the surface area of contact between the reservoir and the well bore so
that more oil or natural gas can move into the well. Horizontal wells are particularly useful in
unconventional gas extraction where the gas is not concentrated in a reservoir. Recent advances
have made it possible to steer the drill in different directions (directional drilling) from the
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surface without stopping the drill to switch directions and allowing for a more controlled and
precise drilling trajectory.
Hydraulic fracturing (also referred to as "Tracking") has been performed since the 1940s
(U.S. DOE, 2013). Hydraulic fracturing involves pumping fluids into the well under very high
pressures in order to fracture the formation containing the resource. Proppant is a mix of sand
and other materials that is pumped down to hold the fractures open to secure gas flow from the
formation (U.S. EPA, 2004).
2.3.2 Production
Production is the process of extracting the hydrocarbons and separating the mixture of
liquid hydrocarbons, gas, water, and solids, removing the constituents that are non-saleable, and
selling the liquid hydrocarbons and gas. The major activities of crude oil and natural gas
production are bringing the fluid to the surface, separating the liquid and gas components, and
removing impurities.
Oil and natural gas are found in the pores of 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 reached. Because the oil and natural gas can travel
no further, the liquids and gases accumulate in a reservoir. Where oil and gas are associated, a
gas cap forms above the oil. Natural gas is extracted from a well either because it is associated
with oil in an oil well or from a pure natural gas reservoir. Once a well has been drilled to reach
the reservoir, the oil and gas can be extracted in different ways depending on the well pressure
(Hyne, 2001).
Frequently, oil and natural gas are produced from the same reservoir. As wells deplete the
reservoirs into which they are drilled, the gas to oil ratio increases (as does the ratio of water to
hydrocarbons). This increase of gas over oil occurs because natural gas usually is in the top of
the oil formation, while the well usually is drilled into the bottom portion to recover most of the
liquid. Production sites often handle crude oil and natural gas from more than one well (Hyne,
2001).
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Well pressure is required to move the resource 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. Typically, about 30 to 35 percent of the resource in
the reservoir is extracted this way (Hyne, 2001). The amount extracted depends on the specific
well characteristics (such as permeability and oil viscosity). Lacking enough pressure for the
resource to surface, gas or water is injected into the well to increase the well pressure and force
the resource out (secondary or improved oil recovery). Finally, in tertiary extraction or
enhanced recovery, gas, chemicals or steam are injected into the well. This can result in
recovering up to 60 percent of the original amount of oil in the reservoir (Hyne, 2001).
In contrast to conventional sources, unconventional oil and gas are trapped in rock or
sand or, in the case of oil, are found in rock as a chemical substance that requires a further
chemical transformation to become oil (U.S. DOE, 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 type of extraction method needed depends on the
type of formation where the resource is located. Unconventional oil and natural gas resource
types relevant for this rule include:
• Shale Oil and Natural Gas: Shale natural gas comes from sediments of clay mixed with
organic matter. These sediments form low permeability shale rock formations that do not
allow the gas to move. To release the gas, the rock must be fragmented, making the
extraction 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 migrated from other sources. Extraction of the
natural gas from tight gas reservoirs is often performed using horizontal wells. Hydraulic
fracturing is often used in tight sands (U.S. DOE, 2013).
• Coalbed Methane: Natural gas is present in a coal bed due to the activity of microbes in
the coal or from alterations of the coal through temperature changes. Horizontal drilling
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is used but given that coalbed methane reservoirs are frequently associated with
underground water reservoirs, hydraulic fracturing is often restricted (Andrews, 2009).
2.3.3 Natural Gas Processing
Natural gas conditioning is the process of removing impurities from the gas stream so
that it is of sufficient quality to pass through transportation systems and used by final consumers.
Conditioning is not always required. Natural gas from some formations emerges from the well
sufficiently pure that it can be sent directly to the pipeline. As the natural gas is separated from
the liquid components, it may contain impurities that pose potential hazards or other problems.
The most significant impurity is HiS, which may or may not be contained in natural gas.
IHbS is toxic (and potentially fatal at certain concentrations) to humans and is corrosive for pipes.
It is therefore desirable to remove IHbS as soon as possible in the conditioning process.
Another concern is that posed by water vapor. At high pressures, water can react with
components in the gas to form gas hydrates, which are solids that can clog pipes, valves, and
gauges, especially at cold temperatures (Manning and Thompson, 1991). Nitrogen and other
gases may also be mixed with the natural gas in the subsurface. These other gases must be
separated from the methane prior to sale. High vapor pressure hydrocarbons that are liquids at
surface temperature and pressure (benzene, toluene, ethylbenzene, and xylene, or BTEX) are
removed and processed separately.
Dehydration removes water from the gas stream. Three main approaches toward
dehydration are the use of a liquid or solid desiccant, and refrigeration. When using a liquid
desiccant, the gas is exposed to a glycol that absorbs the water. The water can be evaporated
from the glycol by a process called heat regeneration. The glycol can then be reused. Solid
desiccants, often materials called molecular sieves, are crystals with high surface areas that
attract the water molecules. The solids can be regenerated simply by heating them above the
boiling point of water. Finally, particularly for gas extracted from deep, hot wells, simply cooling
the gas to a temperature below the condensation point of water can remove enough water to
transport the gas. Of the three approaches mentioned above, glycol dehydration is the most
common when processing at or near the well.
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Sweetening is the procedure in which IHbS and sometimes CO2 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 HiS and separate them from the natural gas. The
contaminant gas solution is then heated, thereby separating the gases and regenerating the amine.
The sulfur gas may be disposed of by flaring, incinerating, or when a market exists, sending it to
a sulfur-recovery facility to generate elemental sulfur as a salable product.
2.3.4 Natural Gas Transmission and Distribution
After processing, natural gas enters a network of compressor stations, high-pressure
transmission pipelines, and often-underground storage sites. Compressor stations are any facility
which supplies energy to move natural gas at increased pressure in transmission pipelines or into
underground storage. Typically, compressor stations are located at intervals along a transmission
pipeline to maintain desired pressure for natural gas transport. These stations will use either large
internal combustion engines or gas turbines as prime movers to provide the necessary
horsepower to maintain system pressure. Underground storage facilities are subsurface facilities
utilized for storing natural gas which has been transferred from its original location for the
primary purpose of load balancing, which is the process of equalizing the receipt and delivery of
natural gas. Processes and operations that may be located at underground storage facilities
include compression and dehydration.
2.4 Reserves and Markets
Crude oil and natural gas have historically served two separate and distinct markets. Oil
is an international commodity, transported and 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 increasingly a national and
international commodity. The following subsections provide historical and forecast data on the
U.S. reserves, production, consumption, and foreign trade of crude oil and natural gas.
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2.4.1 Domestic Proved Reserves
Table 2-1 shows crude oil and dry natural gas proved reserves, unproved reserves, and
total technically recoverable resources as of 2009. According to EIA10, these concepts are defined
as:
• Proved reserves: estimated quantities of energy sources that analysis of geologic and
engineering data demonstrates with reasonable certainty are recoverable under
existing economic and operating conditions.
• Unproved resources: additional volumes estimated to be technically recoverable
without consideration of economics or operating conditions, based on the application
of current technology.
• 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-grade natural gas. The dry natural gas volumes
reported in Table 2-1 reflect the amount of gas remaining after liquefiable portion has been
removed from the natural gas, as well as any non-hydrocarbon gases that render the natural gas
unmarketable have been removed. The sum of proved reserves and unproved reserves equal the
total technically recoverable resources. As seen in Table 2-1, as of 2009, proved domestic crude
oil reserves accounted for about 10 percent of the totally technically recoverable crude oil
resources.
10 U.S. Department of Energy, Energy Information Administration, Glossary of Terms
Accessed 12/21/2010.
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Table 2-1 Technically Recoverable Crude Oil and Natural Gas Resource
Estimates, 2009
Region
Crude Oil and Lease Condensate (billion barrels)
48 States Onshore
48 States Offshore
Alaska
Total U.S.
Dry Natural Gas (trillion cubic feet)
Conventionally Reservoired Fields
48 States Onshore 1
48 States Offshore
Alaska
Tight Gas, Shale Gas and Coalbed Methane
Total U.S.
Proved Reserves
14.2
4.6
3.6
22.3
105.5
81.4
15.0
9.1
167.1
272.5
Unproved
Resources
112.6
50.3
35.0
197.9
904.0
369.7
262.6
271.7
1,026.7
1,930.7
Total Technically
Recoverable
Resources
126.7
54.8
38.6
220.2
1,009.5
451.1
277.6
280.8
1,193.8
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 crude oil reservoirs either as free gas (associated) or as gas
in solution with crude oil (dissolved gas).
Proved natural gas reserves accounted for about 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 estimated 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 percent) is considered
to be wet associated-dissolved natural gas. Associated-dissolved natural gas, according to EIA, is
natural gas which occurs in crude oil reservoirs as free natural gas or in solution with crude oil.
Table 2-2 and Figure 2-1 show trends in crude oil and natural gas production and reserves
from 1990 to 2013. In Table 2-2, proved ultimate recovery equals the sum of cumulative
production and proved reserves. While crude oil and natural gas are nonrenewable resources, the
table shows that proved ultimate recovery rises over time as new discoveries become
2-10
-------
economically accessible. Reserves growth and decline is also partly a function of exploration
activities, which are correlated with oil and natural gas prices. For example, when oil prices are
high there is more of an incentive to use secondary and tertiary recovery, as well as to develop
unconventional sources.
Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Production, Proved
Reserves, and Proved Ultimate Recovery, 1977-2013
Crude Oil and Lease Condensate
(million barrels)
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Cumulative
Production
158,175
160,882
163,507
166,006
168,437
170,831
173,197
175,552
177,834
179,981
182,112
184,229
186,326
188,388
190,379
192,270
194,127
195,981
197,811
199,763
201,764
203,825
206,202
208,918
Proved
Reserves
26,254
24,682
23,745
22,957
22,457
22,351
22,017
22,546
21,034
21,765
22,045
22,446
22,677
21,891
21,371
21,757
20,972
21,317
19,121
20,682
23,267
26,544
30,529
33,371
Proved Ult.
Recovery
184,429
185,564
187,252
188,963
190,894
193,182
195,214
198,098
198,868
201,746
204,157
206,675
209,003
210,279
211,750
214,027
215,099
217,298
216,932
220,445
225,031
230,369
236,731
242,289
Dry Natural Gas
(Billion Cubic Feet or bcf)
Cumulative
Production
744,546
762,244
780,084
798,179
817,000
835,599
854,453
873,355
892,379
911,211
930,393
950,009
968,937
988,036
1,006,627
1,024,677
1,043,181
1,062,447
1,082,605
1,103,229
1,124,545
1,147,447
1,171,480
1,195,814
Proved
Reserves
169,346
167,062
165,015
162,415
163,837
165,146
166,474
167,223
164,041
167,406
177,427
183,460
186,946
189,044
192,513
204,385
211,085
237,726
244,656
272,509
304,625
334,067
308,036
338,264
Proved Ult.
Recovery
913,892
929,306
945,099
960,594
980,837
1,000,745
1,020,927
1,040,578
1,056,420
1,078,617
1,107,820
1,133,469
1,155,883
1,177,080
1,199,140
1,229,062
1,254,266
1,300,173
1,327,261
1,375,738
1,429,170
1,481,514
1,479,516
1,534,078
Source: U.S. Energy Information Administration
However, annual production as a percentage of proved reserves has declined over time for both
crude oil and natural gas, from above 11 percent in the early 1990s to 8 to 10 percent over the
2-11
-------
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.
300,000
250,000 -
3 200,000 -
- 150,000 -
M
100,000 -
50,000 -
0
•o
A). Crude Oil
a
O
2
3
a
Z
1,800,000
1,600,000 -
1,400,000 -
1,200,000 -
1,000,000 -
800,000 -
600,000 -
400,000 -
200,000 -
0
B). Natural Gas
'V 'Y
D Cumulative Production D Proved Reserves
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 account for 81 percent of the U.S. total proved
reserves of crude oil, led by Texas and followed by North Dakota, U.S. Federal Offshore,
Alaska, and California. The top five states (Texas, Pennsylvania, Wyoming, Oklahoma, and
West Virginia) account for about 65 percent of the U.S. total proved reserves of natural gas.
2-12
-------
Table 2-3 Crude Oil
State/Region
Alabama
Alaska
Arkansas
California
Colorado
Florida
Kansas
Kentucky
Louisiana
Michigan
Miscellaneous States
Mississippi
Montana
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
Texas
U.S. Federal Offshore
Utah
West Virginia
Wyoming
Total Proved Reserves
and Dry Natural
Crude Oil
(million bbls)
44
2,898
40
2,876
896
38
372
17
503
64
105
223
413
1,171
*
5,677
42
1,019
15
10,468
5,137
613
17
723
33,371
Gas Proved Reserves by State, 2013
Dry Natural Gas
(bcf)
1,597
7,316
13,518
1,887
22,381
15
3,592
1,663
20,164
1,807
2,552
595
575
13,576
144
5,420
3,161
26,873
49,674
90,349
8,193
6,829
22,765
33,618
338,264
Crude Oil Dry Natural Gas
( % of total) ( % of total)
0.1
8.7
0.1
8.6
2.7
0.1
1.1
0.1
1.5
0.2
0.3
0.7
1.2
3.5
*
17.0
0.1
3.1
0.0
31.4
15.4
1.8
0.1
2.2
100.0
0.5
2.2
4.0
0.6
6.6
0.0
1.1
0.5
6.0
0.5
0.8
0.2
0.2
4.0
0.0
1.6
0.9
7.9
14.7
26.7
2.4
2.0
6.7
9.9
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 decline that began in 1970 and continued to a
low point in 2008. Since 2008, domestic oil production has recovered to the highest levels since
1991. Table 2-4 shows U.S. production in 2013 at 2,716 million bbl per year.
2-13
-------
Table 2-4 Crude Oil Domestic Production, Wells, Well Productivity, and
U.S. Average First Purchase Price, 1990-2013
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Total
Production
(million barrels)
2,685
2,707
2,625
2,499
2,431
2,394
2,366
2,355
2,282
2,147
2,131
2,118
2,097
2,062
,991
,891
,857
,853
,830
,953
2,001
2,060
2,378
2,716
Producing Wells
(1000s)
602
614
594
584
582
574
574
573
562
546
534
530
529
513
510
498
497
500
526
526
520
536
N/A
N/A
Avg. Well
Productivity
(bbl/well)
4,460
4,409
4,419
4,279
4,178
4,171
4,122
4,110
4,060
3,932
3,990
3,995
3,963
4,019
3,905
3,798
3,737
3,706
3,479
3,712
3,848
3,844
N/A
N/A
US Average
First Purchase
Price/Barrel
(nominal
dollars)
20.03
16.54
15.99
14.25
13.19
14.62
18.46
17.23
10.87
15.56
26.72
21.84
22.51
27.56
36.77
50.28
59.69
66.52
94.04
56.35
74.71
95.73
94.52
95.99
US Average
First Purchase
Price/Barrel
(2012 dollars)
31.55
25.21
23.83
20.74
18.80
20.41
25.31
23.23
14.50
20.44
34.32
27.42
27.84
33.42
43.39
57.49
66.21
71.87
99.64
59.26
77.62
97.45
94.52
94.58
Source: U.S. Energy Information Administration
First purchase price represents the average price at the lease or wellhead at which domestic crude is purchased.
Prices adjusted using GDP Implicit Price Deflator.
Average well productivity has also generally decreased since 1990 (Table 2-4 and Figure 2-2).
These production and productivity decreases are in spite of the fact that average first purchase
prices have shown a generally increasing trend.
Annual production of natural gas from natural gas wells has increased more than 8000
bcf from the 1990 to 2013 (Table 2-5). The number of wells producing natural gas has nearly
doubled between 1990 and 2011 (Figure 2-2). While the number of producing wells has
increased overall, average well productivity has declined, despite improvements in exploration
and gas well stimulation technologies.
2-14
-------
A). Crude Oil Wells
700
g 600
£ 500
•| 300 --
"§ 200
£ 100
0
f 4,000 g
-- 3,000 S
H 1—I 1 1—I 1—I 1—I 1—I 1 1—I 1—I 1—I 1—h
5,000
-- 2,000;
-- 1,000^
O
o
cv>
ON
cv>
ON
-Producing Wells (1000s)
Avg. Well Productivity (bbl/well)
B). Natural Gas Wells
I
70
60
50
40
30
20
10
0
600,000
- - 500,000 „,
a
- - 400,000 O
_l 1 1_
H 1 1 h
_l 1 1_
- - 300,000
- - 200,000
-- 100,000
0
| §
- Avg. Well Productivity (MMcf/year)
-Producing Wells
Figure 2-2 A) Total Producing Crude Oil Wells and Average Well Productivity, 1990-
2011. B) Total Producing Natural Gas Wells and Average Well Productivity, 1990-2013.
Domestic exploration and development for oil has continued during the last two decades.
From 2002 to 2010, crude oil well drilling showed significant increases, although the 1992-2004
period showed relatively low levels of crude drilling activity compared to periods before and
after (Table 2-6). The drop in 2009 showed a departure from this trend, likely due to the
recession experienced in the U.S.
Meanwhile, natural gas drilling has increased significantly during the 1990-2010 period.
Like crude oil drilling, 2009 and 2010 saw a relatively low level of natural gas drillings. The
success rate of wells (producing wells versus dry wells) has also 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
2-16
-------
improvements in well drilling and completion. Similarly, 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
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009*
2010*
Crude Oil
12,445
12,035
9,019
8,764
7,001
7,827
8,760
10,445
6,979
4,314
8,090
8,888
6,775
8,129
8,789
10,779
13,385
13,371
16,633
11,190
15,753
Wells Drilled
Natural Gas Dry Holes
11,126
9,611
8,305
10,174
9,739
8,454
9,539
11,186
11,127
11,121
17,051
22,072
17,342
20,722
24,186
28,590
32,838
32,719
32,246
18,088
16,696
8,496
7,882
6,284
6,513
5,515
5,319
5,587
5,955
4,805
3,504
4,146
4,598
3,754
3,982
4,082
4,653
5,206
4,981
5,423
3,525
4,162
Total
32,067
29,528
23,608
25,451
22,255
21,600
23,886
27,586
22,911
18,939
29,287
35,558
27,871
32,833
37,057
44,022
51,429
51,071
54,302
32,803
36,611
Successful
Wells (%)
75
75
75
75
77
77
79
79
80
83
86
87
87
88
89
89
90
90
90
90
89
Average
Depth (ft)
4,881
4,920
5,202
5,442
5,795
5,636
5,617
5,691
5,755
5,090
4,961
5,087
5,232
5,426
5,547
5,508
5,613
6,064
5,964
6,202
6,108
Source: U.S. Energy Information Administration
* Average Depth values for 2009-2010 are estimates.
Produced water is an important byproduct of the oil and natural gas industry, as
management, including reuse and recycling, of produced water can be costly and challenging.
Texas, California, Wyoming, Oklahoma, and Kansas were the top five states in terms of
produced water volumes in 2007 (Table 2-7). These estimates do not include estimates of
flowback water from hydraulic fracturing activities (ANL 2009).
2-17
-------
Table 2-7 U.S. Onshore and Offshore Oil, Gas, and Produced Water Generation, 2007
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
Virginia
West Virginia
Wyoming
State Total
Federal
Offshore
Tribal Lands
Federal Total
U.S. Total
Barrels
Total Oil and Produced
Natural Gas Water per
Crude Oil Total Gas Produced Water (1000 bbls oil Barrel Oil
(1000 bbl) (bcf) (1000 bbl) equivalent) Equivalent
5,028
263,595
43
6,103
244,000
2,375
2,078
3,202
1,727
36,612
3,572
52,495
5,180
20,027
80
34,749
2,335
408
59,138
378
44,543
5,422
60,760
1,537
1,665
350
342,087
19,520
19
679
54,052
7,273,759
467,180
9,513
476,693
1,750,452
285
3,498
1
272
312
1,288
2
no data
4
371
95
1,382
168
97
no data
95
1
0
1,526
55
71
86
1,643
172
12
1
6,878
385
112
225
2,253
21,290
2,787
297
3,084
24,374
119,004
801,336
68
166,011
2,552,194
383,846
50,296
136,872
40,200
1,244,329
24,607
1,149,643
114,580
330,730
1,613
182,266
49,312
6,785
665,685
649
134,991
6,940
2,195,180
3,912
4,186
2,263
7,376,913
148,579
1,562
8,337
2,355,671
20,258,560
587,353
149,261
736,614
20,995,174
55,758
886,239
221
54,519
299,536
231,639
2,434
3,202
2,439
102,650
20,482
298,491
35,084
37,293
80
51,659
2,513
408
330,766
10,168
57,181
20,730
353,214
32,153
3,801
528
1,566,371
88,050
19,955
40,729
455,086
5,063,379
963,266
62,379
1,025,645
6,089,024
2.13
0.90
0.31
3.05
8.52
1.66
20.66
42.75
16.48
12.12
1.20
3.85
3.27
8.87
20.16
3.53
19.62
16.63
2.01
0.06
2.36
0.33
6.21
0.12
1.10
4.29
4.71
1.69
0.08
0.20
5.18
4.00
0.61
2.39
0.72
3.45
Source: Argonne National Laboratory and Department of Energy (2009). Natural gas production converted to
barrels oil equivalent to facilitate comparison using the conversion of 0.178 barrels of crude oil equals 1000
cubic feet natural gas. Totals may not sum due to independent rounding.
2-18
-------
As can be seen in Table 2-7, the amount of water produced is not necessarily correlated
with the ratio of water produced to the volume of oil or natural gas produced. Texas, Alaska and
Wyoming were the three largest producers in barrels of oil equivalent (boe) terms, but had
relatively low rates of water production compared to more Midwestern states such as Illinois,
Missouri, Indiana, and Kansas. Figure 2-3 shows the distribution of produced water management
practices in 2007.
11%
3%
34%
51%
D Injection for
Enhanced Recovery
0 Injection or
Disposal
n Surface Discharge
I Unknown
Source: Argonne National Laboratory
Figure 2-3 U.S. Produced Water Volume by Management Practice, 2007
More than half of the water produced (51 percent) was re-injected to enhance resource recovery
through maintaining reservoir pressure or hydraulically pushing oil from the reservoir. Another
third (34 percent) was injected, typically into wells whose primary purpose is to sequester
produced water. A small percentage (three percent) is discharged into surface water when it
meets water quality criteria. The destination of the remaining produced water (11 percent, the
difference between the total managed and total generated) is uncertain (ANL, 2009).
The movement of crude oil and natural gas primarily takes place via pipelines. Total
crude oil pipeline mileage has decreased during the 1990-2011 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.
2-19
-------
Table 2-8 U.S. Oil and Natural Gas Pipeline Mileage, 2010-2013
Natural Gas Pipelines (miles)
2010
2011
2012
2013
Distribution
mains
1,229,501
1,238,683
1,247,115
1,254,686
Distribution
Service
872,377
881,886
892,209
894,605
Transmission
pipelines
304,775
305,036
303,333
302,827
Gathering
lines
19,640
19,364
16,524
17,435
Total
2,426,293
2,444,969
2,459,181
2,469,553
Source: U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Office of
Pipeline Safety, Annual Report Mileage Summary Statistics, available at
http://phmsa.dot.gov/pipeline/library/data-stats as of December 29, 2014.
Table 2-8 splits natural gas pipelines into four types: distribution mains, distribution
service, transmission pipelines, and gathering lines. Gathering lines are low-volume pipelines
that gather natural gas from production sites to deliver directly to gas processing plants or
compression stations that connect numerous gathering lines to transport gas primarily to
processing plants. Transmission pipelines move large volumes of gas to or from processing
plants to distribution points. From these distribution points, the gas enters a distribution system
that delivers the gas to final consumers.
2.4.3 Domestic Consumption
Historical crude oil sector-level consumption trends for 1990 through 2012 are shown in
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 during this period, while the share
of total consumption by the transportation sector rose from 64 percent in 1990 to 71 percent in
2012.
Table 2-9 Crude Oil Consumption by Sector, 1990-2012
Percent of Total
1990
1991
1992
1993
1994
Total
(million
barrels)
6,178
6,068
6,209
6,277
6,439
Residential and
Commercial
7.3
7.3
7.1
6.9
6.6
Industrial
25.1
24.9
26.1
25.3
26.0
Transportation
Sector
64.3
64.7
64.3
65.0
64.8
Electric
Power
3.3
3.2
2.6
2.9
2.6
2-20
-------
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Source: U.S
snty, _,
g
3
o 50%
a-io^
S3 3Q^-
1 &
••
(\frf
6,402
6,627
6,726
6,837
7,053
6,984
6,963
6,990
7,091
7,399
7,530
7,506
7,517
7,095
6,849
6,994
7,013
6,902
6.4
6.7
6.3
5.7
6.1
4.6
4.6
4.2
4.6
4.4
5.8
5.0
5.1
5.5
5.5
5.2
5.0
5.0
25.7 66.0 1.9
26.1 65.2 2.0
26.4 65.1 2.2
25.4 65.8 3.1
25.6 65.5 2.8
25.1 67.6 2.6
25.1 67.4 2.9
25.2 68.3 2.2
24.8 67.9 2.7
25.3 67.7 2.6
24.2 67.3 2.6
24.8 68.9 1.4
24.1 69.5 1.4
23.0 70.4 1.1
22.2 71.4 1.0
22.8 71.0 0.9
23.2 71.1 0.7
23.4 71.1 0.5
Energy Information Administration.
•uRDDDaFlu D-fa
-»•••««•••!
**********
Residential and Commercial
X Transportation Sector
*-*-*
] D D
>-•-•
A^
^-^ ^^^^^^^^
i i >l__i_i^_^_i ^ '
" ^^^^^^t
D H 1 1 p ,^n y D n n
"••••»tt — 9~r9
CV5 Cv* C\^ CsP cO C\° C^ NV \^ vV
Cv^ CS" W^ CS" CS1^ W^ CT" C\* C\* Cs''
v TT "Vs 'V^ T?^ V TT "(r 'V3 T?
D Industrial
• Electric Power
Figure 2-4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990-
2011
2-21
-------
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 percent per year (Table 2-10 and
Figure 2-5). Over the same period, industrial consumption of natural gas declined, whereas
electric power generation increased its consumption quite dramatically, an important trend in the
industry as many utilities increasingly use natural gas for peak generation or switch from coal-
based to natural gas-based electricity generation. The residential, commercial, and transportation
sectors maintained their consumption levels at more or less constant levels during this time
period.
2-22
-------
50%
45%
0%
oP ^N ^ cf c,<» d> oj= ^ & c? ^ #S ^V ^ ^« ^ ^> ^ ^ ^ ^ x\ y y ry <$* V ^ ^
•Residential
•Electric Power
-Commercial
•Transportation
•Industrial
Figure 2-5 Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-
2012
2.4.4 International Trade
Until 2006, net trade of crude oil and refined petroleum products increased, showing
increased substitution of imports for domestic production, as well as imports satisfying growing
consumer demand in the U.S. (Table 2-11). Since then, however, imports have been declining
while exports have been rising, leading to significant declines in net trade or crude oil and
petroleum products.
2-24
-------
Table 2-11 Total Crude Oil and
1990-2013
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Crude
Oil
2,151
2,111
2,226
2,477
2,578
2,639
2,748
3,002
3,178
3,187
3,320
3,405
3,336
3,528
3,692
3,696
3,693
3,661
3,581
3,290
3,363
3,261
3,121
2,821
Imports
Petroleum
Products
775
673
661
669
706
586
721
707
731
774
874
928
872
949
1119
1310
1310
1255
1146
977
942
913
758
111
Total
2,926
2,784
2,887
3,146
3,284
3,225
3,469
3,709
3,908
3,961
4,194
4,333
4,209
4,477
4,811
5,006
5,003
4,916
4,727
4,267
4,305
4,174
3,879
3,598
Petroleum Products Trade (Million Bbl),
Crude
Oil
40
42
32
36
36
35
40
39
40
43
18
7
3
5
10
12
9
10
10
16
15
17
25
49
Exports
Petroleum
Products
273
323
315
330
308
312
319
327
305
300
362
347
356
370
374
414
472
513
649
723
843
1073
1148
1273
Total
313
365
348
366
344
346
359
366
345
343
381
354
359
375
384
425
481
523
659
739
859
1,090
1,173
1,322
Crude
Oil
2,112
2,068
2,194
2,441
2,542
2,604
2,708
2,963
3,137
3,144
3,301
3,398
3,333
3,523
3,682
3,684
3,684
3,651
3,570
3,274
3,348
3,244
3,096
2,773
Net Imports
Petroleum
Products
502
350
345
339
398
274
403
380
426
474
512
581
517
579
745
896
838
742
497
255
98
-160
-390
-496
Total
2,614
2,418
2,539
2,780
2,940
2,878
3,110
3,343
3,564
3,618
3,813
3,979
3,849
4,102
4,427
4,580
4,523
4,393
4,068
3,528
3,446
3,084
2,706
2,277
Source: U.S. Energy Information
Administration.
Natural gas imports also increased steadily from 1990 to 2007 in volume and percentage
terms (Table 2-12). The years 2007 through 2012 saw imported natural gas constituting a lower
percentage of domestic natural gas consumption. 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 accessible domestic unconventional gas resources, such as shale gas
and coalbed methane, might reduce the need for the U.S. to import natural gas, either via pipeline
or shipped LNG.
2-25
-------
Table 2-12 Natural Gas Imports and Exports, 1990-2013
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Total Imports
(bcf)
1,532
1,773
2,138
2,350
2,624
2,841
2,937
2,994
3,152
3,586
3,782
3,977
4,015
3,944
4,259
4,341
4,186
4,608
3,984
3,751
3,741
3,468
3,138
2,883
Total Exports
(bcf)
86
129
216
140
162
154
153
157
159
163
244
373
516
680
854
729
724
822
963
,072
,137
,506
,619
,572
Net Imports
(bcf)
1,447
1,644
1,921
2,210
2,462
2,687
2,784
2,837
2,993
3,422
3,538
3,604
3,499
3,264
3,404
3,612
3,462
3,785
3,021
2,679
2,604
1,962
1,519
1,311
Percent of U.S.
Consumption
7.3
8.4
9.5
10.6
11.6
12.1
12.3
12.4
13.4
15.3
15.2
16.2
15.2
14.8
15.5
16.7
16.2
16.6
13.2
11.7
10.8
8.0
5.9
N/A
Source: U.S. Energy Information Administration.
2.4.5 Forecasts
In this section, we provide forecasts of well drilling activity and crude oil and natural gas
domestic production, imports, and prices. The forecasts are from the 2014 Annual Energy
Outlook produced by EIA, the most current forecast information available from EIA. As will be
discussed in detail in Section 7, to analyze the impacts of the proposed NSPS on the national
energy economy, we use the National Energy Modeling System (NEMS) that was used to
produce the 2014 Annual Energy Outlook.
Table 2-13 present forecasts of successful wells drilled in the U.S. from 2010 to 2040.
Crude oil well forecasts for the lower 48 states show a rise up to the year 2025 then a gradual
decline until 2040.
2-26
-------
Table 2-13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2040
Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
Crude Oil
19,316
23,048
26,749
25,248
22,274
22,706
22,552
22,355
22,421
22,525
24,765
25,017
25,400
25,981
26,917
27,763
26,258
25,830
25,270
24,801
24,310
23,972
23,607
23,283
23,057
22,740
22,494
22,343
22,075
21,911
21,750
Totals
Natural Gas
19,056
14,355
11,011
11,507
14,099
14,076
15,004
15,773
18,340
20,188
20,396
23,427
24,945
24,999
24,745
24,831
25,445
26,895
28,341
29,019
28,799
29,681
31,406
31,749
32,882
33,278
33,456
33,536
33,944
34,001
33,656
Source: U.S. Energy Information Administration, Annual Energy Outlook 2014.
Meanwhile, show increases for natural gas drilling in the lower 48 states from the present to
2040, more than doubling during this 25-year period.
Table 2-14 presents forecasts of domestic crude oil production, reserves, imports and 6
depicts these trends graphically.
2-27
-------
percent, showing reserves are forecast to grow more rapidly than production. Table 2-14 also
shows average wellhead prices increasing more than 100 percent from 2010 to 2040, from
$76.78 per barrel to $160.38 per barrel in 2011 dollar terms.
- Total Domestic
— Lower 48 Onshore
— Alaska
•Net Imports
•Lower 48 Offshore
Figure 2-6 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 are expected to be eliminated during the forecast
period, from 1.68 tcf in 2011 to -2.43 in 2040 tcf. Imports of LNG are also eliminated during the
forecast period, from 0.28 tcf in 2011 to -3.37 tcf in 2040. Total supply, then, increases about 33
percent, from 22.55 tcf in 2011 to 37.54 tcf in 2040.
2-29
-------
Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price
Domestic Production
(tcf)
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
Dry Gas
Productio
n
22.55
24.06
24.19
24.28
24.63
25.68
26.38
27.20
28.19
29.09
29.70
30.19
30.92
31.44
31.86
32.47
33.07
33.65
34.09
34.43
34.66
35.04
35.39
35.73
36.09
36.36
36.68
37.04
37.36
37.54
Supplemen
tal Natural
Gas
0.06
0.06
0.06
0.07
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
0.06
Net Imports (tcf)
Net
Imports
(Pipeline)
.68
.37
.22
.21
.05
0.92
0.64
0.45
0.22
0.00
-0.13
-0.32
-0.51
-0.62
-0.84
-0.97
- .14
- .28
- .42
- .57
- .67
- .87
- .97
-2.04
-2.16
-2.25
-2.31
-2.39
-2.48
-2.43
Net
Imports
(LNG)
0.28
0.15
0.12
0.14
0.04
-0.16
-0.61
-1.11
-1.62
-1.93
-2.17
-2.17
-2.37
-2.57
-2.57
-2.77
-2.97
-3.17
-3.35
-3.37
-3.37
-3.37
-3.37
-3.37
-3.37
-3.37
-3.37
-3.37
-3.37
-3.37
Total
Supply
24.57
25.64
25.59
25.69
25.78
26.50
26.47
26.61
26.85
27.23
27.47
27.77
28.11
28.31
28.52
28.79
29.02
29.27
29.39
29.56
29.69
29.86
30.12
30.38
30.63
30.80
31.06
31.34
31.57
31.81
Lower 48 End
of Year Dry
Reserves
(tcf)
324.6
320.1
329.1
332.5
337.0
341.8
344.5
346.1
348.6
352.5
354.6
358.0
362.2
365.1
368.5
372.4
375.4
378.4
380.6
382.6
385.2
387.5
389.6
391.9
393.6
394.7
397.5
399.6
401.6
402.6
Average Henry Hub
Spot Price (20 12
dollars per million
Btu)
4.07
2.75
3.60
3.74
3.74
4.14
4.40
4.80
4.66
4.38
4.67
4.82
4.96
5.12
5.23
5.36
5.49
5.59
5.78
6.03
6.17
6.36
6.59
6.74
6.92
7.18
7.23
7.26
7.42
7.65
Source: U.S. Energy Information Administration, Annual Energy Outlook, 2014
2.5 Industry Costs
2.5.1 Finding Costs
Real costs of drilling oil and natural gas wells have increased significantly over the past
two decades, particularly in recent years. Cost per well has increased by an annual average of
2-30
-------
about 15 percent, and cost per foot has increased on average of about 13 percent per year (Figure
2-7).
5,000,000
4,500,000 --
4,000,000 --
3,500,000 --
3,000,000 --
2,500,000 --
2,000,000 --
1,500,000 --
1,000,000 -|
500,000 --
0 --
800
700
600
500
400
300
200
100
0
1981 1984 1987 1990 1993 1996 1999 2002 2005 2008
- Dollars per Wei (2005 dollars)
- Dollars per Foot (2005 dollars)
Figure 2-7 Costs of Crude Oil and Natural Gas Wells Drilled, 1981-2008
The average finding costs compiled and published by EIA add an additional level of detail to
drilling costs, in that finding costs incorporate the costs more broadly associated with adding
proved reserves of crude oil and natural gas. These costs include exploration and development
costs, as well as costs associated with the purchase or leasing of real property. EIA publishes
finding costs as running three-year averages, in order to better compare these costs, which occur
over several years, with annual average lifting costs. Figure 2-8 shows average domestic onshore
and offshore and foreign finding costs for the sample of U.S. firms in EIA's Financial Reporting
System (FRS) database from 1981 to 2009. The costs are reported in 2009 dollars on a barrel of
oil equivalent basis for crude oil and natural gas combined. The average domestic finding costs
dropped from 1981 until the mid-1990s. Interestingly, in the mid-1990s, domestic onshore and
offshore and foreign finding costs converged for a few years. After this period, offshore finding
costs rose faster than domestic onshore and foreign costs.
2-31
-------
-•-U.S. Onshore
A U.S. Offshore Foreign
Figure 2-8 Finding Costs for FRS Companies, 1981-2009
After 2000, average finding costs rose sharply, with the finding costs for domestic onshore and
offshore and foreign proved reserves diverging onto different trajectories. Note the drilling costs
in Figure 2-7 and finding costs in Figure 2-8 present similar trends overall.
2.5.2 Lifting Costs
Lifting costs are the costs to produce crude oil or natural gas once the resource has been
found and accessed. EIA's definition of lifting costs includes costs of operating and maintaining
wells and associated production equipment. Direct lifting costs exclude production taxes or
royalties, while total 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 production taxes. Figure 2-9 depicts direct lifting cost
trends from 1981 to 2009 for domestic and foreign production.
2-32
-------
-Domestic
-Foreign
Figure 2-9 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2009 (3-
year Running Average)
Direct lifting costs (excludes taxes and royalties) for domestic production rose a little more than
$2 per barrels of oil equivalent from 1981 to 1985, then declined almost $5 per barrel of oil
equivalent from 1985 until 2000. From 2000 to 2009, domestic lifting costs increased sharply,
just over $8 per barrel of oil equivalent. Foreign lifting costs diverged from domestic lifting costs
from 1981 to 1991, as foreign lifting costs were lower than domestic costs during this period.
Foreign and domestic lifting costs followed a similar track until they again diverged in 2004,
with domestic lifting again becoming more expensive. Combined with finding costs, the total
finding and lifting costs rose significantly in from 2000 to 2009.
2.5.3 Operating and Equipment Costs
The EIA report, "Oil and Gas Lease Equipment and Operating Costs 1994 through
2009"11, contains indices and estimated costs for domestic oil and natural gas equipment and
production operations. The indices and cost trends track costs for representative operations in six
regions (California, Mid-Continent, South Louisiana, South Texas, West Texas, and Rocky
11 U.S. Energy Information Administration. "Oil and Gas Lease Equipment and Operating Costs 1994 through
2009." September 28, 2010.
Accessed February 2, 2011.
2-33
-------
Mountains) with producing depths ranging from 2000 to 16,000 feet and low to high production
rates (for example, 50,000 to 1 million cubic feet per day for natural gas).
Figure 2-10 depicts crude oil operating costs and equipment costs indices for 1976 to
2009, as well as the crude oil price in 1976 dollars. The indices show that crude oil operating and
equipment costs track the price of oil over this time period, while operating costs have risen
more quickly than equipment costs. Operating and equipment costs and oil prices rose steeply in
the late 1970s, but generally decreased from about 1980 until the late 1990s.
200
1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009
- Grade Oil Operating Costs
- Grade Oil Equipment Cost Index
-Grade Oil Price ($/bbl 1976 Dollars)
Figure 2-10 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and
Crude Oil Price (in 1976 dollars), 1976-200912
Oil costs and prices again generally rose between 2000 to present, with a peak in 2008. The 2009
index values for crude oil operating and equipment costs are 154 and 107, respectively.
12 The last release date for EIA's Oil and Gas Lease Equipment and Operating Costs analysis was September 2010.
Updates have been discontinued.
2-34
-------
1976 1979
12 1985 1988 1991 1994 1997 2000 2003 2006 2009
- Natural Gas Operating Costs
- Natural Gas Equipment Costs
-NaturalGas Price ($/Mc£ 1976 Dollars)
Figure 2-11 Natural Operating Costs and Equipment Costs Indices (1976=100) and
Natural Gas Price, 1976-2009
Figure 2-11 depicts natural gas operating 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, while operating costs have risen more quickly than
equipment costs. Operating and equipment costs and gas prices also rose steeply in the late
1970s, but generally decreased from about 1980 until the mid-1990s. The 2009 index values for
natural gas operating and equipment costs are 137 and 112, respectively.
2.6 Firm Characteristics
A regulatory action to reduce pollutant discharges from facilities producing crude oil and
natural gas will potentially affect the business entities that own the regulated facilities. In the oil
and natural gas production industry, facilities comprise those sites 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 business decisions that affect the facility.
2-35
-------
2.6.1 Ownership
Enterprises in the oil and natural gas industry may be divided into different groups that
include producers, transporters, and distributors. The producer segment may be further divided
between major and independent producers. Major producers include large oil and gas companies
that are involved in each of the five industry segments: drilling and exploration, production,
transportation, refining, and marketing. Independent producers include smaller firms that are
involved in some but not all of the five activities.
According to the Independent Petroleum Association of America (IPAA), independent
companies produce approximately 68 percent of domestic crude oil production of our oil, 85
percent of domestic natural gas, and drill almost 90 percent of the wells in the U.S (IPAA, 2009).
Through the mid-1980s, natural gas was a secondary fuel for many producers. However, now it
is of primary importance to many producers. IPAA reports that about 50 percent of its members'
spending in 2007 was directed toward natural gas production, largely toward production of
unconventional gas (IPAA, 2009). Meanwhile, transporters are comprised of the pipeline
companies, while distributors are comprised of the local distribution companies.
2.6.2 Size Distribution of Firms in Affected NAICS
As of 2014, there were 6,659 firms within the 211111 and 211112 NAICS codes, of
which 6,535 (98 percent) were considered small 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.
2-36
-------
Table 2-16 SB A Size Standards and Size Distribution of Oil and Natural Gas Firms
NAICS
NAICS Description
SBA Size
Standard
(Employees or
Annual Receipts)
Small
Firms
Large
Firms
Total
Firms
Number of Firms by Firm Size
211111
211112
213111
213112
486210
Crude Petroleum and Natural Gas Extraction
Natural Gas Liquid Extraction
Drilling Oil and Gas Wells
Support Activities for Oil and Gas Operations
Pipeline Transportation of Natural Gas
500
500
500
$38.5 million
$27.5 million
6,436
99
1,993
N/A
N/A
87
37
48
N/A
N/A
6,523
136
2,041
8,119
107
Total Employment by Firm Size
211111
211112
213111
213112
486210
Crude Petroleum and Natural Gas Extraction
Natural Gas Liquid Extraction
Drilling Oil and Gas Wells
Support Activities for Oil and Gas Operations
Pipeline Transportation of Natural Gas
500
500
500
$38.5 million
$27.5 million
45,641
1,733
36,663
N/A
N/A
63,313
8,272
57,843
N/A
N/A
108,954
10,005
94,506
219,827
27,151
Source: U.S. Small Business Administration Office of Advocacy. 2014.
Firm Size Data. Accessed January 5, 2015.
Note: "N/A" indicates where national counts of small and large firms could not be performed.
The small and large firms within NAICS 21311 are similarly distributed, with large firms
accounting for about 2 percent of firms, but 61 percent of employment. Because there are
relatively few firms within NAICS 486210, the Census Bureau cannot release breakdowns of
firms by size in sufficient detail to perform similar calculation.
2.6.3 Trends in National Employment and Wages
As well as producing much of the U.S. energy supply, the oil and natural gas industry
directly employs a significant number of people. 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, hitting a low of 314,000 in 1999, but rebounding to a
2013 peak of 620,000. Crude Petroleum and Natural Gas Extraction (NAICS 211111) and
Support Activities for Oil and Gas Operations (NAICS 213112) employ the majority of workers
in the industry.
2-37
-------
Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-2013
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Crude
Petroleum
and Natural
Gas
Extraction
(NAICS
211111)
182,848
177,803
169,615
159,219
150,598
142,971
139,016
137,667
133,137
124,296
117,175
119,099
116,559
115,636
117,060
121,535
130,188
141,239
154,898
155,150
153,490
164,900
181,473
189,804
Natural
Gas
Liquid
Extraction
(NAICS
211112)
8,260
8,443
8,819
7,799
7,373
6,845
6,654
6,644
6,379
5,474
5,091
4,500
4,565
4,691
4,285
4,283
4,670
4,842
5,183
5,538
4,833
5,835
6,529
6,928
Drilling of
Oil and
Natural Gas
Wells
(NAICS
213111)
52,365
46,466
39,900
42,485
44,014
43,114
46,150
55,248
53,943
41,868
52,207
62,012
48,596
51,526
57,332
66,691
79,818
84,525
92,640
67,756
74,491
87,272
92,340
93,261
Support
Activities
for Oil and
Gas Ops.
(NAICS
213112)
109,497
116,170
99,924
102,840
105,304
104,178
107,889
117,460
122,942
101,694
108,087
123,420
120,536
120,992
128,185
145,725
171,127
197,100
223,635
193,589
201,685
241,490
282,447
296,891
Pipeline
Trans, of
Crude Oil
(NAICS
486110)
11,112
11,822
11,656
11,264
10,342
9,703
9,231
9,097
8,494
7,761
7,657
7,818
7,447
7,278
7,073
6,945
7,202
7,975
8,369
8,753
8,893
8,959
9,348
10,059
Pipeline
Trans, of
Natural Gas
(NAICS
486210)
47,533
48,643
46,226
43,351
41,931
40,486
37,519
35,698
33,861
32,610
32,374
33,620
31,556
29,684
27,340
27,341
27,685
27,431
27,080
26,753
26,708
27,320
27,595
26,981
Total
411,615
409,347
376,140
366,958
359,562
347,297
346,459
361,814
358,756
313,703
322,591
350,469
329,259
329,807
341,275
372,520
420,690
463,112
511,805
457,539
470,100
535,776
599,732
623,924
Source: U.S. Bureau of Labor Statistics,
Quarterly Census of Employment and Wages, 2013 ,
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
associated with the oil and natural gas industry.
2-38
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Table 2-18
dollars)
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Oil and Natural Gas Industry Average Wages by NAICS, 1990-2013 (2012
Crude
Petroleum
and Natural
Gas
Extraction
(211111)
74,475
75,980
80,222
81,214
82,976
85,341
88,319
94,309
97,870
103,235
115,018
116,417
115,314
116,161
127,324
133,920
145,658
143,266
153,155
141,752
152,074
156,035
155,735
153,095
Natural
Gas
Liquid
Extraction
(211112)
69,877
69,993
72,285
72,237
74,277
70,873
72,256
83,369
94,427
93,852
117,477
116,513
108,703
118,322
124,374
134,419
140,685
140,329
132,582
131,508
131,980
120,939
136,352
122,787
Drilling of
Oil and
Natural
Gas Wells
(213111)
44,193
45,593
45,683
47,486
46,717
48,462
51,256
54,754
55,692
57,216
63,787
64,792
65,226
64,095
66,251
74,486
78,047
86,705
86,845
85,854
86,297
91,885
92,266
92,737
Support
Activities
for Oil and
Gas Ops.
(213112)
48,010
49,578
51,355
52,649
52,565
53,294
55,400
58,343
60,445
62,756
63,505
64,298
62,847
64,368
65,672
70,753
74,085
76,099
78,432
74,579
77,774
81,441
80,222
80,516
Pipeline
Trans, of
Crude Oil
(486110)
71,231
72,277
77,941
76,445
79,790
82,717
80,589
82,305
83,028
86,626
84,994
87,363
91,763
91,788
98,381
96,906
96,693
101,516
107,836
106,188
108,855
114,710
120,292
116,215
Pipeline
Trans, of
Natural
Gas
(486210)
64,452
68,228
70,472
70,777
71,804
75,418
80,103
86,858
88,367
99,119
136,907
128,243
96,010
96,109
98,485
95,017
104,055
111,476
105,127
106,598
112,857
116,266
139,127
116,621
Total
62,245
63,886
67,435
67,734
68,058
69,634
71,727
75,355
77,393
82,969
90,990
89,416
86,240
86,714
90,960
95,030
100,084
101,724
105,011
102,193
106,522
108,863
108,872
107,028
Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2013, annual wages per
employee
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 transportation 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 outside are produced in house, while the horizontal
2-39
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aspect of a firm's size refers to the scale of production in a single-product firm or its scope in a
multiproduct one. Vertical integration is a potentially important dimension in analyzing firm-
level impacts because the regulation could affect a vertically integrated firm on more than one
level. The regulation may affect companies for whom oil and natural gas production is only one
of several processes in which the firm is involved. For example, a company that owns oil and
natural gas production facilities may ultimately produce final petroleum products, such as motor
gasoline, jet fuel, or kerosene. This firm would be considered vertically integrated because it is
involved in more than one level of requiring crude oil and natural gas and finished petroleum
products. A regulation that increases the cost of oil and natural gas production will ultimately
affect the cost of producing final petroleum products.
Horizontal integration is also a potentially important dimension in firm-level analyses for
any of the following reasons. A horizontally integrated firm may own many facilities of which
only some are directly affected by the regulation. Additionally, a horizontally integrated firm
may own facilities in unaffected industries. This type of diversification would help mitigate the
financial impacts of the regulation. A horizontally integrated firm could also be indirectly as well
as directly affected by the regulation.
In addition to the vertical and horizontal integration that exists among the large firms in
the industry, many major producers often diversify within the energy industry and produce a
wide array of products unrelated to oil and gas production. As a result, some of the effects of
regulation of oil and gas production can be mitigated if demand for other energy sources moves
inversely compared to petroleum product demand.
In the natural gas sector of the industry, vertical integration is less predominant than in
the oil sector. Transmission and local distribution of natural gas usually occur at individual firms,
although processing is increasing performed by the integrated major companies. Several natural
gas firms operate multiple facilities. However, natural gas wells are not exclusive to natural gas
firms only. Typically wells produce both oil and gas and can be owned by a natural gas firm or
an oil company.
Unlike the large integrated firms that have several profit centers such as refining,
marketing, and transportation, most independents have to rely only on profits generated at the
2-40
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wellhead from the sale of oil and natural gas or the provision of oil and gas production-related
engineering or financial services. Overall, independent producers typically sell their output to
refineries or natural gas pipeline companies and are not vertically integrated. Independents may
also own relatively few facilities, indicating limited horizontal integration.
2.6.5 Firm-level Information
The annual Oil and Gas Journal (OGJ) survey, the OGJ150, reports financial and
operating results for public oil and natural gas 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.13 The
2012 list contains four companies that were not on the list in the previous year. Also, 10 other
companies listed in 201 Ido not appear on the 2012 list as a result of mergers, bankruptcies, or
other reasons. Table 2-19 lists selected statistics for the top 20 companies in 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 capital and operating costs in 2012.
Net income for the top 134 companies fell between 2011 and 2012 from $114.5 billion to
$91.1 billion. Revenues for these companies fell 1.4 percent from 2011 to 2012. Even though
earnings decreased in 2012, strong earnings from 2011 boosted available financial resources and
the companies continued to invest. Capital and exploratory spending for the companies in 2012
totaled $206.5 billion, up 17.1 from 2011.
The total worldwide liquids production for the 134 firms increased 6.85 percent to 2.879
billion bbl, while total worldwide 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 from 2011 to 2012. Domestic production of liquids
increased about 19.8 percent from 2011 to 1.437 billion bbl, and natural gas production was up
about 6.3 percent. For context, the OGJ150 domestic crude production represents about 49
percent of total domestic production (2.06 billion bbl, according to EIA). The OGJ150 natural
gas production represents about 69 percent of total domestic production (28.5 tcf, according to
; Oil and Gas Journal. "OGJ150 Earnings Down as US Production Climbs." September 2, 2013.
2-41
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EIA).
The OGJ also releases a period report entitled "Worldwide Gas Processing Survey",
which provides a wide range of information on existing processing facilities. We used a recent
list of U.S. gas processing facilities (Oil and Gas Journal, June 7, 2010) and other resources,
such as the American Business Directory and company websites, to best identify the parent
company of the facilities. As of 2009, there are 579 gas processing facilities in the U.S., with a
processing capacity of 73,767 million cubic feet per day and throughout of 45,472 million cubic
feet per day (Table 2-20). The overall trend in U.S. gas processing capacity is showing fewer, but
larger facilities. For example, in 1995, there were 727 facilities with a capacity of 60,533 million
cubic feet per day (U.S. DOE, 2006).
Trends in gas processing facility ownership are also showing a degree of concentration,
as large firms own multiple facilities, which also tend to be relatively large facilities (Table
2-20). While we estimate 142 companies own the 579 facilities, the top 20 companies (in terms
of total throughput) own 264 or 46 percent of the facilities. That larger companies tend to own
larger facilities is indicated by these top 20 firms owning 86 percent of the total capacity and 88
percent of actual throughput.
2-42
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Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012
Worldwide
Production
Rank by
Total
Assets
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Company
ExxonMobil Corp.
Chevron Corp.
ConocoPhillips
Occidental Petroleum Corp.
Apache Corp.
Anadarko Petroleum Corp.
Hess Corp.
Devon Energy Corp.
Chesapeake Energy Corp.
Marathon Oil Corp.
EOG Resources Inc.
Noble Energy Inc.
Murphy Oil Corp.
Plains Exploration and
Production Co
Pioneer Natural Resources Co.
Linn Energy LLC
Denbury Resources Inc.
Sandridge Energy Inc.
WPX Energy Inc.
Continental Resources Inc.
Employees
76,900
17,418
16,900
12,300
5,976
5,200
14,775
5,700
12,000
3,367
2,650
2,190
9,185
906
3,667
1,136
1,432
2,510
1,200
753
Total
Assets
($Million)
333,795
232,982
117,144
64,210
60,737
52,589
43,441
43,326
41,611
35,306
27,337
17,554
17,523
17,298
13,069
11,451
11,139
9,791
9,456
9,140
Total
Revenue
($Million)
482,295
241,909
62,004
24,253
17,078
13,411
38,373
9,502
12,316
16,221
11,683
4,223
28,626
2,565
3,228
1,774
2,456
2,731
3,189
2,573
Net Liquids
Income (Million
($Million) bbl)
47,681
26,336
8,498
4,598
2,001
2,445
2,063
-206
-594
1582
570
1027
971
343
243
-387
525
247
-211
416
625
536
271
201
145
115
110
103
93
78
49
42
41
34
26
25
24
24
22
20
US
Production
Natural Liquids
Gas (Million
(Bcf) bbl)
2,992
1,737
1,539
1129
938
916
839
565
557
470
416
380
322
284
259
253
249
249
244
183
166
151
120
100
84
75
61
57
49
45
39
34
26
25
24
24
24
20
18
18
Natural
Gas
(Bcf)
1,518
1,129
916
752
685
565
440
407
380
380
313
300
259
253
249
249
183
161
160
156
Net
Wells
Drilled
1,411
1,272
1,163
1,016
958
951
826
769
751
699
513
492
468
439
367
334
315
297
271
263
Source: Oil and Gas Journal. "OGJ150 Earnings Down as US Production Climbs." September 2, 2013.
OGJ150, reports financial and operating results for public oil and natural gas companies with domestic
Notes: The source for employment figures is Hoovers, a D&B Company.
The annual Oil and Gas Journal (OGJ) survey, the
reserves and headquarters in the U.S.
2-43
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Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Company
BPPLC
DCP Midstream Inc.
Enterprise Products Operating LP —
Targa Resources
Enbridge Energy Partners LP —
Williams Cos.
Martin Midstream Partners
Chevron Corp.
Devon Gas Services LP
ExxonMobil Corp.
Occidental Petroleum Corp
Kinder Morgan Energy Partners
Enogex Products Corp.
Hess Corp.
Norcen Explorer
Copano Energy
Anadarko
Oneok Field Services
Shell
DTE Energy
TOTAL FOR TOP 20
TOTAL FOR ALL COMPANIES
Processing
Plants (No.)
19
64
23
16
19
10
16
23
6
6
7
9
8
3
1
1
18
10
4
1
264
579
Natural Gas
Capacity
(MMcf/day)
13,378
9,292
10,883
4,501
3,646
4,826
3,384
1,492
1,038
1,238
776
1,318
863
1,060
600
700
816
1,751
801
800
63,163
73,767
Natural Gas
Throughput
(MMcf/day)
11,420
5,586
5,347
2,565
2,444
2,347
2,092
1,041
846
766
750
743
666
613
500
495
489
472
446
400
40,028
45,472
Source: Oil and Gas Journal. "Special Report: Worldwide Gas Processing:
Processing Capacity Ahead in 2009." June 7, 2010, with additional analysis
plants.
New Plants, Data Push Global Gas
to determine ultimate ownership of
The OGJ also issues a periodic report on the economics of the U.S. pipeline industry.
This report examines the economic status of all major and non-major natural gas pipeline
companies, which amounts to 162 companies in 2011 (Oil and Gas Journal, September 2, 2013).
Table 2-21 presents the pipeline mileage, volumes of natural gas transported, operating revenue,
and net income for the top 20 U.S. natural gas pipeline companies in 2012. Ownership of gas
pipelines is mostly independent from ownership of oil and gas production companies, as is seen
from the lack of overlap between the OGJ list of pipeline companies and the OGJ150. This
observation shows that the pipeline industry is still largely based upon firms serving regional
market.
The top 20 companies maintain about 61 percent of the total pipeline mileage and
transport about 56 percent of the volume of the industry (Table 2-21). Operating revenues of the
2-44
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top 20 companies equaled $12.1 billion, representing 59 percent of the total operating revenues
for major and non-major companies. The top 20 companies also account for 59 percent of the net
income of the industry.
Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2012
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Source:
2013.
Company
Dominion Transmission Inc.
Texas Eastern Transmission LP
Florida Gas Transmission Co. LLC
Transcontinental Gas Pipe Line Co. LLC
Tennessee Gas Pipeline Co.
Columbia Gas Transmission LLC
Natural Gas Pipeline Co of America
Southern Natural Gas Co.
ETC Tiger Pipeline LLC
Northern Natural Gas Co.
Panhandle Eastern Pipe Line Co., LP
Texas Gas Transmission LLC
Kern River Gas Transmission Co.
Rockies Express Pipeline LLC
CenterPoint Energy Gas Transmission Co.,
LLC
Colorado Interstate Gas Co.
Dominion Cove Point LNG, LP
Gulf South Pipeline Co., LP
Northern Border Pipeline Co.
Northwest Pipeline GP
TOTAL FOR TOP 20
TOTAL FOR ALL COMPANIES
Oil and Gas Journal. "US Pipeline Operators
Transmission
(miles)
3,687
9,563
5,336
9,378
13,780
9,708
8,911
7,079
196
14,949
6,406
5,880
1,718
1,698
5,954
4,253
136
6,484
1,408
3,906
120,430
198,279
Vol. trans
for others
(MMcf)
653,272
1,747,856
979,857
3,274,209
2,626,030
1,305,728
1,511,844
1,005,151
546,137
928,977
581,926
1,052,070
928,206
822,587
1,143,552
788,905
82989
1,115,618
1,008,857
658,161
22,761,932
40,759,824
Operating
Revenue
($OOOs)
903,404
956,536
775,375
1,254,154
1,015,928
813,185
687,366
584,828
279,572
587,768
338,787
417,809
383,393
786,225
437,836
397,292
281,517
470,149
310,869
437,835
12,119,828
20,545,763
Net
Income
($OOOs)
256,010
242,277
204,968
194,573
190,970
186,594
176,447
162,275
134,934
134,715
123,392
106,994
105,447
103,427
103,290
100,902
97,192
93,816
89,767
87,119
2,895,109
4,888,125
Sink Revenue Growth into Expansion." September 2,
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 publication "The Performance Profiles of Major Energy
Producers".14 This information is used in annual report to Congress, as well as is released to the
14 The "Performance Profiles of Major Energy Producers 2009" released on February 25, 2011 is the most recent
release of this report.
2-45
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public in aggregate form. While the companies that report information to FRS each year changes,
EIA makes an effort to retain sufficient consistency such that trends can be evaluated. For 2009,
there are 30 companies in the FRS15 that accounted for 43 percent of total U.S. crude oil and
NGL production, 43 percent of natural 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 aggregated from FRS firms' financial statements.
The table shows operating revenues and expenses rising significantly from 1990 to 2008, with
operating income (the difference between operating revenues and expenses) rising until dropping
off significantly in 2009. Interest expenses remained relatively flat during this period.
Meanwhile, recent years have shown that other income and income taxes have played a more
significant 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 declined significantly during the
latter half of 2008.
15 Alenco, Alon USA, Anadarko Petroleum Corporation, Apache Corporation, BP America, Inc., Chalmette,
Chesapeake Energy Corporation, Chevron Corporation, CITGO Petroleum Corporation, ConocoPhillips, Devon
Energy Corporation, El Paso Corporation, EOG Resources, Inc., Equitable Resources, Inc., Exxon Mobil
Corporation, Hess Corporation, Hovensa, Lyondell Chemical Corporation, Marathon Oil Corporation, Motiva
Enterprises, L.L.C., Occidental Petroleum Corporation, Shell Oil Company, Sunoco, Inc., Tesoro Petroleum
Corporation, The Williams Companies, Inc., Total Holdings USA, Inc., Valero Energy Corp., Western
Refining, WRB Refining LLC, and XTO Energy, Inc.
2-46
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Table 2-22 Selected Financial Items from Income Statements (Billion 2008 Dollars)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
Operating Operating Operating Interest Other Income
Revenues Expenses Income Expense Income* Taxes
766.9
673.4
670.2
621.4
606.5
640.8
706.8
673.6
614.2
722.9
1,114.3
961.8
823.0
966.9
1,188.5
1,447.3
1,459.0
1,475.0
1,818.1
1,136.8
706.4
635.7
637.2
586.6
565.6
597.5
643.3
613.8
594.1
682.6
1,011.8
880.3
776.9
872.9
,051.1
,263.8
,255.0
,297.7
,654.0
,085.9
60.5
37.7
33.0
34.8
40.9
43.3
63.6
59.9
20.1
40.3
102.5
81.5
46.2
94.0
137.4
183.5
204.0
177.3
164.1
50.8
16.8
14.4
12.7
11.0
10.8
11.1
9.1
8.2
9.2
10.9
12.9
10.8
12.7
10.1
12.4
11.6
12.4
11.1
11.4
10.8
13.6
13.4
-5.6
10.3
6.8
12.9
13.4
13.4
11.0
12.7
18.4
7.6
7.9
19.5
20.1
34.6
41.2
47.5
32.6
18.7
24.8
15.4
12.2
12.7
14.4
17.0
26.1
23.9
6.0
13.6
42.9
33.1
17.2
37.2
54.2
77.1
94.8
86.3
98.5
29.5
Net
Income
32.5
21.3
2.5
21.5
22.5
28.1
41.8
41.2
15.9
28.6
65.1
45.2
24.3
66.2
90.9
129.3
138.0
127.4
86.9
29.3
Source: Energy Information Administration, Form EIA-28 (Financial Reporting System). * Other Income
includes other revenue and expense (excluding interest expense), discontinued operations, extraordinary items,
and accounting changes. Totals may not sum due to independent rounding.
Table 2-23 shows in percentage terms the estimated return on investments for a variety of
business lines, in 1998, 2003, 2008, and 2009 for FRS companies. For U.S. petroleum-related
business activities, oil and natural gas production was the most profitable line of business
relative to refining/marketing and pipelines, sustaining a return on investment greater than 10
percent in 1998, 2003, and 2008, with a significant decrease in 2009. Returns to foreign oil and
natural gas production rose above domestic production in 2008 and 2009. Electric power
generation and sales emerged in 2008 as a highly profitable line of business for the FRS
companies and declined significantly in 2009.
2-47
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Table 2-23 Return on Investment for Lines of Business (all FRS), for 1998, 2003, 2008,
and 2009 (percent)
Line of Business
Petroleum
U.S. Petroleum
Oil and Natural Gas Production
Refining/Marketing
Pipelines
Foreign Petroleum
Oil and Natural Gas Production
Refining/Marketing
Downstream Natural Gas*
Electric Power
Other Energy
Non-energy
1998
10.8
10
12.5
6.6
6.7
11.9
12.5
10.6
-
-
7.1
10.9
2003
13.4
13.7
16.5
9.3
11.5
13.0
14.2
8.0
8.8
5.2
2.8
2.4
2008
12.0
8.2
10.7
2.6
2.4
17.8
16.3
26.3
5.1
181.4
-2.1
-5.3
2009
4.5
0.4
3.5
-6.6
4.7
10.3
11
5.8
9.6
-32
5.1
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 production tax trends from 1990 to 2009
for FRS companies. The column with U.S. federal, state, and local taxes paid or accrued includes
deductions for the U.S. Federal Investment Tax Credit ($198 million in 2008)16 and the effect of
the Alternative Minimum Tax ($34 million in 2008). Income taxes paid to state and local
authorizes were $3,060 million in 200813, about 13 percent of the total paid to U.S. authorities.
' Data was withheld in 2009 to avoid disclosure.
2-48
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Table 2-24 Income and Production Taxes, 1990-2009 (Million 2008 Dollars)
US Federal, State,
and Local Taxes Total Total Income
Year Paid or Accrued Total Current Deferred Tax Expense
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009*
9,568
6,672
4,994
3,901
3,348
6,817
8,376
7,643
1,199
2,626
14,308
10,773
814
9,274
19,661
29,993
29,469
28,332
23,199
-1,655
25,056
18,437
16,345
13,983
13,556
17,474
22,493
20,764
7,375
13,410
36,187
28,745
17,108
30,349
50,185
72,595
85,607
84,119
95,590
35,478
-230
-3,027
-4,116
-1,302
887
-510
3,626
3,141
-1,401
140
6,674
4,351
46
6,879
4,024
4,529
9,226
2,188
2,866
-5,988
24,826
15,410
12,229
12,681
14,443
16,965
26,119
23,904
5,974
13,550
42,861
33,097
17,154
37,228
54,209
77,125
94,834
86,306
98,456
29,490
Other
Production
Taxes Paid
4,341
3,467
3,097
2,910
2,513
2,476
2,922
2,743
1,552
2,147
3,254
3,042
2,617
3,636
3,990
5,331
5,932
7,501
12,507
-173
Source: Energy Information Administration,
*In 2009, data on the U.S. Federal Investment
avoid disclosure.
Form EIA-28 (Financial Reporting System).
Tax Credit and U.S. State and Local Income Taxes were withheld to
The difference between total current taxes and U.S. federal, state, and local taxes in
includes taxes and royalties paid to foreign countries. As can be seen in Table 2-24, foreign taxes
paid far exceeds domestic taxes paid. Other non-income production taxes paid, which have risen
almost three-fold between 1990 and 2008, include windfall profit and severance taxes, as well as
other production-related taxes.
2.7 References
Andrews, et al. 2009. Unconventional Gas Shales: Development, Technology, and Policy Issues.
Congressional Research Service. R40894.
Argonne National Laboratory. 2009. Produced Water Volumes and Management Practices in the
United States. ANL/EVS/R-09/1.
Hyne, NJ. 2001. Nontechnical Guide to Petroleum Geology, Exploration, Drilling and
Production. Tulsa, OK: Pen well Books.
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Independent Petroleum Association of America. 2009. Profile of Independent Producers.
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 Processing: New Plants, Data Push
Global Gas Processing Capacity Ahead in 2009." June 7, 2010.
U.S. Energy Information Administration (U.S. EIA). 2006. Natural Gas Processing: The Crucial
Link between Natural Gas Production and Its Transportation to Market.
Accessed February 2, 2011.
U.S. Department of Energy. 2013. Modern Shale Gas Development in the United States: An
Update. Accessed December 19, 2014.
U.S. Energy Information Administration (U.S. EIA). 2012. Annual Energy Review 2011 (AER).
U.S. Energy Information Administration (U.S. EIA). 2010. Oil and Gas Lease Equipment and
Operating Costs 1994 through 2009
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.
Accessed September 15, 2013.
U.S. Energy Information Administration (U.S. EIA). 2011. Performance Profiles of Major
Energy Producers 2009. Accessed
September 15, 2013.
U.S. Energy Information Administration (U.S. EIA). 2014. Annual Energy Outlook 2014.
Accessed March 17, 2014.
2-50
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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.
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 Gas Extraction Industry. EPA/310-R-99-006.
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.
Accessed December 19, 2014.
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3 EMISSIONS AND ENGINEERING COSTS
3.1 Introduction
This chapter describes the emissions and engineering cost analysis for the proposed
NSPS. The first section discusses the emissions points and control options. The following section
describes each step in the emissions and engineering cost analysis and presents overview results.
Detailed tables describing the impacts for each source and option can be found at the end of the
chapter. We provide reference to the more-detailed Technical Support Document (TSD) prepared
by the EPA for the reader interested in a greater level of detail.17
3.2 Sector Emissions Overview
Before going into detail on emissions points and pollution controls, it is useful to provide
estimates of overall emissions from the crude oil and natural gas industry to provide context for
estimated reductions as a result of the proposed rule. Crude oil and natural gas production sector
VOC emissions are approximately 2.8 million tons, according to the 2011 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 and petroleum transportation) to be 182 MMt COi
Eq. In 2013, total methane emissions from the oil and gas industry represented nearly 29 percent
of the total methane emissions from all sources and account for about 3 percent of all CO2 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-fractured oil well completions due to lack of
available data when the 2013 GHG Inventory estimate was developed. The estimate in this
proposed rule includes an adjustment for hydraulically fractured oil wells, and such an
adjustment is also being considered as a planned improvement in the 2014 Inventory (to be
published April 2016). This adjustment would increase the 2013 Inventory methane estimate by
17 U.S. EPA. 2015. Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas
Production, Transmission and Distribution. Background Technical Support Document for the Proposed
Amendments to the New Source Performance Standards.
3-1
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about 3 MMt CCh Eq. The total methane emissions from Petroleum and Natural Gas Systems
based on the 2013 GHG Inventory, adjusted for hydraulically fractured and re-fractured oil well
completions, is approximately 185 MMt COi Eq.
3.3 Emissions Points and Pollution Controls assessed in the RIA
A series of emissions controls were evaluated as part of the NSPS review. This section
provides a basic description of emissions sources and the controls evaluated for each source to
facilitate the reader's understanding of the economic impact and benefit analyses. The reader
who is interested in more technical detail on the engineering and cost basis of the analysis is
referred to the relevant chapters within the TSD.
Completions of Hydraulically Fractured and Re-fractured Oil Wells: Well completion
activities include multiple steps after the well bore hole has reached the target depth. The highest
emissions are from venting of natural gas to the atmosphere during flowback. Flowback
emissions are short-term in nature and occur as a specific event during completion of a new well
or during activities that involve re-drilling or re-fracturing an existing well. The TSD separately
considers developmental wells and exploratory wells. Developmental wells are wells drilled
within known boundaries of a proven oil or gas field, while exploratory or "wildcat" wells are
wells drilled in areas of new or unknown potential.
The EPA considered the same two techniques that have been proven to reduce emissions
from well completions: reduced emissions completions (RECs) and completion combustion. The
use of a REC not only reduces emissions but delivers natural gas product that would typically be
vented to the sales meter. Completion combustion destroys the organic compounds. Three main
technical barriers limit the feasibility of RECs at some wells: proximity of pipelines, pressure of
produced gas, and inert gas concentration.
Fugitive Emissions: There are several potential sources of fugitive emissions throughout the oil
and natural gas sector. Fugitive emissions occur when connection points are not fitted properly
or when seals and gaskets start to deteriorate. Changes in pressure and pressure or mechanical
stresses can also cause components or equipment to leak. Potential sources of fugitive emissions
include agitator seals, connectors, pump diaphragms, flanges, instruments, meters, open-ended
3-2
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lines, pressure relief devices, pump seals, valves or improperly controlled liquid storage tanks.
These fugitive emissions do not include devices that vent as part of normal operations, such as
gas driven pneumatic controllers or gas driven pneumatic pumps.
The TSD considers fugitive emissions from production well sites, gathering line and
boosting stations, and natural gas transmission/storage compressor stations. There are two
options for reducing methane and VOC emissions from leaking components: a leak monitoring
program based on individual component monitoring using EPA Method 21 for leak detection
combined with a leak correction, and a leak monitoring program based on the use of OGI leak
detection combined with leak correction. In addition, alternative frequencies for fugitive
emissions surveys were considered: annual, semiannual, and quarterly.
Pneumatic controllers: Pneumatic controllers are automated instruments used for maintaining a
process condition such as liquid level, pressure, pressure differential, and temperature. In many
situations across all segments of the oil and natural gas industry, pneumatic controllers make use
of the available high-pressure natural gas to operate or control a valve. In these "gas-driven"
pneumatic controllers, natural gas may be released with every valve movement and/or
continuously from the valve control pilot. Not all pneumatic controllers are gas driven. These
"non-gas driven" pneumatic controllers use sources of power other than pressurized natural gas.
Examples include solar, electric, and instrument air. At oil and gas locations with electrical
service, non-gas-driven controllers are typically used. Continuous bled pneumatic controllers can
be classified into two types based on their emissions rates: (1) high-bleed controllers and (2)
low-bleed controllers. A controller is considered to be high-bleed when the continuous bleed
emissions are in excess of 6 standard cubic feet per hour (scfh), while low-bleed devices bleed at
a rate less than or equal to 6 scfh. The EPA evaluated the impact of replacing high-bleed
controllers with low-bleed controllers.
Pneumatic pumps: Pneumatic pumps are devices that use gas pressure to drive a fluid by raising
or reducing the pressure of the fluid by means of a positive displacement, a piston or set of
rotating impellers. Gas powered pneumatic pumps are generally used at oil and natural gas
production sites where electricity is not readily available (GRI/EPA, 1996) and can be a
significant source of methane and VOC emissions. Pneumatic chemical and methanol injection
3-3
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pumps are generally used to pump fairly small volumes of chemicals or methanol into well-
bores, surface equipment, and pipelines. Typically, these pumps include plunger pumps with a
diaphragm or large piston on the gas end and a smaller piston on the liquid end to enable a high
discharge pressure with a varied but much lower pneumatic supply gas pressure. They are
typically used semi-continuously with some seasonal variation. Pneumatic diaphragm pumps are
another type used widely in the onshore oil and gas sector to move larger volumes of liquids per
unit of time at lower discharge pressures than chemical and methanol injection pumps. The usage
of these pumps is episodic including transferring bulk liquids such as motor oil, pumping out
sumps, and circulation of heat trace medium at well sites in cold climates during winter months.
For both of these types of pumps, emissions occur when the gas used in the pump stroke
is exhausted to enable liquid filling of the liquid chamber side of the diaphragm. Emissions are a
function of the amount of fluid pumped, the pressure of the pneumatic supply gas, the number of
pressure ratio's between the pneumatic supply gas pressure and the fluid discharge pressure, and
the mechanical inefficiency of the pump. As discussed in the white papers, we identified several
options for reducing methane and VOC emissions: replace natural gas-assisted pump with
instrument air pump, replace natural gas-assisted pump with solar-charged direct current pump
(solar pumps), replace natural gas-assisted pump with electric pump, and route pneumatic pump
emissions to a control device. The EPA evaluated the impact of routing pump emissions to a pre-
existing on-site control device.
Centrifugal and Reciprocating Compressors: Compressors are mechanical devices that
increase the pressure of natural gas and allow the natural gas to be transported from the
production site, through the supply chain, and to the consumer. The types of compressors that are
used by the oil and gas industry as prime movers are reciprocating and centrifugal compressors.
Centrifugal compressors use either wet or dry seals.
Emissions from compressors occur when natural gas leaks around moving parts in the
compressor. In a reciprocating compressor, emissions occur when natural gas leaks around the
piston rod when pressurized natural gas is in the cylinder. Over time, during operation of the
compressor, the rod packing system becomes worn and will need to be replaced to prevent
excessive leaking from the compression cylinder. The potential control options reviewed for
3-4
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reducing emissions from reciprocating compressors include control techniques that limit the
leaking of natural gas past the piston rod packing. This includes replacement of the compressor
rod packing, replacement of the piston rod, and the refitting or realignment of the piston rod.
Emissions from centrifugal compressors depend on the type of seal used: either "wet",
which use oil circulated at high pressure, or "dry", which use a thin gap of high pressure gas. The
use of dry gas seals substantially reduces emissions. In addition, they significantly reduce
operating costs and enhance compressor efficiency. Limiting or reducing the emission from the
rotating shaft of a centrifugal compressor using a mechanical dry seal system was evaluated. For
centrifugal compressors equipped with wet seals, a flare was evaluated as an option for reducing
emissions from centrifugal compressors.
3.4 Engineering Cost Analysis
In this section, we provide an overview of the engineering cost analysis used to estimate
the additional private expenditures industry may make to comply with the proposed NSPS. A
detailed discussion of the methodology used to estimate cost impacts is presented in the TSD,
which is published in the Docket.
The following sections describe each step in the engineering cost analysis. First,
representative facilities are established for each source category, including baseline emissions
and control options. The regulatory alternatives include different variations of regulatory
requirements considered for inclusion in the proposed standards. Then, projections are made of
the number of incrementally affected facilities for each type of equipment or facility. National
emissions reductions and cost estimates result from multiplying representative factors by the
number of affected facilities in each projection year. In addition to emissions reductions, some
control options result in natural 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.
3.4.1 Regulatory Options
For each emissions source, point, and control option, the TSD develops a representative
facility. The characteristics of this facility include typical equipment, operating characteristics,
3-5
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and representative factors including baseline emissions and the costs, emissions reductions, and
product recovery resulting from each control option. In this RIA, we examine three broad
regulatory options.18 Table 3-1 shows the emissions sources, points, and controls for the three
NSPS regulatory options analyzed in this RIA, which we term Option 1, Option 2, and Option 3.
Options 1 and 2 were selected for co-proposal.
1 The EPA also analyzed a variant of proposed Option 2 where only emissions combustion is required for
hydraulically fractured and re-fracture oil well completions, rather than require reduced emissions completions
(RECs) in combination with combustion. This variation of the proposed Option 2 would achieve direct emission
reduction that are equivalent to requiring RECs and combustion, but at an approximately $70 million per year
lower cost. However, as explained in Section VIII.F of the preamble to the proposed NSPS, the EPA determined
RECs and combustion to be the best system of emissions reduction. Section 4 of the Technical Support
Document for the proposal presents the detailed technical analysis of the regulatory options for hydraulically
fractured and re-fractured oil well completions.
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Table 3-1 Emissions Sources and Controls Evaluated at Proposal for the NSPS
Emissions Point
Emissions Control Option 1
Option 2
(proposed)
Option 3
Well Completions and Recompletions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured Wildcat
and Delineation Oil Wells
Fugitive Emissions
Well Pads
Gathering and Boosting Stations
Transmission Compressor Stations
Pneumatic Pumps
Well Pads
Gathering and Boosting Stations
Transmission and Storage
Compressor Stations
Pneumatic Controllers -
Natural Gas Transmission and
Storage Stations
Reciprocating Compressors
Natural Gas Transmission and
Storage Stations
Centrifugal Compressors
Natural Gas Transmission and
Storage Stations
RFC / Combustion
Combustion
Monitoring and
Maintenance
Monitoring and
Maintenance
Monitoring and
Maintenance
Route to control
Route to control
Route to control
Emissions limit
Annual Monitoring
and Maintenance
Route to control
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Annual Semiannual Quarterly
Semiannual Semiannual Quarterly
Semiannual Semiannual Quarterly
X
X
X
X
X
X
The co-proposed Option 2 contains reduced emission completion (REC) and completion
combustion requirements for a subset of newly completed oil wells that are hydraulically
fractured or refractured. Option 2 also requires fugitive emissions survey and repair programs be
performed semiannually (twice per year) at newly drilled or refractured oil and natural gas well
sites, new or modified gathering and boosting stations, and new or modified transmission and
storage compressor stations. However, low production well sites are exempt from the well site
fugitive requirements. A low production site is defined by the average combined oil and natural
3-7
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gas production for the wells at the site being less than 15 barrels of oil equivalent (boe) per day.19
Option 2 also requires reductions from centrifugal compressors, reciprocating compressors,
pneumatic controllers, and pneumatic pumps throughout the oil and natural gas source category.
While the EPA is proposing an exclusion from fugitive emission requirements for low
production well sites, there is uncertainty in how many well sites this exclusion might affect in
the future. As a result, the analyses in this RIA presents a "low" impact case and "high" impact
case for fugitive emissions requirements at well sites. The low impact case excludes from
analysis an estimate low production sites, assuming that the fraction of wells meeting the low
production criteria in the future will be the same as in 2012 (based on the first month of
production data from wells newly completed or modified in 2012).The high impact case includes
all forecast well sites providing a bounding case where no newly completed or modified wells
meet the low production criteria. Summary results for option 2, then, are presented as ranges.
Options 1 and 3 differ from the Option 2 with respect to the requirements for fugitive
emissions. Meanwhile, the co-proposed Option 1 requires annual monitoring for well sites,
including low production sites, while maintaining semiannual requirements for others sites. The
more stringent 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 over the co-proposed Option 2.
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 their emissions control activities as a result of the
proposal. Facilities in states with similar state-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 proposal over a longer period of time. Affected
19 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels of crude oil
equals 1000 cubic feet natural gas.
3-8
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facilities are facilities which are new or modified since the effective 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 modified in each year, and to the extent the facilities remain in
operation in future years, the total number of facilities subject to the NSPS accumulates. In 2025,
affected facilities include facilities newly established or modified in 2025, but also facilities
which were newly established or modified from 2020 through 2024 and are still operating in
2025.
The EPA has projected affected facilities using a combination of historical data from the
U.S. GHG Inventory, and projected activity levels, taken from the Energy Information
Administration (EIA's) Annual Energy Outlook (AEO). The EPA derived typical counts for new
compressors, pneumatic controllers, and pneumatic pumps by averaging the year-to-year
increases over the past ten years in the Inventory. New and modified hydraulically fractured oil
well completions and well sites are based on projections and growth rates consistent with the
drilling activity in the 2014 Annual Energy Outlook.
The 2014 Annual Energy Outlook was the most recent projection available at the time
that the analysis underlying this RIA was being prepared. However, since then the 2015 Annual
Energy Outlook has been released by the U.S. Energy Information Administration. The 2015
AEO reflects that growth in U.S. crude oil production over the last two years, along with the late-
2014 drop in global crude oil prices, have altered the economics of the oil market. In comparison
to 2014 AEO reference case, the 2015 AEO reference case shows higher crude oil production (in
2025, 18 percent higher in 2015 AEO), slightly lower natural gas production (in 2025, about 4
percent lower in 2015 AEO15), lower Brent spot and West Texas Intermediate crude oil prices,
and lower total wells drilled in the lower 48 states (in 2025, about 20 percent lower in 2015
AEO). If this RIA were updated to reflect the lower drilling activity in 2015 AEO, then the
national costs and emissions reductions of the oil well completions and well site fugitives
provisions of the rule would likely be reduced. Costs and emissions reductions per facility would
not be affected, however.
We also reviewed state regulations and permitting requirements, which require mitigation
measures for many emission sources in the oil and natural gas sector. State regulations in
3-9
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Colorado and Wyoming both require RECs for hydraulically fractured oil and gas wells. Sources
in Colorado, Wyoming, Utah, and Ohio are subject to fugitive emissions requirements.
Applicable facilities in these states are not included in the estimates of incrementally affected
facilities presented in the RIA, as sources in those states are already subject to similar
requirements to the federal standards. A more detailed discussion on the derivation of the
baseline for the current proposal is presented for each emissions source is the TSD. The
estimated counts of hydraulically-fractured and re-fracture oil well completions also account for
the wells anticipated to be excluded from the proposed NSPS requirements because of a gas-to-
oil ratio (GOR) of 300 or below.
Table 3-2 Number of Incrementally Affected Sources for the NSPS
Emissions Sources
Hydraulically Fractured and Re-fractured Oil Well Completions
Fugitive Emissions2
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total2
Incrementally
2020
15,000
14,000 to 22,000
3,000
68
210
3 1,000 to 40,000
Affected Sources
20251
15,000
86,000 to 140,000
18,000
410
1,300
120,000 to 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 low end of the range in the fugitive emissions and total rows reflect the number of incrementally affected
sources under the low impact co-proposed Option 2, which excludes low production well sites.
Table 3-2 presents the estimates of the number of incrementally affected sources for this
proposal after accounting for state regulations as described above. Note that hydraulically
fractured and re-fractured oil well completions do not grow significantly from 2020 to 2025,
while other sources do. This is a result of completions being a one-time activity in a given year,
while other sources are affected and remain affected as they continue to operate, thus these
sources accumulate over time. The estimates for that hydraulically fractured and re-fractured oil
well completions and fugitive emissions at well sites (a large fraction of the incrementally
affected sources under the proposed rule fugitive emissions provisions) include both new and
modified sources. The estimates for other sources are based upon projections of new sources
alone. While some of these sources, particularly pneumatic pumps and controllers, are likely to
be predominantly new sources, the impact estimates may be under-estimated by the under-
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represented modified sources. In the preamble to the proposed rale, 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 modification of relevant sources, as well as the number of wells on
well sites.
3.4.3 Emissions Reductions
Table 3-3 summarizes the national emissions 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. Table 3-1 summarizes the applicable controls, and
Table 3-2 summarizes the affected facilities, aggregating multiple model plant types within each
source category (e.g., oil well completions combine development and exploratory wells). The
detailed description of emissions controls is provided in the TSD. Please note that all results have
been rounded to two significant digits.
Table 3-3 Emissions Reductions for Proposed NSPS Option 2, 2020 and 2025
Emissions Reductions, 2020
Source/Emissions
Point
Oil Well Completions
and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
Methane
(short tons)
140,000
24,000 to 33,000
5,400
1,600
590
170,000 to 180,000
VOC
(short tons)
110,000
6,200 to 8,700
1,500
43
16
120,000
HAP
(short tons)
14
230 to 330
57
1
0
310 to 400
Methane
(metric tons CCh Eq.)
63,100,000
740,000 to 750,000
120,000
36,000
13,000
3,800,000 to 4,000,000
Emissions Reductions, 2025
Source/Emissions
Point
Oil Well Completions
and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
Methane
(short tons)
140,000
150,000 to 210,000
32,000
9,400
3,500
340,000 to 400,000
VOC
(short tons)
120,000
40,000 to 57,000
9,000
260
97
170,000 to 180,000
HAP
(short tons)
14
1,500 to 2,200
340
8
3
2,200 to 2,500
Methane
(metric tons CCh Eq.)
3,100,000
3,500,000 to 4,900,000
740,000
210,000
80,000
7,700,000 to 9,000,000
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3.4.4 Product Recovery
The annualized cost estimates presented below include revenue from additional natural
gas recovery in the production and processing segments. Several emission controls for the NSPS
capture methane and VOC emissions that otherwise 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 saleable natural gas, we base the
estimated revenues from averted natural gas emissions on an estimate of the amount of natural
gas that would not be emitted during one year for the control.
The standards that result in natural gas recovery are: RECs at hydraulically fractured oil
wells, fugitive emissions monitoring and repair, rod packing replacement in reciprocating
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 strategies do result in natural gas
recovery, but these alternative controls were not assumed as part of this analysis. For example,
alternatives to routing pneumatic pump emissions to a control device include substituting a solar
or electric pump where a gas-driven pump would have otherwise been used.
Table 3-5 summarizes natural gas recovery and revenue included in annualized cost
calculations. When including the additional natural gas recovery in the cost analysis, we assume
that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the wellhead.
The Energy Information Administration's 2014 Annual Energy Outlook forecasted wellhead
prices paid to lower 48 state producers to be $4.46/Mcf in 2020 and $5.06/Mcf in 2025. The
$4/Mcf price assumed in this RIA is intended to reflect the AEO estimate but simultaneously be
conservatively low.
Natural gas recovery at any point in the system provide benefits to the energy system and
to the public. However, due to contractual arrangements, transmission and storage companies do
not always benefit from lowering the leak rate of their operations because they do not necessarily
own the gas, and fixed loss rates are included in long-term contracts. As a result, the EPA
excludes revenue from natural gas recovery in estimating compliance costs for the transmission
and storage segment. This approach likely overestimates the long-term compliance cost of the
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controls.
Table 3-4 Estimated Natural Gas
and 2025
Recovery (Mcf) for Proposed NSPS Option 2 in 2020
2020
Source/Emissions
Point
Oil Well Completions
and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
Gas recovery
(Mcf)
6,200,000
1,400,000 to
1,900,000
0
76,000
30,000
7,700,000 to
8,200,000
Revenue from
recovery
(millions 2012$)
$25
$5.1 to $7.3
$0
$0
$0
$30 to $32
2025
Gas recovery
(Mcf)
6,200,000
8,900,000 to
12,000,000
0
450,000
180,000
16,000,000 to
19,000,000
Revenue from
recovery
(millions 2012$)
$25
$33 to $47
$0
$0
$0
$58 to $72
As natural gas prices can increase or decrease rapidly, the estimated engineering
compliance costs can vary when revenue from additional natural gas recovery is included. There
is also geographic variability in wellhead prices, which can also influence estimated engineering
costs. For the proposed option, a $l/Mcf change in the wellhead price causes a change in
estimated engineering compliance costs of about $8 million in 2020 and $16 to $19 million in
2025, in 2012 dollars.
3.4.5 Engineering Compliance Costs
Table 3-6 summarizes the capital and annualized costs for the evaluated emissions
sources and points. The detailed description of costs estimates is provided in TSD. To estimate
total annualized engineering compliance costs, we added the annualized costs of each item
without accounting for different expected lifetimes. This approach is mathematically equivalent
to establishing an overall, representative project time horizon and annualizing costs after
consideration of control options that would need to be replaced periodically within the given
time horizon.
3-13
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Table 3-5 Engineering Compliance Cost Estimates for Proposed NSPS Option 2 in
2020 and 2025 (millions 2012$)
Source/Emissions Point
Oil Well Completions and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Reporting and Recordkeeping
Total
Compliance
Capital
Costs
(2012$)
$150
$15 to $22
$5.9
$0.54
$0.048
$0.0
$170 to!80
Costs, 2020
Nationwide
Annualized
Costs (2012$)
$120
$29 to $47
$0.84
$0.25
$0.0052
$1.4
$150 to $170
Compliance
Capital
Costs
(2012$)
$150
$95 to $140
$36.0
$3.2
$0.29
$0.0
$280 to $330
Costs, 2025
Nationwide
Annualized
Costs (2012$)
$120
$180 to $290
$5.1
$1.5
$0.031
$4.1
$320 to $420
Engineering capital costs were annualized using a 7 percent interest rate. Section 3.4
provides a comparison to using a 3 percent interest rate. Different emissions control options were
annualized using expected lifetimes that were determined to be most appropriate for individual
options. For control options evaluated for the NSPS, the following lifetimes were used:
• Reduced emissions completions and combustion devices: 1 year (more discussion of the
selection of a one-year lifetime follows in this section)
• Fugitive emissions monitoring program design: 8 years
• Reciprocating compressors rod packing: 3.8 - 4.4 years
• Centrifugal compressors, pneumatic controllers, and pneumatic pumps: 10 years
Reporting and recordkeeping costs were drawn from the information collection requirements
(ICR) in this proposed rule that have been submitted for approval to the Office of Management
and Budget (OMB) under the Paperwork Reduction Act (see Chapter 5 for more detail). The
2020 reporting and recordkeeping costs in this RIA ($1.4 million) are based on the first year ICR
cost estimates. Meanwhile, we drew upon the first year cost in the ICR cost estimates ($4.1
million) and applied that cost to 2025 in this RIA.
3.4.6 Cost-Effectiveness
This section summarizes the cost-effectiveness of the proposed standards for each source
in 2020 and 2025. The proposed NSPS includes standards for both methane and VOC reductions.
3-14
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As discussed in the preamble to this action, cost-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 spent. In the context of air pollution control
options, cost-effectiveness typically refers to the annualized cost of implementing an air
pollution control option divided by the amount of pollutant reductions realized annually. A cost-
effectiveness analysis is not intended to constitute or approximate a cost-benefits analysis but
rather provides a metric of the relative cost to reduction ratios of various control options.
The estimation and interpretation of cost-effectiveness values is relatively straightforward
when an abatement measure controls a single pollutant. Increasingly, however, air pollution
reduction programs require reductions in emissions of multiple pollutants, and in such programs
multipollutant controls may be employed. Consequently, there is a need for determining cost-
effectiveness for a control option across multiple pollutants (or classes of multiple pollutants).
This is the case for the current proposal where the EPA is proposing to directly regulate both
methane and VOC.
To assign the entire annualized cost to the reduction in emissions of a single pollutant
reduced by the multipollutant control option is appropriate when reductions of the other
pollutants are considered to cobenefits with no cost. However, under the current proposal,
methane and VOCs are both directly regulated; therefore, reductions of each pollutant must be
properly considered benefits, not co-benefits, and consideration of only one of the regulated
pollutants is not appropriate.
Alternatively, all annualized costs can be allocated to each of the pollutant emission
reductions addressed by the multipollutant control option. Unlike the approach above, no
emission reduction is treated as a co-benefit; each emission reduction is assessed based on the
full cost of the control. However, this approach, which is often used for assessing single-
pollutant controls, evaluates emission reduction of each pollutant separately, assuming that each
bears the entire cost, and thus inflates the control cost in the multiple of the number of additional
pollutants being reduced. This approach therefore over-estimates the cost of obtaining emissions
reductions with a multipollutant control as it does not recognize the simultaneity of the
reductions achieved by the application of the control option. Another approach allocates the
3-15
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annualized cost to the sum of the individual pollutant emission reductions addressed by the
multipollutant control option. The multipollutant cost-effectiveness approach may be appropriate
when each of the pollutant reductions is similar in value or impact. However, in the current
proposal, methane and VOC have quite different 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 assign all costs to the emission reduction of one pollutant and zero to
all other concurrent reductions; if the cost is reasonable for reducing any of the targeted
emissions alone, the cost of such control is clearly reasonable for the concurrent emission
reduction of all the other pollutants because they are being reduced at no additional cost. While
this approach assigns all costs to only a portion of the emission reduction, it does not overstate
the cost. It also does not require unreasonable assumptions about the equivalency of the impacts
between a ton of methane and VOC emission reduction, which is not appropriate as discussed in
the option immediately above. In addition, this approach is simple and straight forward in
application. If the multipollutant control is cost effective for reducing emissions of either of the
targeted pollutant, it is clearly cost effective for reducing all other targeted emissions that are
being achieved simultaneously.
A second approach, which we term a "multipollutant cost-effectiveness" approach,
apportions the annualized cost across the pollutant reductions addressed by the control option in
proportion to the relative percentage reduction of each pollutant controlled by mass. For
example, in this proposal both methane and VOC 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 approach similarly does not inflate the control cost nor requires
unreasonable assumptions about the equivalency of the impacts between a ton of methane and
VOC emission reduction.
We believe that both approaches discussed above are appropriate for assessing the
reasonableness of the multipollutant controls considered in this action. As such, in our analyses
3-16
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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 appropriate in other instances.
Under the single pollutant cost-effectiveness approach, the total national compliance
costs are divided by the emissions reductions for methane and VOC separately (Table 3-6). This
approach does not account for the combined emissions reductions of both pollutants. We only
present the cost-effectiveness for the high impact case for fugitive emissions requirements at
well sites. The low impact case would show lower dollar per ton estimates.
Table 3-6 Single Pollutant Approach to Engineering Compliance Cost-Effectiveness
Estimates in 2020 and 2025 for Proposed NSPS Option 2 (High Impact Case for Well Site
Fugitive Emissions Requirements)
Cost-Effectiveness, 2020
(2012$)
Source/ Emissions Point
Oil Well Completions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
Methane
($/short
ton)
$910
$1,400
$160
$160
$9
$980
VOC
($/short
ton)
$1,100
$5,300
$560
$5,600
$320
$1,400
Methane
($/metric
ton CO2
Eq.)
$40
$62
$7
$7
$0
$43
Cost-Effectiveness, 2025
(2012$)
Methane
($/short
ton)
$900
$1,400
$160
$160
$9
$1,100
VOC
($/short
ton)
$1,100
$5,100
$560
$5,600
$320
$2,300
Methane
($/metric
ton CO2
Eq.)
$39
$60
$7
$7
$0
$47
For the multipollutant cost-effectiveness approach, costs are allocated proportionally to
methane and VOC reductions based on the percent reduction achieved in each pollutant (Table 3-
7). Because the relevant oil and gas controls reduce methane and VOC in equal proportion, 50
percent of costs are allocated to each emission.
3-17
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Table 3-7 Multipollutant Approach to Engineering Compliance Cost-Effectiveness
Estimates for Proposed NSPS Option 2 in 2020 and 2025 (High Impact Case for Well Site
Fugitive Emissions Requirements)
Cost-Effectiveness, 2020
(2012$)
Source/ Emissions Point
Oil Well Completions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
Methane
($/short
ton)
$450
$710
$78
$78
$5
$490
voc
($/short
ton)
$540
$2,700
$280
$2,800
$160
$690
Methane
($/metric
ton CO2
Eq.)
$20
$31
$3
$3
$0
$22
Cost-Effectiveness, 2025
(2012$)
Methane
($/short
ton)
$450
$680
$78
$78
$5
$530
VOC
($/short
ton)
$530
$2,500
$280
$2,800
$160
$1,200
Methane
($/metric
ton CO2
Eq.)
$20
$30
$3
$3
$0
$24
3.4.7 Comparison of Regulatory Alternatives
Table 3-8 presents a comparison of the regulatory alternatives through each step of the
emissions analysis in 2020 and 2025.20 The requirements between the options vary with respect
to the fugitive emissions requirements. Option 1 includes requirements for annual fugitive
emissions surveys at well sites but semiannual frequency at other sites, and Option 3 includes
requirements for quarterly fugitive emissions surveys, as opposed the semiannual requirement in
Options 2. Annual, semiannual, and quarterly fugitive emissions surveys are assumed to result in
respective reductions in emissions of 40 percent, 60 percent, and 80 percent, but affect the same
number of sources. Natural gas recovery also varies as a result of survey frequency. Variation in
natural gas recovery, capital and annualized costs reflect these differences in the number of
affected facilities and frequency of fugitive emissions surveys.
20 The EPA also analyzed a variant of proposed Option 2 where only emissions combustion is required for
hydraulically fractured and re-fracture oil well completions, rather than require reduced emissions completions in
combination with combustion (RECs). This variation of the proposed Option 2 would achieve direct emission
reduction that are equivalent to requiring RECs and combustion, but at an approximately $70 million per year
lower cost. However, as explained in Section VIII.F of the preamble to the proposed NSPS, the EPA determined
RECs and combustion to be the best system of emissions reduction. Section 4 of the Technical Support
Document for the proposal presents the detailed technical analysis of the regulatory options for hydraulically
fractured and re-fractured oil well completions.
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Table 3-8 Comparison of Regulatory Alternatives
Option 1
Regulatory Alternative
Option 2
(proposed)
Option 3
Impacts in 2020
Affected Sources 40,000
Emissions Reductions
Methane Emissions Reduction (short
, x 1 /U.UUU
tons/year)
VOC Emissions Reduction (short tons/year) 120,000
Natural Gas Recovery (Mcf) 7,700,000
Compliance Costs
Capital Costs (2012$) $180,000,000
Annualized Costs (2012$) $150,000,000
Cost-Effectiveness (Single Pollutant Approach)1
Methane (2012$ / short ton) $920
VOC (2012$ / short ton) $1,300
Cost-Effectiveness (Multipollutant Approach)1
Methane (2012$/shortton) $460
VOC (2012$ / short ton) $630
31,000 to 40,000 40,000
170,000 to 180,000 190,000
120,000 130,000
7,700,000 to 8,200,000 8,800,000
$170,000,000 to $180,000,000 $180,000,000
$150,000,000 to $170,000,000 $210,000,000
$920 to $980
$1,300 to $1,400
$460 to $490
$640 to $690
$1,100
$1,700
$570
$840
Impacts in 2025
Affected Sources 180,000
Emissions Reductions
Methane Emissions Reduction (short , .„ „„„
tons/year)
VOC Emissions Reduction (short tons/year) 170,000
Natural Gas Recovery (Mcf) 16,000,000
Compliance Costs
Capital Costs (2012$) $330,000,000
Annualized Costs (2012$) $310,000,000
Cost-Effectiveness (Single Pollutant Approach)1
Methane (2012$/shortton) $920
VOC (2012$ / short ton) $1,900
Cost-Effectiveness (Multipollutant Approach)1
Methane (2012$ / short ton) $460
VOC (2012$ / short ton) $940
120,000 to 180,000 180,000
340,000 to 400,000 470,000
170,000 to 180,000 200,000
16,000,000 to 19,000,000 23,000,000
$280,000,000 to $330,000,000 $330,000,000
$320,000,000 to $420,000,000 $680,000,000
$940 to $1,100 $1,400
$1,900 to $2,300 $3,400
$470 to $530 $720
$960 to $1,200 $1,700
Cost-effectiveness based on high impact case for well site fugitive emissions requirements.
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3.4.8 Capital and Annualized Compliance Costs Compared to Industry-lev el Capital
Expenditures and Revenues
In order to provide another perspective on the reasonableness of the estimated cost of
control as determined in our evaluation of "Best System of Emission Reduction" (BSER) for the
proposed standards, we analyzed the total cost of the rule for each type of affected facility under
two additional approaches using industry economic data.
First, we compared the total nationwide capitals costs that would be incurred for each
type of affected facility to comply with the proposed standards to the industry's estimated new
annual capital expenditures. This analysis allowed us to compare the capital costs that would be
incurred to comply with the proposed standards to the level of new capital expenditures that the
industry is incurring in the absence of the proposed standards. Capital expenditure data for
relevant NAICS codes covered by the rule were obtained from the U.S. Census 2013 Annual
Capital Expenditures Survey21. For the capital expenditures analysis, we determined the
estimated nationwide capital costs incurred by each type of affected facility to comply with the
proposed standards, then divided the nationwide capital costs by the new capital expenditures
(Census data) for the appropriate NAICS code(s) to determine the percentage that the nationwide
capital costs represent of the capital expenditures. For example, we used the total estimated
capital cost (nationwide) for hydraulically fractured development oil well completions and
compared that to the total capital expenditures the NAICs codes that correspond to oil and
natural gas production segment. Table 3-9 below summarizes the capital expenditure data used
for our analysis.
Table 3-9 NAICS-Based Capital Expenditure Data
Oil and Natural Gas
Segment NAICS Code
2111
Production
213111,213112
Transmission and Storage 4862
NAICS Description
Crude Petroleum and
Natural Gas Extraction
Support Activities for Oil
and Gas Operations
Pipeline transportation of
natural gas
Total New Expenditures
(millions, current $)
$158,911
$19,966
$12,891
21 Capital Expenditures for Structures and Equipment for Companies With Employees by Industry: 2013, Table 4a.
See http://www. census. go v/econ/aces/xls/2013/full_report. html
3-20
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For fugitive emissions standards at well sites and compressor stations, there are no actual
capital cost identified in the TSD. First year costs, which are corporate-based costs for these
standards are factored into the annual costs; however, these first year costs are not actual capital
costs and we therefore, determined that comparison of these costs to industry capital
expenditures would be inappropriate.
In the second approach, we compared the annualized costs that would be incurred to
comply with the standards to the industry's estimated annual revenues. This analysis allowed us
determine whether the annualized costs appear reasonable as a percentage of the revenues being
generated by the industry. The annualized costs, as calculated for the rule, include capital cost
annualized using a seven percent discount rate plus any annually incurred cost for
implementation of a control technology. We used annual costs without savings from natural gas
recovery in order to present the highest costs. The annual revenue data for relevant NAICS codes
were obtained from the U.S. Census 2012 County Business Patterns and 2012 Economic
Census22. For the annual revenues analysis, we determined the estimated nationwide annualize
costs incurred by each type of affected facility to comply with the proposed standards, then
divided the nationwide annualized costs by the annual revenues (Census data) for the appropriate
NAICS code(s) to determine the percentage that the nationwide annualized costs represent of
annual revenues. For example, we used the total annual cost (nationwide) for hydraulically
fractured development oil well completions and compared that to the total receipts for the NAICs
codes that correspond to oil and natural gas production segment. Table 3-10 below summarizes
the revenue data used for our analysis.
Table 3-10 NAICS-Based Revenue Data
Oil and Natural Gas
Segment
Production
Processing
Transmission and Storage
NAICS Code
211111
213112
211112
486210
NAICS Description
Crude Petroleum and Natural Gas Extraction
Support Activities for Oil and Gas Operations
Natural Gas Liquid Extraction
Pipeline Transportation of Natural Gas
Estimated
Receipts
(millions
2012$)
$276,077
$90,646
$49,236
$26,587
22 Number of Firms, Number of Establishments, Employment, Annual Payroll, and Estimated Receipts by Enterprise
Employment Size for the United States, All Industries: 2012. Release date: 6/22/2015. 2012 County Business
Patterns and 2012 Economic Census. For information on confidentiality protection, sampling error, and
nonsampling error, see http://www.census.gov/econ/susb/methodology.html. For definitions of estimated receipts
and other definitions, see http://www.census.gov/econ/susb/definitions.html.
3-21
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For the capital expenditures, the production segment was represented with the NAICS
codes 21111 " Crude Petroleum and Natural Gas Extraction" and 213111 and 213112 " Support
Activities for Oil and Gas Operations". The transmission and storage segment was represented
with the NAICS code 4862 "Pipeline transportation of natural gas". For revenue, the production
segment was represented with the NAICS codes 21111 " Crude Petroleum and Natural Gas
Extraction" and 213112 " Support Activities for Oil and Gas Operations". The transmission and
storage segment was represented with the NAICS code 486210 "Pipeline Transportation of
Natural Gas". Although there is not a one-to-one correspondence between NAICS codes and the
industry segments we used in the development of the analysis, we believe there is enough
similarity to draw accurate conclusions.
Because we are aware that different owners or operators are generally involved in the
different industry segments, we conducted the analysis at the affected facility level to ensure
proper characterization of the impact. We also conducted the analysis for all sources in the
production segment and in the transmission and storage segment. Table 3-11 summarizes the
result of our analysis. In all cases we found that the impacts of the proposed rule in comparison
to either capital expenditures or revenues represent a fraction of one percent.
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Table 3-11 Comparison of Proposed NSPS Nationwide Cost by Affected Facility Cost to
Industry-wide Capital Expenditures and Revenues
Oil and Natural Gas Segment/
Affected Facility
Number
of
Sources
Subject
to NSPS
Total
Nationwide
Capital Costs
(millions
2012$)
Total
Nationwide
Annual Cost
(millions
2012$)
Nationwide
Capital
Cost/
Capital
Expenditur
es (%)
Nationwide
Annual
Cost/
Receipts
(%)
Production
Hydraulically Fractured Oil Well Completions and Recompletions
- Development Oil Wells
- Exploratory/Delineation Oil
Wells
Gas-Driven Pumps
Fugitives - Well Sites
Total Production Segment
Transmission and Storage
Compressors
13,804
1,166
17,760
138,568
171,298
$144
$4
$36
NA
$184
$144
$4
$5
$310
$464
0.08%
0.00%
0.02%
NA
0.10%
0.03%
0.00%
0.00%
0.09%
0.13%
- Reciprocating
- Centrifugal
Pneumatic Controllers
Fugitives - Compressor Stations
Total Transmission and Storage
Segment
402
6
1,260
1,680
3,348
$2.80
$0.14
$0.29
NA
$3
$0.79
$0.02
$0.03
$27
$28
0.02%
0.01%
0.00%
NA
0.03%
0.00%
0.00%
0.00%
0.10%
0.11%
Source : All cost information is from the "Oil and Natural Gas Sector: Standards of Performance for Crude Oil and
Natural Gas Production, Transmission and Distribution, Background Technical Support Document for the Proposed
New Source Performance Standards, 40 CFR Part 60, subpart OOOOa" available in the docket. For Hydraulically
Fractured Oil Well Completions and Recompletions from Table 4-8, for Gas Driven Pumps from Table 7-19, for
Fugitives - Well sites from Table 5-31, for Compressors, Reciprocating from Table 8-13,for Centrifugal from
Table8-14, for Pneumatic controllers from- Table 6-9, and for Fugitives - Compressor Stations from Table 5-31.
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3.5 Compliance Costs Estimated using 3 and 7 Percent Discount Rates
Table 3-9 shows that the choice of discount rate has very minor effects on the nationwide
annualized costs of the proposed option.
Table 3-12 Annualized Costs using 3 and 7 Percent Discount Rates for Proposed NSPS
Option 2 in 2020 and 2025 (millions 2012$)
Oil Well Completions and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Reporting and Recordkeeping
Total
Nationwide Annualized
Costs, 2020 (2012$)
7 percent 3 percent
$120 $120
$29 to $47 $29 to $46
$0.84 $0.69
$0.25 $0.23
$0.0052 $0.0040
$1.4 $1.4
$150 to $170 $150 to $170
Nationwide Annualized
Costs, 2025 (2012$)
7 percent 3 percent
$120 $120
$180 to 290 $180 to $290
$5.1 $4.2
$1.5 $1.4
$0.031 $0.024
$4.1 $4.1
$320 to $420 $310 to $420
The choice of discount rate has a small effect on nationwide annualized costs. The
compliance costs related to oil well completions and fugitive emissions surveys occur in each
year, so the interest rate has little impact on annualized costs for these sources. The annualized
costs for pneumatic pumps, compressors, and pneumatic controllers are sensitive to interest rate,
but these constitute a relatively small part of the total compliance cost estimates for the proposal.
3.6 Detailed Impacts Tables
The following tables shows the full details of the costs and emissions reduction by
emissions sources for each regulatory option in 2020 and 2025.
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Table 3-13 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020
Nationwide Emissions Reductions
Incrementally
Affected
Source/Emissions Point Units
Methane VOC
(short tons) (short tons)
HAP
(short Methane (metric
tons) tons CO2 Eq.)
National Costs (2012$)
Ann. Costs With Addl.
Capital Costs Revenues
Well Completions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured
Wildcat and Delineation Oil
Wells
14,000
870
130,000
8,000
110,000
6,700
13
1
2,900,000
180,000
$140,000,000
$3,200,000
$120,000,000
$3,200,000
Fugitive Emissions
Well Pads
Gathering and Boosting
Stations
Transmission Compressor
Stations
22,000
260
21
17,000
5,500
1,700
4,800
1,500
47
180
57
1
390,000
120,000
39,000
$18,000,000
$4,200,000
$340,000
$25,000,000
$2,800,000
$440,000
Pneumatic Pumps
Well Pads
Gathering and Boosting
Stations
Transmission and Storage
Compressor Stations
3,000
0
0
5,400
0
0
1,500
0
0
57
0
0
120,000
0
0
$5,900,000
$0
$0
$840,000
$0
$0
Pneumatic Controllers -
Natural Gas Transmission
and Storage Stations
67
1,500
40
1
33,000
$470,000
$130,000
Reciprocating Compressors
Natural Gas Transmission
and Storage Stations
Centrifugal Compressors
Natural Gas Transmission
and Storage Stations
Reporting and Recordkeeping
TOTAL
1
210
All
40,000
110
590
0
170,000
3
16
0
120,000
0
0
0
310
2,500
13,000
0
3,800,000
$72,000
$48,000
$0
$180,000,000
$110,000
$5,200
$1,400,000
$150,000,000
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Table 3-14 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025
Nationwide Emissions Reductions
Incrementally
Source/Emissions Point Affected Units
Methane VOC
(short tons) (short tons)
HAP
(short Methane (metric
tons) tons CO2 Eq.)
National Costs (2012$)
Ann. Costs With Addl.
Capital Costs Revenues
Well Completions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured
Wildcat and Delineation
Oil Wells
14,000
1,200
130,000
11,000
110,000
9,000
13
1
2,900,000
240,000
$140,000,000
$4,300,000
$120,000,000
$4,300,000
Fugitive Emissions
Well Pads
Gathering and Boosting
Stations
Transmission Compressor
Stations
140,000
1,600
130
110,000
33,000
10,000
32,000
9,100
280
1,200
340
8
2,600,000
740,000
230,000
$110,000,000
$25,000,000
$2,100,000
$160,000,000
$17,000,000
$2,600,000
Pneumatic Pumps
Well Pads
Gathering and Boosting
Stations
Transmission and Storage
Compressor Stations
18,000
0
0
32,000
0
0
9,000
0
0
340
0
0
740,000
0
0
$36,000,000
$0
$0
$5,100,000
$0
$0
Pneumatic Controllers -
Natural Gas Transmission
and Storage Stations
400
8,800
240
7
200,000
$2,800,000
$790,000
Reciprocating Compressors
Natural Gas Transmission
and Storage Stations
Centrifugal Compressors
Natural Gas Transmission
and Storage Stations
Reporting and Recordkeeping
TOTAL
6
1,300
All
180,000
670
3,500
0
340,000
18
97
0
170,000
1
3
0
1,900
15,000
80,000
0
7,700,000
$430,000
$290,000
$0
$330,000,000
$680,000
$31,000
$4,100,000
$310,000,000
3-26
-------
Table 3-15 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact Case, 2020
Nationwide Emissions Reductions
National Costs (2012$)
Incrementally Methane (short VOC HAP (short Methane (metric
Source/Emissions Point Affected Units tons) (short tons) tons) tons COi Eq.)
Ann. Costs With Addl.
Capital Costs Revenues
Well Completions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured
Wildcat and Delineation Oil
Wells
14,000
870
130,000
8,000
110,000
6,700
13
1
2,900,000
180,000
$140,000,000
$3,200,000
$120,000,000
$3,200,000
Fugitive Emissions
Well Pads
Gathering and Boosting
Stations
Transmission Compressor
Stations
13,000
260
21
17,000
5,500
1,700
4,600
1,500
47
180
57
1
380,000
120,000
39,000
$11,000,000
$4,200,000
$340,000
$26,000,000
$2,800,000
$440,000
Pneumatic Pumps
Well Pads
Gathering and Boosting
Stations
Transmission and Storage
Compressor Stations
3,000
0
0
5,400
0
0
1,500
0
0
57
0
0
120,000
0
0
$5,900,000
$0
$0
$840,000
$0
$0
Pneumatic Controllers -
Natural Gas Transmission
and Storage Stations
67
1,500
40
1
33,000
$470,000
$130,000
Reciprocating Compressors
Natural Gas Transmission
and Storage Stations
Centrifugal Compressors
Natural Gas Transmission
and Storage Stations
Reporting and Recordkeeping
TOTAL
1
210
All
31,000
110
590
0
170,000
3
16
0
120,000
0
0
0
310
2,500
13,000
0
3,800,000
$72,000
$48,000
$0
$170,000,000
$110,000
$5,200
$1,400,000
$150,000,000
3-27
-------
Table 3-16 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, Low Impact Case, 2025
Nationwide Emissions Reductions
National Costs (2012$)
Incrementally
Source/Emissions Point Affected Units
Methane VOC Methane (metric
(short tons) (short tons) HAP (short tons) tons COi Eq.)
Ann. Costs With
Capital Costs Addl. Revenues
Well Completions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured
Wildcat and Delineation
Oil Wells
14,000
1,200
130,000
11,000
110,000
9,000
13
1
2,900,000
240,000
$140,000,000
$4,300,000
$120,000,000
$4,300,000
Fugitive Emissions
Well Pads
Gathering and Boosting
Stations
Transmission Compressor
Stations
84,000
1,600
130
110,000
33,000
10,000
31,000
9,100
280
1,200
340
8
2,500,000
740,000
230,000
$68,000,000
$25,000,000
$2,100,000
$160,000,000
$17,000,000
$2,600,000
Pneumatic Pumps
Well Pads
Gathering and Boosting
Stations
Transmission and Storage
Compressor Stations
18,000
0
0
32,000
0
0
9,000
0
0
340
0
0
740,000
0
0
$36,000,000
$0
$0
$5,100,000
$0
$0
Pneumatic Controllers -
Natural Gas Transmission
and Storage Stations
400
8,800
240
7
200,000
$2,800,000
$790,000
Reciprocating Compressors
Natural Gas Transmission
and Storage Stations
Centrifugal Compressors
Natural Gas Transmission
and Storage Stations
Reporting and Recordkeeping
TOTAL
6
1,300
All
120,000
670
3,500
0
340,000
18
97
0
170,000
1
3
0
1,900
15,000
80,000
0
7,700,000
$430,000
$290,000
$0
$280,000,000
$680,000
$31,000
$4,100,000
$320,000,000
3-28
-------
Table 3-17 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact Case, 2020
Nationwide Emissions Reductions
National Costs (2012$)
Incrementally
Affected
Source/Emissions Point Units
Methane VOC
(short tons) (short tons)
HAP
(short Methane (metric
tons) tons CO2 Eq.)
Ann. Costs With Addl.
Capital Costs Revenues
Well Completions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured
Wildcat and Delineation Oil
Wells
14,000
870
130,000
8,000
110,000
6,700
13
1
2,900,000
180,000
$140,000,000
$3,200,000
$120,000,000
$3,200,000
Fugitive Emissions
Well Pads
Gathering and Boosting
Stations
Transmission Compressor
Stations
22,000
260
21
26,000
5,500
1,700
7,200
1,500
47
270
57
1
590,000
120,000
39,000
$18,000,000
$4,200,000
$340,000
$43,000,000
$2,800,000
$440,000
Pneumatic Pumps
Well Pads
Gathering and Boosting
Stations
Transmission and Storage
Compressor Stations
3,000
0
0
5,400
0
0
1,500
0
0
57
0
0
120,000
0
0
$5,900,000
$0
$0
$840,000
$0
$0
Pneumatic Controllers -
Natural Gas Transmission
and Storage Stations
67
1,500
40
1
33,000
$470,000
$130,000
Reciprocating Compressors
Natural Gas Transmission
and Storage Stations
Centrifugal Compressors
Natural Gas Transmission
and Storage Stations
Reporting and Recordkeeping
TOTAL
1
210
All
40,000
110
590
0
180,000
3
16
0
120,000
0
0
0
400
2,500
13,000
0
4,000,000
$72,000
$48,000
$0
$180,000,000
$110,000
$5,200
$1,400,000
$170,000,000
3-29
-------
Table 3-18 Incrementally Affected Units, Emissions Reductions and Costs, Proposed Option 2, High Impact Case, 2025
Nationwide Emissions Reductions
Incrementally
Source/Emissions Point Affected Units
Methane VOC
(short tons) (short tons)
HAP
(short Methane (metric
tons) tons CO2 Eq.)
National Costs (2012$)
Ann. Costs With Addl.
Capital Costs Revenues
Well Completions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured
Wildcat and Delineation
Oil Wells
14,000
1,200
130,000
11,000
110,000
9,000
13
1
2,900,000
240,000
$140,000,000
$4,300,000
$120,000,000
$4,300,000
Fugitive Emissions
Well Pads
Gathering and Boosting
Stations
Transmission Compressor
Stations
140,000
1,600
130
170,000
33,000
10,000
48,000
9,100
280
1,800
340
8
3,900,000
740,000
230,000
$110,000,000
$25,000,000
$2,100,000
$270,000,000
$17,000,000
$2,600,000
Pneumatic Pumps
Well Pads
Gathering and Boosting
Stations
Transmission and Storage
Compressor Stations
18,000
0
0
32,000
0
0
9,000
0
0
340
0
0
740,000
0
0
$36,000,000
$0
$0
$5,100,000
$0
$0
Pneumatic Controllers -
Natural Gas Transmission
and Storage Stations
400
8,800
240
7
200,000
$2,800,000
$790,000
Reciprocating Compressors
Natural Gas Transmission
and Storage Stations
Centrifugal Compressors
Natural Gas Transmission
and Storage Stations
Reporting and Recordkeeping
TOTAL
6
1,300
All
180,000
670
3,500
0
400,000
18
97
0
180,000
1
3
0
2,500
15,000
80,000
0
9,000,000
$430,000
$290,000
$0
$330,000,000
$680,000
$31,000
$4,100,000
$420,000,000
3-30
-------
Table 3-19 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020
Nationwide Emissions Reductions
Incrementally
Affected
Source/Emissions Point Units
Methane VOC
(short tons) (short tons)
HAP
(short Methane (metric
tons) tons CO2 Eq.)
National Costs (2012$)
Ann. Costs With Addl.
Capital Costs Revenues
Well Completions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured
Wildcat and Delineation Oil
Wells
14,000
870
130,000
8,000
110,000
6,700
13
1
2,900,000
180,000
$140,000,000
$3,200,000
$120,000,000
$3,200,000
Fugitive Emissions
Well Pads
Gathering and Boosting
Stations
Transmission Compressor
Stations
22,000
260
21
34,000
7,300
2,300
9,600
2,000
63
360
76
2
780,000
170,000
52,000
$18,000,000
$4,200,000
$340,000
$81,000,000
$5,400,000
$780,000
Pneumatic Pumps
Well Pads
Gathering and Boosting
Stations
Transmission and Storage
Compressor Stations
3,000
0
0
5,400
0
0
1,500
0
0
57
0
0
120,000
0
0
$5,900,000
$0
$0
$840,000
$0
$0
Pneumatic Controllers -
Natural Gas Transmission
and Storage Stations
67
1,500
40
1
33,000
$470,000
$130,000
Reciprocating Compressors
Natural Gas Transmission
and Storage Stations
Centrifugal Compressors
Natural Gas Transmission
and Storage Stations
Reporting and Recordkeeping
TOTAL
1
210
All
40,000
110
590
0
190,000
3
16
0
130,000
0
0
0
510
2,500
13,000
0
4,200,000
$72,000
$48,000
$0
$180,000,000
$110,000
$5,200
$1,400,000
$210,000,000
3-31
-------
Table 3-20 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025
Nationwide Emissions Reductions
Incrementally
Source Affected Units
Methane VOC
(short tons) (short tons)
HAP
(short Methane (metric
tons) tons CO2 Eq.)
National Costs (2012$)
Ann. Costs With Addl.
Capital Costs Revenues
Well Completions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured
Wildcat and Delineation
Oil Wells
14,000
1,200
130,000
11,000
110,000
9,000
13
1
2,900,000
240,000
$140,000,000
$4,300,000
$120,000,000
$4,300,000
Fugitive Emissions
Well Pads
Gathering and Boosting
Stations
Transmission Compressor
Stations
140,000
1,600
130
230,000
44,000
14,000
64,000
12,000
380
2,400
460
11
5,200,000
990,000
310,000
$110,000,000
$25,000,000
$2,100,000
$510,000,000
$32,000,000
$4,700,000
Pneumatic Pumps
Well Pads
Gathering and Boosting
Stations
Transmission and Storage
Compressor Stations
18,000
0
0
32,000
0
0
9,000
0
0
340
0
0
740,000
0
0
$36,000,000
$0
$0
$5,100,000
$0
$0
Pneumatic Controllers -
Natural Gas Transmission
and Storage Stations
400
8,800
240
7
200,000
$2,800,000
$790,000
Reciprocating Compressors
Natural Gas Transmission
and Storage Stations
Centrifugal Compressors
Natural Gas Transmission
and Storage Stations
Reporting and Recordkeeping
TOTAL
6
1,300
All
180,000
670
3,500
0
470,000
18
97
0
200,000
1
3
0
3,200
15,000
80,000
0
11,000,000
$430,000
$290,000
$0
$330,000,000
$680,000
$31,000
$4,100,000
$680,000,000
3-32
-------
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 PMi.5 health benefits from VOC reductions, and HAP "co-benefits". These co-benefits
occur because the control techniques to meet the standards simultaneously reduce methane,
VOC, and HAP emissions. The proposed NSPS is anticipated to prevent 170,000 to 180,000 tons
of methane, 120,000 tons of VOC, and 310 to 400 tons of HAP from new sources in 2020. In
2025, the NSPS would prevent 340,000 to 400,000 tons of methane, 170,000 to 180,000 tons of
VOC, and 1,900 to 2,500 tons of HAP. The CO2-equivalent (CO2 Eq.) methane emission
reductions are estimated to be 3.8 to 4.0 million metric tons in 2020 and 7.7 to 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 $200 to
$210 million and $460 to $550 million using a 3 percent discount rate in 2020 and 2025,
respectively. The specific control techniques for the proposed NSPS are anticipated to have
minor emissions disbenefits (e.g., increases in emissions of carbon dioxide (COi), nitrogen
oxides (NOx), PM, carbon monoxide (CO), and total hydrocarbons (THC)) and emission
changes associated with the energy system impacts.
While we expect that the avoided VOC emissions will also result in improvements in air
quality and reduce health and welfare effects associated with exposure to ozone, fine particulate
matter (PMi.s), 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 provide 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 nature of air quality responses associated with HAP
4-1
-------
and VOC reductions.23 In this chapter, we provide a qualitative assessment of the health benefits
associated with reducing exposure to these pollutants, as well as visibility impairment and
ecosystem benefits. Table 4-1 summarizes the quantified and unquantified benefits in this
analysis.
Table 4-1 Climate and Human Health Effects of Emission Reductions from this
Proposal
Category
Effect Has
Specific Effect Been
Quantified
Effect Has
„ More
Been T ,
-, , Information
Monetized
Improved Environment
Reduced climate
effects
Global climate impacts from methane and [
carbon dioxide (CCh)
Other climate impacts (e.g., ozone, black
carbon, aerosols, other impacts)
Marten et al.
S (2014), SC-CO2
TSDs
IPCC, Ozone ISA,
~~ PM ISA2
Improved Human Health
Reduced incidence of
premature mortality
from exposure to
PM2.5
Reduced incidence of
morbidity from
exposure to PMa.s
Adult premature mortality based on cohort
study estimates and expert elicitation estimates —
(age >25 or age >30)
Infant mortality (age <1 ) —
Non-fatal heart attacks (age > 18) —
Hospital admissions — respiratory (all ages) —
Hospital admissions — cardiovascular (age >20) —
Emergency room visits for asthma (all ages) —
Acute bronchitis (age 8-12) —
Lower respiratory symptoms (age 7-14) —
Upper respiratory symptoms (asthmatics age 9-
11) ~~
Asthma exacerbation (asthmatics age 6-18) —
Lost work days (age 18-65) —
Minor restricted-activity days (age 18-65) —
Chronic Bronchitis (age >26) —
Emergency room visits for cardiovascular
effects (all ages)
Strokes and cerebrovascular disease (age 50-
79) ~~
Other cardiovascular effects (e.g., other ages) —
Other respiratory effects (e.g., pulmonary
function, non-asthma ER visits, non-bronchitis —
chronic diseases, other ages and populations)
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA3
— PM ISA2
— PM ISA2
23 Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the
effect that those emissions have on ambient PM2.5 levels and the health effects associated with PM2.5 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 all sectors. Coupled with the larger uncertainties about
the relationship between VOC emissions and PM2.5 and the highly localized nature of air quality responses
associated with VOC reductions, these factors lead us to conclude that the available VOC benefit-per-ton
estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding exercise.
4-2
-------
Category
Reduced incidence of
mortality from
exposure to ozone
Reduced incidence of
morbidity from
exposure to ozone
Reduced incidence of
morbidity from
exposure to HAP
Effect Has
Specific Effect Been
Quantified
Reproductive and developmental effects (e.g.,
low birth weight, pre-term births, etc)
Cancer, mutagenicity, and genotoxicity effects —
Premature mortality based on short-term study
estimates (all ages)
Premature mortality based on long-term study
estimates (age 30-99)
Hospital admissions — respiratory causes (age >
65) —
Hospital admissions — respiratory causes (age
<2) ~~
Emergency department visits for asthma (all
ages) ~~
Minor restricted-activity days (age 18-65) —
School absence days (age 5-17) —
Decreased outdoor worker productivity (age
18-65) ~~
Other respiratory effects (e.g., premature aging
of lungs)
Cardiovascular and nervous system effects —
Reproductive and developmental effects —
Effects associated with exposure to hazardous
air pollutants such as benzene
Effect Has , ,
„ More
Been T ,
-, , Information
Monetized
— PM ISA2-4
— PM ISA2-4
— Ozone ISA3
— Ozone ISA3
— Ozone ISA3
— Ozone ISA3
— Ozone ISA3
— Ozone ISA3
— Ozone ISA3
— Ozone ISA3
— Ozone ISA2
— Ozone ISA2
— Ozone ISA2-4
— ATSDR, IRIS2-3
Improved Environment
Reduced visibility
impairment
Reduced effects from
PM deposition
(organics)
Reduced vegetation
and ecosystem effects
from exposure to
ozone
Visibility in Class 1 areas —
Visibility in residential areas —
Effects on Individual organisms and
ecosystems
Visible foliar injury on vegetation —
Reduced vegetation growth and reproduction —
Yield and quality of commercial forest
products and crops
Damage to urban ornamental plants —
Carbon sequestration in terrestrial ecosystems —
Recreational demand associated with forest
aesthetics
Other non-use effects
— PM ISA3
— PM ISA3
— PM ISA2
— Ozone ISA3
— Ozone ISA3
— Ozone ISA3
— Ozone ISA2
— Ozone ISA3
— Ozone ISA2
Ozone ISA2
Ecosystem functions (e.g., water cycling,
biogeochemical cycles, net primary
productivity, leaf-gas exchange, community
composition)
Ozone ISA2
1 The global climate and related impacts of COa and CH4 emissions changes, such as sea level rise, are estimated within each
integrated assessment model as part of the calculation of the SC-CO2 and SC-CHt. The resulting monetized damages, which
are relevant for conducting the benefit-cost analysis, are used in this RIA to estimate the welfare effects of quantified changes
in COa emissions.
2 We assess these benefits qualitatively because we do not have sufficient confidence in available data or methods.
3 We assess these benefits qualitatively due to data limitations for this analysis, but we have quantified them in other analyses.
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.
4-3
-------
4.2 Emission Reductions from the Proposed NSPS
As described in Section 2 of this RIA, oil and natural gas operations in the U.S. include a
variety of emission points for methane, VOC, and HAP, including wells, well sites, processing
plants, compressor stations, storage equipment, and transmission and distribution lines. These
emission points are located throughout much of the country with significant concentrations in
particular regions. For example, wells and processing plants are largely concentrated in the South
Central, Midwest, and Southern California regions of the U.S., whereas gas compression stations
are located all over the country. Distribution lines to customers are frequently located within
areas of high population density.
In implementing this rule, emission controls may lead to reductions in ambient PlVh.5 and
ozone below the National Ambient Air Quality Standards (NAAQS) in some areas and assist
other areas with attaining the NAAQS. Due to the high degree of variability in the
responsiveness of ozone and PMi.5 formation to VOC emission reductions, we are unable to
determine how this rule might affect attainment status without air quality modeling data.24
Because the NAAQS RIAs also calculate ozone and PM benefits, there are important differences
worth noting in the design and analytical objectives of each RIA. The NAAQS RIAs illustrate
the potential costs and benefits of attaining a new air quality standard nationwide based on an
array of emission control strategies for different sources.25 By contrast, the emission reductions
for implementation rules, including this rule, are generally from a specific class of well-
characterized sources. In general, the EPA is more confident in the magnitude and location of the
emission reductions for implementation rules rather than illustrative NAAQS analyses. Emission
reductions achieved under these and other promulgated rules will ultimately be reflected in the
baseline of future NAAQS analyses, which would reduce the incremental costs and benefits
associated with attaining the NAAQS.
24 The responsiveness of ozone and PM2.s formation is discussed in greater detail in sections 4.4.1 and 4.5.1 of this
RIA.
25 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 intended 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.
4-4
-------
Table 4-2 shows the direct emission reductions anticipated for this rule, across the
regulatory options examined in the rule. It is important to note that these benefits accrue at
different spatial scales. HAP emission reductions reduce exposure to carcinogens and other toxic
pollutants primarily near the emission source. Reducing VOC emissions would reduce precursors
to secondary formation of PM2.5 and ozone, which reduces exposure to these pollutants on a
regional scale. Climate effects associated with long-lived greenhouse gases like methane
generally do not depend on the location of the emission of the gas, and have global impacts.
Methane is also a precursor to global background concentrations of ozone.
Table 4-2 Direct Emission Reductions
2025
Pollutant
Option 1
across NSPS Regulatory Options in 2020 and
Option 2
(proposed)
Option 3
2020
Methane (short tons/year)
VOC (short tons/year)
HAP (short tons/year)
Methane (metric tons)
Methane (metric tons COi Eq.)
170,000
120,000
310
150,000
3,800,000
170,000 to 180,000
120,000
3 10 to 400
150,000 to 160,000
3,800,000 to 4,000,000
190,000
130,000
510
170,000
4,200,000
2025
Methane (short tons/year)
VOC (short tons/year)
HAP (short tons/year)
Methane (metric tons)
Methane (metric tons COi Eq.)
340,000
170,000
1,900
310,000
7,700,00
340,000 to 400,000
170,000 to 180,000
1,900 to 2,500
3 10,000 to 360,000
7,700,000 to 9,000,000
470,000
200,000
3,200
430,000
11,000,000
4.3 Methane
4.3.1 Methane climate effects and valuation
Methane is the principal component of natural gas. Methane is also a potent greenhouse
gas (GHG) that once emitted into the atmosphere absorbs terrestrial infrared radiation that
contributes to increased global warming and continuing climate change. Methane reacts in the
atmosphere to form ozone and ozone also impacts global temperatures. Methane, in addition to
other GHG emissions, contributes to warming of the atmosphere, which over time leads to
increased air and ocean temperatures, changes in precipitation patterns, melting and thawing of
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global glaciers and ice, increasingly severe weather events, such as hurricanes of greater
intensity, and sea level rise, among other impacts.
According to the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment
Report (AR5, 2013), changes in methane concentrations since 1750 contributed 0.48 W/m2 of
forcing, which is about 17 percent of all global forcing due to increases in anthropogenic GHG
concentrations, and which makes methane the second leading long-lived climate forcer after
COi. However, after accounting for changes in other greenhouse substances such as ozone and
stratospheric water vapor due to chemical reactions of methane in the atmosphere, historical
methane emissions were estimated to have contributed to 0.97 W/m2 of forcing today, which is
about 30 percent of the contemporaneous forcing due to historical greenhouse gas emissions.
Processes in the oil and gas category emit 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 Gas Systems (not including petroleum refineries
and petroleum transportation) to be 182 MMt CO2 Eq. In 2013, total methane emissions from the
oil and gas industry represented nearly 29 percent of the total methane emissions from all
sources and account for about 3 percent of all COi Eq. emissions in the U.S., with the combined
petroleum and natural gas systems being the largest contributor to U.S. anthropogenic methane
emissions (U.S. EPA, 2015c).
It is important to note that the 2013 GHG emissions estimates do not include methane
emissions from hydraulically fractured and re-fractured oil well completions due to lack of
available data when the 2013 GHG Inventory estimate was developed. The estimate in this
proposed rule includes an adjustment for hydraulically fractured oil wells, and such an
adjustment is also being considered as a planned improvement in the 2014 Inventory (to be
published April 2016). This adjustment would increase the 2013 Inventory methane estimate by
about 3 MMt CCh Eq. The total methane emissions from Petroleum and Natural Gas Systems
based on the 2013 GHG Inventory, adjusted for hydraulically fractured and re-fractured oil well
completions, is approximately 185 MMt COi Eq.
Actions taken to comply with the proposed NSPS are anticipated to significantly decrease
methane emissions from the oil and natural gas sector in the United States. The proposed NSPS
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is expected to reduce methane emissions by about 170,000 to 180,000 short tons or
approximately 150,000 to 160,000 metric tons methane (or 3.8 to 4.0 MMt CChEq.) in 2020. In
2025, the proposed NSPS is expected to reduce methane emissions by about 340,000 to 400,000
short tons or approximately 310,000 to 360,000 metric tons methane (or 7.7 to 9.0 MMt CO2
Eq.). These reductions in 2020 and 2025 represent about 2 percent and 4 to 5 percent,
respectively, of the GHG emissions for this sector (excluding petroleum refineries and petroleum
transportation) reported in the 1990-2013 U.S. GHG Inventory (182 MMt CO2 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/O, a metric that
estimates the monetary value of impacts associated with marginal changes in methane emissions
in a given year. It includes a wide range of anticipated climate impacts, such as net changes in
agricultural productivity and human health, property damage from increased flood risk, and
changes in energy system costs, such as reduced costs for heating and increased costs for air
conditioning. The SC-CH4 estimates applied in this analysis were developed by Marten et al.
(2014) and are discussed in greater detail below.
A similar metric, the social cost of CO2 (SC-CCh), provides important context for
understanding the Marten et al. SC-CH4 estimates. Estimates of the SC-COi have been used by
the EPA and other federal agencies to value the impacts of CO2 emissions changes in benefit cost
analysis for GHG-related rulemakings since 2008. The SC-CCh is a metric that estimates the
monetary value of impacts associated with marginal changes in COi emissions in a given year.
Similar to the SC-CH4, it includes a wide range of anticipated climate impacts, such as net
changes in agricultural productivity, property damage from increased 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 CO2 emissions, or the disbenefit from increasing
emissions, in regulatory impact analyses.
The SC-CO2 estimates were developed over many years, using the best science available,
and with input from the public. Specifically, an interagency working group (IWG) that included
the EPA and other executive branch agencies and offices used three integrated assessment
models (lAMs) to develop the SC-CO2 estimates and recommended four global values for use in
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regulatory analyses. The SC-CCh 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, reference case socioeconomic and emission scenarios,
and equilibrium climate sensitivity distribution. Rather, improvements in the way damages are
modeled are confined to those that have been incorporated into the latest versions of the models
by the developers themselves and published in the peer-reviewed literature. The 2010 SC-COi
Technical Support Document (2010 SC-CCh TSD) provides a complete discussion of the
methods used to develop these estimates and the current SC-CCh TSD presents and discusses the
2013 update (including recent minor technical corrections to the estimates).26
The 2010 SC-CO2 TSD noted a number of limitations to the SC-COi analysis, including
the incomplete way in which the lAMs capture catastrophic and non-catastrophic impacts, their
incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of
damages to high temperatures, and assumptions regarding risk aversion. Currently lAMs do not
assign value to all of the important physical, ecological, and economic impacts of climate change
recognized in the climate change literature due to a lack of precise information on the nature of
damages and because the science incorporated into these models understandably lags behind the
most recent research. Nonetheless, these estimates and the discussion of their limitations
represent the best available information about the social benefits of COi reductions to inform
benefit-cost analysis. The new versions of the models offer some improvements in these areas,
although further work is warranted.
Accordingly, the EPA and other agencies continue to engage in research on modeling and
valuation of climate impacts with the goal to improve these estimates. The EPA and other
agencies also continue to consider feedback on the SC-COi estimates from stakeholders through
a range of channels, including public comments on Agency rulemakings that use the SC-COi in
supporting analyses and through regular interactions with stakeholders and research analysts
implementing the SC-COi methodology used by the IWG. In addition, OMB sought public
26 Both the 2010 SC-CO2 TSD and the current SC-CO2 TSD are available at:
https ://www. whitehouse. go v/omb/oira/social-cost-of-carbon
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comment on the approach used to develop the SC-CCh estimates through a separate comment
period that ended on February 26, 2014.27
After careful evaluation of the full range of comments, the IWG continues to recommend
the use of the SC-CCh estimates in regulatory impact analysis. 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-CCh estimates continue to reflect the best available
scientific and economic information on climate change.28 The NRC review will be informed by
the public comments received and focus on the technical merits and challenges of potential
approaches to improving the SC-COi estimates in future updates.
Concurrent with OMB's publication of the response to comments on SC-CCh and
announcement of the NRC process, OMB posted a revised TSD that includes two minor
technical corrections to the current estimates. One technical correction addressed an inadvertent
omission of climate change damages in the last year of analysis (2300) in one model and the
second addressed a minor indexing error in another model. On average the revised SC-CO2
estimates are one dollar less than the mean SC-CO2 estimates reported in the November 2013
TSD. The change in the estimates associated with the 95th percentile estimates when using a 3
percent discount rate is slightly larger, as those estimates are heavily influenced by the results
from the model that was affected by the indexing error.
The four SC-CO2 estimates are: $13, $45, $67, and $130 per metric ton of CO2 emissions
in the year 2020 (2012 dollars).29 The first three values are based on the average SC-COi from
the three lAMs, at discount rates of 5, 3, and 2.5 percent, respectively. Estimates of the SC-CO2
for several discount rates are included because the literature shows that the SC-COi is sensitive
to assumptions about the discount rate, and because no consensus exists on the appropriate rate
27 For the IWG's response to comments, see https://www. whitehouse.gov/sites/default/files/omb/inforeg/scc-
response-to-comments -Fmal-j uly-2015 .pdf.
28 See https://www.whitehouse.gov/blog/2015/07/02/estimating-benefits-carbon-dioxide-emissions-reductions.
29 The current version of the SC-COi TSD is available at:
-------
to use in an intergenerational context (where costs and benefits are incurred by different
generations). The fourth value is the 95th percentile of the SC-CCh across all three models at a 3
percent discount rate. It is included to represent higher-than-expected impacts from temperature
change further out in the tails of the SC-COi distribution. The SC-CCh increases over time
because future emissions are expected to produce larger incremental damages as economies grow
and physical and economic systems become more stressed in response to greater climate change.
A challenge particularly relevant to this proposal is that the IWG did not estimate the
social costs of non-COi GHG emissions at the time the SC-COi estimates were developed. One
alternative approach to value methane impacts is to use the global warming potential (GWP) to
convert the emissions to COi equivalents which are then valued using the SC-COi estimates.
The GWP measures the cumulative radiative forcing from a perturbation of a non-CCh
GHG relative to a perturbation of COi over a fixed time horizon, often 100 years. The GWP
mainly reflects differences in the radiative efficiency 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-CCh emissions compared to COi on a purely physical basis,
there are several well-documented limitations in using it to value non-CCh GHG benefits, as
discussed in the 2010 SC-CO2 TSD and previous rulemakings (e.g., U.S. EPA 2012b, 2012d).30
In particular, several recent studies found that GWP-weighted benefit estimates for methane are
likely to be lower than the estimates derived using directly modeled social cost estimates for
these gases. Gas comparison metrics, such as the GWP, are designed to measure the impact of
non-COi GHG emissions relative to CO2 at a specific point along the pathway from emissions to
monetized damages (depicted in Figure 4-1), and this point may differ across measures.
1 missions
Atmoiphpric
Concentration
Rddiativc
toting
_j»
Climate
impact*.
Environmental
arid Socio-
Eeonomie
Impacts
Wonpti/pd
Source: Marten et al. 2014
Figure 4-1 Path from GHG Emissions to Monetized Damages
1 See also Reilly and Richards, 1993; Schmalensee, 1993; Fankhauser, 1994; Marten and Newbold, 2012.
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The GWP is not ideally suited for use in benefit-cost analyses to approximate the social
cost of non-CO2 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-CCh takes into account the fact that marginal damages from
an increase in temperature are a function of existing 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 for that matter, and will
therefore be incorrectly allocated. For example, the economic impacts associated with increased
agricultural productivity due to higher atmospheric COi concentrations included in the SC-COi
would be incorrectly allocated to methane emissions with the GWP-based valuation approach.
Also of concern is the fact that the assumptions made in estimating the GWP are not
consistent with the assumptions underlying SC-COi estimates in general, and the SC-COi
estimates developed by the IWG more specifically. For example, the 100-year time horizon
usually used in estimating the GWP is less than the approximately 300-year horizon the IWG
used in developing the SC-COi estimates. The GWP approach also treats all impacts within the
time horizon equally, independent of the time at which they occur. This is inconsistent with the
role of discounting in economic analysis, which accounts for a basic preference for earlier over
later gains in utility and expectations regarding future levels of economic growth. In the case of
methane, which has a relatively short lifetime compared to COi, the temporal independence of
the GWP could lead the GWP approach to underestimate the SC-CFU with a larger downward
bias under higher discount rates (Marten and Newbold, 2012).3
31
The EPA sought public comments on the valuation of non-CCh GHG impacts in previous
rulemakings (e.g., U.S. EPA 2012b, 2012d). In general, the commenters strongly encouraged the
EPA to incorporate the monetized value of non-COi GHG impacts into the benefit cost analysis,
however they noted the challenges associated with the GWP-approach, as discussed above, and
encouraged the use of directly-modeled estimates of the SC-CFU to overcome those challenges.
31 We note that the truncation of the time period in the GWP calculation could lead to an overestimate of SC-CH4
for near term perturbation years when the SC-COi is based on a sufficiently low or steeply declining discount
rate.
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The EPA had cited several researchers that had directly estimated the social cost of non-
COi emissions using lAMs but noted that the number of such estimates was small compared to
the large number of SC-COi estimates available in the literature. The EPA found considerable
variation among these published estimates in terms of the models and input assumptions they
employ (U.S. EPA, 2012d). These studies differed in the emissions perturbation year, employed
a wide range of constant and variable discount rate specifications, and considered a range of
baseline socioeconomic and emissions scenarios that have been developed over the last 20 years.
Furthermore, at the time, none of the other published estimates of the social cost of non-CCh
GHG were consistent with the SC-CCh estimates developed by the IWG, and most were likely
underestimates due to changes in the underlying science since their publication.
Therefore, the EPA concluded that the GWP approach would serve as an interim method
of analysis until directly modeled social cost estimates for non-CCh GHGs, consistent with the
SC-CO2 estimates developed by the IWG, were developed. The EPA presented GWP-weighted
estimates in sensitivity analyses rather than the main benefit-cost analyses.32
Since then, a paper by Marten et al. (2014) provided the first set of published SC-CH4
estimates in the peer-reviewed literature that are consistent with the modeling assumptions
underlying the SC-CCh estimates.33 Specifically, the estimation approach of Marten et al. used
the same set of three lAMs, five socioeconomic and emissions scenarios, equilibrium climate
sensitivity distribution, three constant discount rates, and aggregation approach used by the IWG
to develop the SC-COi estimates. The aggregation method involved distilling the 45 distributions
of the SC-CH4 produced for each emissions year into four estimates: the mean across all models
and scenarios using a 2.5 percent, 3 percent, and 5 percent discount rate, and the 95th percentile
of the pooled estimates from all models and scenarios using a 3 percent discount rate. The
atmospheric lifetime and radiative efficacy of methane used by Marten et al. is based on the
32 For example, the 2012 New Source Performance Standards and Amendments to the National Emissions
Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry are expected to reduce methane
emissions by 900,000 metric tons annually, see http://www.gpo.gov/fdsys/pkg/FR-2012-08-16/pdf/2012-
16806.pdf. Additionally, the 2017-2025 Light-duty Vehicle Greenhouse Gas Emission Standards and Corporate
Average Fuel Economy Standards, promulgated jointly with the National Highway Traffic Safety
Administration, is expected to reduce methane emissions by over 100,000 metric tons in 2025 increasing to
nearly 500,000 metric tons in 2050, see http://www.gpo.gov/fdsys/pkg/FR-2012-10-15/pdf/2012-21972.pdf
33 Marten et al. (2014) also provided the first set of SC-NiO estimates that are consistent with the assumptions
underlying the SC-COi estimates.
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estimates reported by the IPCC in their Fourth Assessment Report (AR4, 2007), including an
adjustment in the radiative efficacy of methane to account for its role as a precursor for
tropospheric ozone and stratospheric water. These values represent the same ones used by the
IPCC in AR4 for calculating GWPs. At the time Marten et al. developed their estimates of the
SC-CH4, AR4 was the latest assessment report by the IPCC. The IPCC updates GWP estimates
with each new assessment, and in the most recent assessment, AR5, the latest estimate of the
methane GWP ranged from 28-36, compared to a GWP of 25 in AR4. The updated values reflect
a number of changes: changes in the lifetime and radiative efficiency estimates for COi, changes
in the lifetime estimate for methane, and changes in the correction factor applied to methane's
GWP to reflect the effect of methane emissions on other climatically important substances such
as tropospheric ozone and stratospheric water vapor. In addition, the range presented in the latest
IPCC report reflects different choices regarding whether to account for how biogenic and fossil
methane have different carbon cycle effects, and for whether to account for climate feedbacks on
the carbon cycle for both methane and CO2 (rather than just for CO2 as was done in AR4).34'35
Marten et al. (2014) discuss these estimates, (SC-CH4 estimates presented below in Table
4-3), and compare them with other recent estimates in the literature.36 The authors noted that a
direct comparison of their estimates with all of the other published estimates is difficult, given
the differences in the models and socioeconomic and emissions scenarios, but results from three
relatively recent studies offer a better basis for comparison (see Hope (2006), Marten and
Newbold (2012), Waldhoff et al. (2014)). Marten et al. found that in general the SC-CH4
estimates from their 2014 paper are higher than previous estimates. The higher SC-CH4 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-CH4 estimates are higher than the GWP-weighted
34 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.
35 Note that this proposal uses a GWP value for methane of 25 for COi equivalency calculations, consistent with
the GHG emissions inventories and the IPCC Fourth Assessment Report (AR4).
36 Marten et al (2014) estimates are presented in 2007 dollars. These estimates were adjusted for inflation using
National Income and Product Accounts Tables, Table 1.1.9, Implicit Price Deflators for Gross Domestic
Product (US Department of Commerce, Bureau of Economic Analysis),
http://www.bea.gov/iTable/index nipa.cfm (1.0804) Accessed 3/3/15.
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estimates. More detailed discussion of the SC-CH4 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-CH4), 2012 - 2050a [in 2012$ per metric ton]
(Source: Marten etal., 2014b)
Year
2012
2015
2020
2025
2030
2035
2040
2045
2050
5 Percent
Average
$430
$490
$580
$700
$820
$970
$1,100
$1,300
$1,400
3 Percent
Average
$1,000
$1,100
$1,300
$1,500
$1,700
$1,900
$2,200
$2,500
$2,700
SC-CH4
2.5 Percent
Average
$1,400
$1,500
$1,700
$1,900
$2,200
$2,500
$2,800
$3,000
$3,300
3 Percent
95th percentile
$2,800
$3,000
$3,500
$4,000
$4,500
$5,300
$5,900
$6,600
$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-COi estimates
described above. See Corrigendum to Marten et al. (2014) for more details
http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550.
The application of directly modeled estimates from Marten et al. (2014) to benefit-cost
analysis of a regulatory action is analogous to the use of the SC-COi estimates. Specifically, the
SC-CH4 estimates in Table 4-3 are used to monetize 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 result of the proposed regulatory action, are multiplied
by the SC-CH4 estimate for that year. To obtain a present value estimate, the monetized stream
of future non-COi benefits are discounted back to the analysis year using the same discount rate
used to estimate the social cost of the non-CCh GHG emission changes. In addition, the
limitations for the SC-CCh estimates discussed above likewise apply to the SC-CH4 estimates,
given the consistency in the methodology.
The EPA recently conducted a peer review of the application of the Marten et al. (2014)
non-COi social cost estimates in regulatory analysis and received responses that supported this
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application. Three reviewers considered seven charge questions that covered issues such as the
EPA's interpretation of the Marten et al. estimates, the consistency of the estimates with the SC-
COi estimates, the EPA's characterization of the limits of the GWP-approach to value non-COi
GHG impacts, and the appropriateness of using the Marten et al estimates in regulatory impact
analyses. The reviewers agreed with the EPA's interpretation of Marten et a/.'s estimates;
generally found the estimates to be consistent with the SC-CCh estimates; and concurred with the
limitations of the GWP approach, finding directly modeled estimates to be more appropriate.
While outside of the scope of the review, the reviewers briefly considered the limitations in the
SC-CO2 methodology (e.g., those discussed earlier in this section) and noted that because the
SC-CO2 and SC-CH4 methodologies are similar, the limitations also apply to the resulting SC-
CH4 estimates. Two of the reviewers concluded that use in RIAs of the SC-CH4 estimates
developed by Marten et al and published in the peer-reviewed literature is appropriate, provided
that the Agency discuss the limitations, similar to the discussion provided for SC-CCh and other
economic analyses. All three reviewers encouraged continued improvements in the SC-COi
estimates and suggested that as those improvements are realized they should also be reflected in
the SC-CH4 estimates, with one reviewer suggesting the SC-CH4 estimates lag this process. The
EPA supports continued improvement in the SC-CCh estimates developed by the U.S.
government and agrees that improvements in the SC-COi estimates should also be reflected in
the SC-CH4 estimates. The fact that the reviewers agree that the SC-CH4 estimates are generally
consistent with the SC-CCh estimates that are recommended by OMB's guidance on valuing COi
emissions reductions, leads the EPA to conclude that use of the SC-CH4 estimates is an
analytical improvement over excluding methane emissions from the monetized portion of the
benefit cost analysis.
In light of the favorable peer review and past comments urging the EPA to value non-
COi GHG impacts in its rulemakings, the Agency has used the Marten et al. (2014) SC-CH4
estimates to value methane impacts expected from this proposed rulemaking and has included
those benefits in the main benefits analysis. The EPA seeks comments on the use of these
directly modeled estimates, from the peer-reviewed literature, for the social cost of non-CCh
GHGs in this RIA.
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The methane benefits are presented below in Table 4-4 for years 2020 and 2025 across
regulatory options. Applying this approach to the methane reductions estimated for the proposed
NSPS option, the 2020 methane benefits vary by discount rate and range from about $88 million
to approximately $550 million; the mean SC-CH4 at the 3 percent discount rate results in an
estimate of about $200 to $210 million in 2020. The methane benefits increase for the proposed
option in 2025 and likewise vary by discount rate, ranging from about $220 million to
approximately $1.4 billion in that year; the mean SC-CH4 at the 3-percent discount rate results in
an estimate of about $460 to $550 million in 2025.
Table 4-4 Estimated Global Benefits of Methane Reductions* (in millions, 2012$)
Discount rate and
statistic
Million metric tonnes
of methane reduced
Million metric tonnes
of CO2 Eq.
5% (average)
3% (average)
2.5% (average)
3% (95th percentiie)
Option 1
2020
0.15
3.8
$89
$200
$260
$530
2025
0.31
7.7
$220
$470
$600
$1,200
Proposed Option 2
(Low)
2020
0.15
3.8
$88
$200
$260
$520
2025
0.31
7.7
$220
$460
$600
$1,200
Proposed Option 2
(High)
2020
0.16
4.0
$93
$210
$280
$550
2025
0.36
9.0
$250
$550
$700
$1,400
Option 3
2020
0.17
4.2
$99
$220
$290
$590
2025
0.43
11
$300
$640
$830
$1,700
*The SC-CH4 values are dollar-year and emissions-year specific. SC-CH4 values represent only a partial accounting
of climate impacts.
The vast majority of this proposal's climate-related benefits are associated with methane
reductions, but some climate-related impacts are expected from the proposal's secondary air
impacts. The secondary impacts are discussed in Section 4.7.
Methane is also a precursor to ozone. In remote areas, methane is a dominant precursor to
tropospheric ozone formation (U.S. EPA, 2013). Approximately 40 percent of the global annual
mean ozone increase since preindustrial times is believed to be due to anthropogenic methane
(HTAP, 2010). Projections of future emissions also indicate that methane is likely to be a key
contributor to ozone concentrations in the future (HTAP, 2010). Unlike NOx and VOCs, which
affect ozone concentrations regionally and at hourly time scales, methane emissions affect ozone
concentrations globally and on decadal time scales given methane's relatively long atmospheric
lifetime (HTAP, 2010). Reducing methane emissions, therefore, can reduce global background
ozone concentrations, human exposure to ozone, and the incidence of ozone-related health
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effects (West et al, 2006, Anenberg et al, 2009). These benefits are global and occur in both
urban and rural areas. Reductions in background ozone concentrations can also have benefits for
agriculture and ecosystems (UNEP/WMO, 2011). Studies show that controlling methane
emissions can reduce global ozone concentrations and climate change simultaneously, but
controlling other shorter-lived ozone precursors such as NOx, carbon monoxide, or non-methane
VOCs have larger local health benefits from greater reductions in local ozone concentrations
(West and Fiore, 2005; West et al., 2006; Fiore et al., 2008; Dentener et al., 2005; Shindell et al.,
2005, 2012; UNEP/WMO, 2011). The health, welfare, and climate effects associated with ozone
are described in the preceding sections. Without detailed air quality modeling, we are unable to
estimate the effect that reducing methane will have on ozone concentrations at particular
locations.
Recently, a paper was published in the peer-reviewed scientific literature that presented a
range of estimates of the monetized ozone-related mortality benefits of reducing methane
emissions (Sarofim et al. 2015). For example, under their base case assumptions using a 3%
discount rate, Sarofim et al. find global ozone-related mortality benefits of methane emissions
reductions to be $790 per tonne of methane in 2020, with 10.6%, or $80, of this amount resulting
from mortality reductions in the United States. The methodology used in this study is consistent
in some (but not all) aspects with the modeling underlying the SC-CO2 and SC-CH4 estimates
discussed above, and required a number of additional assumptions such as baseline mortality
rates and mortality response to ozone concentrations. The Sarofim et al. (2015) study may have
implications for this benefits analysis as it provides a potential approach to estimating the ozone
related mortality benefits resulting from the methane reductions expected from this proposed
rulemaking. The EPA requests comment on Sarofim et a/.'s approach to estimating the ozone
related mortality benefits of methane emissions reductions, including technical considerations in
applying their methodology to this regulatory impact analysis.
4.4 VOC as a PM2.5 precursor
This rulemaking would reduce emissions of VOC, which are a precursor to PlVb.5. Most
VOC emitted are oxidized to CO2 rather than to PM, but a portion of VOC emission contributes
to ambient PMi5 levels as organic carbon aerosols (U.S. EPA, 2009a). Therefore, reducing these
emissions would reduce PM2.5 formation, human exposure to PMi.5, and the incidence of PM2.5-
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related health effects. However, we have not quantified the PMi.s-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 (natural) contribution. Given that a
fraction of secondarily formed organic carbon aerosols is from anthropogenic VOC emissions
and the extremely small amount of VOC emissions from this sector relative to the entire VOC
inventory it is unlikely this sector has a large contribution to ambient secondary organic carbon
aerosols. Photochemical models typically estimate secondary organic carbon from anthropogenic
VOC emissions to be less than 0.1 |ig/m3.
Due to data limitations regarding potential locations of new and modified sources
affected by this rulemaking, we did not perform air quality modeling for this rule needed to
quantify the PMi.5 benefits associated with reducing VOC emissions. Due to the high degree of
variability in the responsiveness of PM2.5 formation to VOC emission reductions, we are unable
to estimate the effect that reducing VOC will have on ambient PMi.5 levels without air quality
modeling. However, we provide the discussion below for context regarding findings from
previous modeling.
4.4.1 PM2.5 health effects and valuation
Reducing VOC emissions would reduce PlVb.5 formation, human exposure, and the
incidence of PMi.s-related health effects. Reducing exposure to PlVb.5 is associated with
significant human health benefits, including avoiding mortality and respiratory morbidity.
Researchers have associated PM2.5- exposure with adverse health effects in numerous
lexicological, clinical and epidemiological studies (U.S. EPA, 2009a). When adequate data and
resources are available, the EPA generally quantifies several health effects associated with
exposure to PMi.5 (e.g., U.S. EPA (201 lg)). These health effects include premature mortality for
adults and infants; cardiovascular morbidity, such as heart attacks; respiratory morbidity, such as
asthma attacks and acute and chronic bronchitis; which result in hospital and ER visits, lost work
days, restricted activity days, and respiratory symptoms. Although the EPA has not quantified
these effects in previous benefits analyses, the scientific literature suggests that exposure to
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PM2.5 is also associated with adverse effects on birth weight, pre-term births, pulmonary
function, other cardiovascular effects, and other respiratory effects (U.S. EPA, 2009a).
When the EPA quantifies PMi.s-related benefits, the Agency assumes that all fine
particles, regardless of their chemical composition, are equally potent in causing premature
mortality because the scientific evidence is not yet sufficient to allow differentiation of effect
estimates by particle type (U.S. EPA, 2009a). Based on our review of the current body of
scientific literature, the EPA estimates PM-related premature mortality without applying an
assumed concentration threshold. This decision is supported by the data, which are quite
consistent in showing effects down to the lowest measured levels of PM2.5 in the underlying
epidemiology studies.
Previous studies have estimated the monetized benefits-per-ton of reducing VOC
emissions associated with the effect that those emissions have on ambient PMi.5 levels and the
health effects associated with PMi.5 exposure (Fann, Fulcher, and Hubbell, 2009), and these
estimates can provide useful context for this rulemaking. Using the estimates in Fann, Fulcher,
and Hubbell (2009), the monetized benefit-per-ton of reducing VOC emissions in nine urban
areas of the U.S. ranges from $560 in Seattle, WA to $5,700 in San Joaquin, CA, with a national
average of $2,400. These estimates assume a 50 percent reduction in VOC, the Laden et al.
(2006) mortality function (based on the Harvard Six Cities study, a large cohort epidemiology
study in the Eastern U.S., an analysis year of 2015, a 3 percent discount rate, and 2006$).
Additional benefit-per-ton estimates are available from this dataset using alternate assumptions
regarding the relationship between PM2.5 exposure and premature mortality from empirical
studies and supplied by experts (e.g., Pope et al, 2002; Laden et al, 2006; Roman et al, 2008).
The EPA generally presents a range of benefits estimates derived from the American Cancer
Society cohort (e.g., Pope et al, 2002; Krewski et al, 2009) to the Harvard Six Cities cohort
(e.g., Laden et al, 2006; Lepuele et al, 2012) because the studies are both well-designed and
extensively peer reviewed, and the EPA provides the benefit estimates 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 epidemiology studies and the range of the urban
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areas is $300 to $7,500 per ton of VOC reduced (2012$).37 Since these estimates were presented
in the 2012 Oil and Gas NSPS RIA (U.S. EPA, 2012b), we updated our methods to apply more
recent epidemiological studies for these cohorts (i.e., Krewski et al., 2009; Lepuele et al., 2012)
as well as additional updates to the morbidity studies and population data.38 Because these
updates would not lead to significant changes in the benefit-per-ton estimates for VOC, we have
not updated them here.
While these ranges of benefit-per-ton estimates provide useful context, the geographic
distribution of VOC 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 all sectors.
Coupled with the larger uncertainties about the relationship between VOC emissions and PM2.5,
these factors lead the EPA to conclude that the available VOC benefit per ton estimates are not
appropriate to calculate monetized benefits of this rule, even as a bounding exercise.
37 We also converted the estimates from Fann, Fulcher, and Hubbell (2009) to 2012$ and applied EPA's current
value of a statistical life (VSL) estimate. For more information regarding EPA's current VSL estimate, please
see Section 5.6.5.1 of the RIA for the PM NAAQS RIA (U.S. EPA, 2012c). EPA continues to work to update
its guidance on valuing mortality risk reductions.
38 For more information regarding these updates, please see Section 5.3 of the RIA for the final PM NAAQS (U.S.
EPA, 2012c).
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Table 4-5 Monetized Benefits-per-Ton Estimates for
Area
Atlanta
Chicago
Dallas
Denver
NYC/ Philadelphia
Phoenix
Salt Lake
San Joaquin
Seattle
National average
Pope et al.
(2002)
$660
$1,600
$320
$770
$2,300
$1,100
$1,400
$3,100
$300
$1,300
Laden et al.
(2006)
$1,600
$4,000
$790
$1,900
$5,600
$2,700
$3,300
$7,500
$730
$3,200
Expert
A
$1,700
$4,200
$830
$2,000
$5,900
$2,800
$3,500
$7,900
$770
$3,400
Expert
B
$1,300
$3,300
$650
$1,500
$4,600
$2,200
$2,700
$6,100
$570
$2,600
VOC based on Previous Modeling in 2015
Expert
C
$1,300
$3,200
$630
$1,500
$4,500
$2,100
$2,700
$6,000
$590
$2,600
Expert
D
$920
$2,300
$450
$1,100
$3,200
$1,500
$1,900
$4,300
$420
$1,800
Expert
E
$2,100
$5,300
$1,000
$2,400
$7,300
$3,500
$4,400
$9,700
$950
$4,200
Expert
F
$1,200
$3,000
$580
$1,400
$4,100
$2,000
$2,500
$5,500
$540
$2,300
Expert
G
$780
$1,900
$380
$910
$2,700
$1,300
$1,600
$3,600
$350
$1,500
Expert
H
$980
$2,400
$480
$1,100
$3,400
$1,600
$2,000
$4,500
$440
$1,900
(2012$)
Expert
I
$1,300
$3,200
$630
$1,500
$4,500
$2,100
$2,700
$6,000
$580
$2,500
Expert
J
$1,000
$2,600
$510
$1,200
$3,600
$1,700
$2,200
$4,900
$470
$2,100
Expert
K
$260
$640
$130
$300
$890
$420
$570
$1,400
$120
$520
Expert
L
$1,000
$2,500
$490
$910
$3,300
$1,600
$2,100
$4,600
$350
$1,900
* These estimates assumed a 50 percent reduction in VOC emissions, an analysis year of 2015, and a 3 percent discount rate. All estimates are rounded to two
significant digits. These estimates have been adjusted from Fann, Fulcher, and Hubbell (2009) to reflect a more recent currency year and the EPA's current
VSL estimate. However, these estimates have not been updated to reflect recent epidemiological studies for mortality studies, morbidity studies, or population
data. Using a discount rate of 7 percent, the benefit-per-ton estimates would be approximately 9 percent lower. Assuming a 75 percent reduction in VOC
emissions would increase the benefit-per-ton estimates by approximately 4 percent to 52 percent. Assuming a 25 percent reduction in VOC emissions would
decrease the benefit-per-ton estimates by 5 percent to 52 percent. The EPA generally presents a range of benefits estimates derived from the expert functions
from Roman et al. (2008) as a characterization of uncertainty.
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4.4.2 Organic PM welfare effects
According to the previous residual risk assessment for this sector (U.S. EPA, 2012a),
persistent and bioaccumulative HAP reported as emissions from oil and gas operations include
polycyclic organic matter (POM). POM defines a broad class of compounds that includes
polycyclic aromatic hydrocarbon compounds (PAHs). Several significant ecological effects are
associated with deposition of organic particles, including persistent organic pollutants, and PAHs
(U.S. EPA, 2009a). This summary is from section 6.6.1 of the 2012 PM NAAQS RIA (U.S.
EPA, 2012c).
PAHs can accumulate in sediments and bioaccumulate in freshwater, flora, and fauna.
The uptake of organics depends on the plant species, site of deposition, physical and chemical
properties of the organic compound and prevailing environmental conditions (U.S. EPA, 2009a).
PAHs can accumulate to high enough concentrations in some coastal environments to pose an
environmental health threat that includes cancer in fish populations, toxicity to organisms living
in the sediment and risks to those (e.g., migratory birds) that consume these organisms.
Atmospheric deposition of particles is thought to be the major source of PAHs to the sediments
of coastal areas of the U.S. Deposition of PM to surfaces in urban settings increases the metal
and organic component of storm water runoff. This atmospherically-associated pollutant burden
can then be toxic to aquatic biota. The contribution of atmospherically deposited PAHs to
aquatic food webs was demonstrated in high elevation mountain lakes 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 components (air, snow, water, sediment, lichen,
conifer needles, and fish) in eight core national parks. The study concluded that bioaccumulation
of semi-volatile organic compounds occurred throughout park ecosystems, an elevational
gradient in PM deposition exists with greater accumulation in higher altitude areas, and
contaminants accumulate in proximity to individual agriculture and industry sources, which is
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counter to the original working hypothesis that most of the contaminants would originate from
Eastern Europe and Asia.
4.4.3 Visibility Effects
Reducing secondary formation of PlVb.5 from VOC emissions would improve visibility
throughout the U.S. Fine particles with significant light-extinction efficiencies include sulfates,
nitrates, organic carbon, elemental carbon, and soil (Sisler, 1996). Suspended particles and gases
degrade visibility by scattering and absorbing light. Higher visibility impairment levels in the
East are due to generally higher concentrations of fine particles, particularly sulfates, and higher
average relative humidity levels. Visibility has direct significance to people's enjoyment of daily
activities and their overall sense of wellbeing. Good visibility increases the quality of life where
individuals live and work, and where they engage in recreational activities. Previous analyses
(U.S. EPA, 2006b; U.S. EPA, 201 la; U.S. EPA, 201 Ig; U.S. EPA, 2012c) show that visibility
benefits are a significant welfare benefit category. Without air quality modeling, we are unable to
estimate visibility related benefits, nor are we able to determine whether VOC emission
reductions would be likely to have a significant impact on visibility in urban areas or Class I
areas.
4.5 VOC as an Ozone Precursor
This rulemaking would reduce emissions of VOC, which are also precursors to secondary
formation of ozone. Ozone is not emitted directly into the air, but is created when its two primary
components, volatile organic compounds (VOC) and oxides of nitrogen (NOx), react in the
presence of sunlight. In urban areas, compounds representing all classes of VOC are important
for ozone formation, but biogenic VOC emitted from vegetation tend to be more important
compounds in non-urban vegetated areas (U.S. EPA, 2013). Therefore, reducing these emissions
would reduce ozone formation, human exposure to ozone, and the incidence of ozone-related
health effects. However, we have not quantified the ozone-related benefits in this analysis for
several reasons. First, previous rules have shown that the monetized benefits associated with
reducing ozone exposure are generally smaller than PM-related benefits, even when ozone is the
pollutant targeted for control (U.S. EPA, 2010a, 2014b). Second, the complex non-linear
chemistry of ozone formation introduces uncertainty to the development and application of a
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benefit-per-ton estimate, particularly for sectors with substantial new growth. Third, the impact
of reducing VOC emissions is spatially heterogeneous depending on local air chemistry. Urban
areas with a high population concentration are often VOC-limited, which means that ozone is
most effectively reduced by lowering VOC. Rural areas and downwind suburban areas are often
NOx-limited, which means that ozone concentrations are most effectively reduced by lowering
NOx emissions, rather than lowering emissions of VOC. Between these areas, ozone is relatively
insensitive to marginal changes in both NOx and VOC.
Due to data limitations regarding potential locations of new and modified sources
affected by this rulemaking, we did not perform air quality modeling for this rule needed to
quantify the ozone benefits associated with reducing VOC emissions. Due to the high degree of
variability in the responsiveness of ozone formation to VOC emission reductions and data
limitations regarding the location of new and modified well sites, we are unable to estimate the
effect that reducing VOC will have on ambient ozone concentrations without air quality
modeling.
4.5.1 Ozone health effects and valuation
Reducing ambient ozone concentrations is associated with significant human health
benefits, including mortality and respiratory morbidity (U.S. EPA, 2010a). Researchers have
associated ozone exposure with adverse health effects in numerous lexicological, clinical and
epidemiological studies (U.S. EPA, 2013). When adequate data and resources are available, the
EPA generally quantifies several health effects associated with exposure to ozone (e.g., U.S.
EPA, 2010a; U.S. EPA, 201 la). These health effects include respiratory morbidity such as
asthma attacks, hospital and emergency department visits, 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 and premature aging of the lungs.
In a recent EPA analysis, the EPA estimated that reducing 15,000 tons of VOC from
industrial boilers resulted in $3.6 to $15 million (2008$) of monetized benefits from reduced
ozone exposure (U.S. EPA, 201 lb).39 After updating the currency year to 2012$, this implies a
39 While EPA has estimated the ozone benefits for many scenarios, most of these scenarios also reduce NOx
emissions, which make it difficult to isolate the benefits attributable to VOC reductions.
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benefit-per-ton for ozone of $260 to $1,070 per ton of VOC reduced. Since EPA conducted the
analysis of industrial boilers, the EPA published the Integrated Science Assessment for Ozone
(U.S. EPA, 2013), the Health Risk and Exposure Assessment for Ozone (U.S. EPA, 2014a), and
the RIA for the proposed Ozone NAAQS (U.S. EPA, 2014b). Therefore, the ozone mortality
studies applied in the boiler analysis, while current at that time, do not reflect the most updated
literature available. The selection of ozone mortality studies used to estimate benefits in RIAs
was revisited in the RIA for the proposed Ozone NAAQS. Applying the more recent studies
would lead to benefit-per-ton estimates for ozone within the range shown here. While these
ranges of benefit-per-ton estimates provide useful context, the geographic distribution of VOC
emissions from the oil and gas sector are not consistent with emissions modeled in the boiler
analysis. Therefore, we do not believe that those estimates to provide useful estimates of 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 effects include those that damage or impair the
intended use of the plant or ecosystem. Such effects are considered adverse to the public welfare
and can include reduced growth and/or biomass production in sensitive trees, 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-lived 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) radiation. 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 regional and global climate change. Due to its short
atmospheric lifetime, tropospheric ozone concentrations exhibit large spatial and temporal
variability (U.S. EPA, 2009b). A recent United Nations Environment Programme (UNEP) study
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reports that the threefold increase in ground level ozone during the past 100 years makes it the
third most important contributor to human contributed climate change behind CO2 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 sources of outdoor origin across the U.S., we
see that emissions declined by approximately 42 percent since 1990. However, despite this
decline, the 2005 National-Scale Air Toxics Assessment (NATA) predicts that most Americans
are exposed to ambient concentrations of air toxics at levels that have the potential to cause
adverse health effects (U.S. EPA, 201 Id).40 The levels of air toxics to which people are exposed
vary depending on where they live and work and the kinds of activities in which they engage. In
order to identify and prioritize air toxics, emission source types and locations that are of greatest
potential concern, the EPA conducts the NATA.41 The most recent NATA was conducted for
calendar year 2005 and was released in March 2011. NATA includes four steps:
1) Compiling a national emissions inventory of air toxics emissions from outdoor sources
2) Estimating ambient concentrations of air toxics across the U.S. utilizing dispersion
models
3) Estimating population exposures across the U.S. utilizing exposure models
4) Characterizing potential public health risk due to inhalation of air toxics including both
cancer and noncancer effects
Based on the 2005 NATA, the EPA estimates that about 5 percent of census tracts
nationwide have increased cancer risks greater than 100 in a million. The average national cancer
risk is about 50 in a million. Nationwide, the key pollutants that contribute most to the overall
40 The 2005 NATA is available on the Internet at http://www.epa.gov/ttn/atw/nata2005/.
41 The NATA modeling framework has a number of limitations that prevent its use as the sole basis for setting
regulatory standards. These limitations and uncertainties are discussed on the 2005 NATA website. Even so,
this modeling framework is very useful in identifying air toxic pollutants and sources of greatest concern,
setting regulatory priorities, and informing the decision making process. U.S. EPA. (2011) 2005 National-Scale
Air Toxics Assessment, http://www.epa.gov/ttn/atw/nata2005/
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cancer risks are formaldehyde and benzene.42'43 Secondary formation (e.g., formaldehyde
forming from other emitted pollutants) was the largest contributor to cancer risks, while
stationary, mobile and background sources contribute almost equal portions of the remaining
cancer risk.
Noncancer health effects can result from chronic,44 subchronic,45 or acute46 inhalation
exposure to air toxics, and include neurological, cardiovascular, liver, kidney, and respiratory
effects as well as effects on the immune and reproductive systems. According to the 2005
NATA, about three-fourths of the U.S. population was exposed to an average chronic
concentration of air toxics that has the potential for adverse noncancer respiratory health effects.
Results from the 2005 NATA indicate that acrolein is the primary driver for noncancer
respiratory risk.
Figure 4-2 and Figure 4-3 depict the 2005 NATA estimated census tract-level
carcinogenic risk and noncancer respiratory hazard from the assessment. It is important to note
that large reductions in HAP emissions may not necessarily translate into significant reductions
in health risk because toxicity varies by pollutant, and exposures may or may not exceed levels
of concern. For example, acetaldehyde mass emissions were more than double acrolein
emissions on a national basis in the EPA's 2005 National Emissions Inventory (NEI). However,
the Integrated Risk Information System (IRIS) reference concentration (RfC) for acrolein is
considerably lower than that for acetaldehyde, suggesting that acrolein could be potentially more
42 Details on EPA's approach to characterization of cancer risks and uncertainties associated with the 2005 NATA
risk estimates can be found at http://www.epa.gov/ttn/atw/natal999/riskbg.htmltZ2.
43 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 qualitative (e.g., quality of data, review of emission
inventories) judgments can be found at http://www.epa.gov/ttn/atw/nata/roy/pagel6.html.
44 Chronic exposure is defined in the glossary of the Integrated Risk Information System (IRIS) database
(http://www.epa.gov/iris) as repeated exposure by 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).
45 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).
46 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.
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toxic than acetaldehyde.47 Thus, it is important to account for the toxicity and exposure, as well
as the mass of the targeted emissions.
*•
Cancer Risk
(in a million)
1 -25
[ 25-50
| 50-75
(75-100
| > 100
Zero Population Tracts
Figure 4-2 2005 NATA Model Estimated Census Tract Carcinogenic Risk from HAP
Exposure from All Outdoor Sources based on the 2005 National Toxics Inventory
47 Details on the derivation of IRIS values and available supporting documentation for individual chemicals (as
well as chemical values comparisons) can be found at http://cfpub.epa.gov/ncea/iris/conipare.cfm.
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Total Respiratory
Hazard Index
o-1
1-5
^H 5-10
H 10-15
j^H 15-20
^B >20
Zero Population Tracts
Figure 4-3 2005 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk
from HAP Exposure from All Outdoor Sources based on the 2005 National Toxics
Inventory
Due to methodology and data limitations, we were unable to estimate the benefits
associated with the hazardous air pollutants that would be reduced as a result of this rule. In a
few previous analyses of the benefits of reductions in HAP, the EPA has quantified the benefits
of potential reductions in the incidences of cancer and noncancer risk (e.g., U.S. EPA, 1995). In
those analyses, EPA relied on unit risk factors (URF) and reference concentrations (RfC)
developed through risk assessment procedures. The URF is a quantitative estimate of the
carcinogenic potency of a pollutant, often expressed as the probability of contracting cancer from
a 70-year lifetime continuous exposure to a concentration of one |^g/m3 of a pollutant. These
URFs are designed to be conservative, and as such, are more likely to represent the high end of
the distribution of risk rather than a best or most likely estimate of risk. An RfC is an estimate
(with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure
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to the human population (including sensitive subgroups) that is likely 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 occur from a reduction in pollution, use
of high-end, conservative risk estimates would overestimate the benefits of the regulation. While
we used high-end risk estimates in past analyses, advice from the EPA's Science Advisory Board
(SAB) recommended that we avoid using high-end estimates in benefit analyses (U.S. EPA-
SAB, 2002). Since this time, the EPA has continued to develop better methods for analyzing the
benefits of reductions in HAP.
As part of the second prospective analysis of the benefits and costs of the Clean Air Act
(U.S. EPA, 201 la), the EPA conducted a case study analysis of the health effects associated with
reducing exposure to benzene in Houston from implementation of the Clean Air Act (lEc, 2009).
While reviewing the draft report, the EPA's Advisory Council on Clean Air Compliance
Analysis concluded that "the challenges for assessing progress in health improvement as a result
of reductions in emissions of hazardous air pollutants (HAP) are daunting...due to a lack of
exposure-response functions, uncertainties in emissions inventories and background levels, the
difficulty of extrapolating risk 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, the EPA convened a workshop to address the inherent complexities, limitations,
and uncertainties in current methods to quantify the benefits of reducing HAP.
Recommendations from this workshop included identifying research priorities, focusing on
susceptible and vulnerable populations, and improving dose-response relationships (Gwinn et al,
2011).
In summary, monetization of the benefits of reductions in cancer incidences requires
several important inputs, including central estimates of cancer risks, estimates of exposure to
carcinogenic HAP, and estimates of the value of an avoided case of cancer (fatal and non-fatal).
Due to methodology and data limitations, we did not attempt to monetize the health benefits of
reductions in HAP in this analysis. Instead, we provide a qualitative analysis of the health effects
associated with the HAP anticipated to be reduced by this rule. The EPA remains committed to
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improving methods for estimating HAP benefits by continuing to explore additional concepts of
benefits, including changes in the distribution of risk.
Available emissions data show that several different HAP are emitted from oil and
natural gas operations, either from equipment leaks, processing, compressing, transmission and
distribution, or storage tanks. Emissions of eight HAP make up a large percentage of the total
HAP emissions by mass from the oil and gas sector: toluene, hexane, benzene, xylenes (mixed),
ethylene glycol, methanol, ethyl benzene, and 2,2,4-trimethylpentane (U.S. EPA, 2012a). In the
subsequent sections, we describe the health effects associated with the main HAP of concern
from the oil and natural gas sector: benzene, toluene, carbonyl sulfide, ethyl benzene, mixed
xylenes, and n-hexane. This rule is anticipated to avoid or reduce 2,500 tons of HAP in 2025.
With the data available, it was not possible to estimate the tons of each individual HAP that
would be reduced.
4.6.1 Benzene
The EPA's IRIS database lists benzene as a known human carcinogen (causing leukemia)
by all routes of exposure, and concludes that exposure is associated with additional health
effects, including genetic changes in both humans and animals and increased proliferation of
bone marrow cells in mice.48'49'50 The EPA states in its IRIS database that data indicate a causal
relationship between benzene exposure and acute lymphocytic leukemia and suggest a
relationship between benzene exposure and chronic non-lymphocytic leukemia and chronic
lymphocytic leukemia. The International Agency for Research on Carcinogens (IARC) has
determined that benzene is a human carcinogen and the U.S. Department of Health and Human
48 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene.
Research and Development, National Center for Environmental Assessment, Washington, DC. This material is
available electronically at: http://www.epa.gov/iris/subst/0276.htm.
49 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 Agency for Research
on Cancer, World Health Organization, Lyon, France, p. 345-389, 1982.
50 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, V.A. (1992) Synergistic action of the benzene metabolite
hydroquinone on myelopoietic stimulating activity of granulocyte/macrophage colony-stimulating factor in
vitro, Proc. Natl. Acad. Sci. 89:3691-3695.
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Services has characterized benzene as a known human carcinogen.51'52 A number of adverse
noncancer health effects including blood disorders, such as preleukemia and aplastic anemia,
have also been associated with long-term exposure to benzene.53-54 The most sensitive noncancer
effect observed in humans, based on current data, is the depression of the absolute lymphocyte
count in blood.55-56 In addition, recent work, including studies sponsored by the Health Effects
Institute (HEI), provides evidence that biochemical responses are occurring at lower levels of
benzene exposure than previously known.57'58'59-60 The EPA's IRIS program has not yet evaluated
these new data.
4.6.2 Toluene61
Under the 2005 Guidelines for Carcinogen Risk Assessment, there is inadequate
information to assess the carcinogenic potential of toluene because studies of humans chronically
exposed to toluene are inconclusive, toluene was not carcinogenic in adequate inhalation cancer
51 International Agency for Research on Cancer (IARC). 1987. Monographs on the evaluation of carcinogenic risk
of chemicals to humans, Volume 29, Supplement 7, Some industrial chemicals and dyestuffs, World Health
Organization, Lyon, France.
52 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens
available at: http://ntp.niehs.nih.gov/go/16183.
53 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197.
54 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541-554.
55Rothman, N., G.L. Li, M. Dosemeci, W.E. Bechtold, G.E. Marti, Y.Z. Wang, M. Linet, L.Q. Xi, W. Lu, M.T.
Smith, N. Titenko-Holland, L.P. Zhang, W. Blot, S.N. Yin, and R.B. Hayes (1996) Hematotoxicity among
Chinese workers heavily exposed to benzene. Am. J. Ind. Med. 29: 236-246.
56 U.S. Environmental Protection Agency (U.S. EPA). 2000. Integrated Risk Information System File for Benzene
(Noncancer Effects). Research and Development, National Center for Environmental Assessment, Washington,
DC. This material is available electronically at: http://www.epa.gov/iris/subst/0276.htm.
57 Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; Cohen, B.; Melikian, A.; Eastmond, D.; Rappaport, S.; Li, H.;
Rupa, D.; Suramaya, R.; Songnian, W.; Huifant, Y.; Meng, M.; Winnik, M.; Kwok, E.; Li, Y.; Mu, R.; Xu, B.;
Zhang, X.; Li, K. (2003). HEI Report 115, Validation & Evaluation of Biomarkers in Workers Exposed to
Benzene in China.
58 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.
59Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels
of Benzene. Science 306: 1774-1776.
60 Turtletaub, K.W. and Mani, C. (2003). Benzene metabolism in rodents at doses relevant to human exposure from
Urban Air. Research Reports Health Effect Inst. Report No. 113.
61 All health effects language for this section came from: U.S. EPA. 2005. "Full IRIS Summary for Toluene
(CASRN 108-88-3)" Environmental Protection Agency, Integrated Risk Information System (IRIS), Office of
Health and Environmental Assessment, Environmental Criteria and Assessment Office, Cincinnati, OH.
Available on the Internet at .
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bioassays of rats and mice exposed for life, and increased incidences of mammary cancer and
leukemia were reported in a lifetime rat oral bioassay.
The central nervous system (CNS) is the primary target for toluene toxicity in both
humans and animals for acute and chronic exposures. CNS dysfunction (which is often
reversible) and narcosis have been frequently observed in humans acutely exposed to low or
moderate levels of toluene by inhalation: symptoms include fatigue, sleepiness, headaches, and
nausea. Central nervous system depression has been reported to occur in chronic abusers exposed
to high levels of toluene. Symptoms include ataxia, tremors, cerebral atrophy, nystagmus
(involuntary eye movements), and impaired speech, hearing, and vision. Chronic inhalation
exposure of humans to toluene also causes irritation of the upper respiratory tract, eye irritation,
dizziness, headaches, and difficulty with sleep.
Human studies have also reported developmental effects, such as CNS dysfunction,
attention deficits, and minor craniofacial and limb anomalies, in the children of women who
abused toluene during pregnancy. A substantial database examining the effects of toluene in
subchronic and chronic occupationally exposed humans exists. The weight of evidence from
these studies indicates neurological effects (i.e., impaired color vision, impaired hearing,
decreased performance in neurobehavioral analysis, changes in motor and sensory nerve
conduction velocity, headache, and dizziness) as the most sensitive endpoint.
4.6.3 Carbonyl sulfide
Limited information is available on the health effects of carbonyl sulfide. Acute (short-
term) inhalation of high concentrations of carbonyl sulfide may cause narcotic effects and irritate
the eyes and skin in humans.62 No information is available on the chronic (long-term),
reproductive, developmental, or carcinogenic effects of carbonyl sulfide in humans. Carbonyl
62 Hazardous Substances Data Bank (HSDB), online database). US National Library of Medicine, Toxicology Data
Network, available online at http://toxnet.nlm.nih.gov/. Carbonyl health effects summary available at
http://toxnet.nlm. nih.gov/cgi-bin/sis/search/r?dbs+hsdb:@term+@rn+@rel+463-58-l.
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sulfide has not undergone a complete evaluation and determination under the EPA's IRIS
program for evidence of human carcinogenic potential.63
4.6.4 Ethylbenzene
Ethylbenzene is a major industrial chemical produced by alkylation of benzene. The pure
chemical is used almost exclusively for styrene production. It is also a constituent of crude
petroleum and is found in gasoline and diesel fuels. Acute (short-term) exposure to ethylbenzene
in humans results in respiratory effects such as throat irritation and chest constriction, and
irritation of the eyes, and neurological effects such as dizziness. Chronic (long-term) exposure of
humans to ethylbenzene may cause eye and lung irritation, with possible adverse effects on the
blood. Animal studies have reported effects on the blood, liver, and kidneys and endocrine
system from chronic inhalation exposure to ethylbenzene. No information is available on the
developmental or reproductive effects of ethylbenzene in humans, but animal studies have
reported developmental effects, including birth defects in animals exposed via inhalation. Studies
in rodents reported increases in the percentage of animals with tumors of the nasal and oral
cavities in male and female rats exposed to ethylbenzene via the oral route.64'65 The reports of
these studies lacked detailed information on the incidence 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 Research on Cancer (IARC, 2000) and
the National Toxicology Program (NTP).66'67 The NTP (1999) carried out a chronic inhalation
bioassay in mice and rats and found clear evidence of carcinogenic activity in male rats and some
evidence in female rats, based on increased incidences of renal tubule adenoma or carcinoma in
63 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.
64 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.
65 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 AcadSci 837:15-52.
66 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.
67 National Toxicology Program (NTP), 1999. Toxicology and Carcinogenesis Studies of Ethylbenzene (CAS No.
100-41-4) in F344/N Rats and in B6C3F1 Mice (Inhalation Studies). Technical Report Series No. 466. NIH
Publication No. 99-3956. U.S. Department of Health and Human Services, Public Health Service, National
Institutes of Health. NTP, Research Triangle Park, NC.
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male rats and renal tubule adenoma in females. NTP (1999) also noted increases in the incidence
of testicular adenoma in male rats. Increased incidences of lung alveolar/bronchiolar adenoma or
carcinoma were observed in male mice and liver hepatocellular adenoma or carcinoma in female
mice, which provided some evidence of carcinogenic activity in male and female mice (NTP,
1999). IARC (2000) classified ethylbenzene as Group 2B, possibly carcinogenic to humans,
based on the NTP studies.
4.6.5 Mixed xylenes
Short-term inhalation of mixed xylenes (a mixture of three closely-related compounds) in
humans may cause irritation of the nose and throat, nausea, vomiting, gastric irritation, mild
transient eye irritation, and neurological effects.68 Other reported effects include labored
breathing, heart palpitation, impaired function of the lungs, and possible effects in the liver and
kidneys.69 Long-term inhalation exposure to xylenes in humans has been associated with a
number of effects in the nervous system including headaches, dizziness, fatigue, tremors, and
impaired motor coordination.70 The EPA has classified mixed xylenes in Category D, not
classifiable with respect to human carcinogenicity.
4.6.6 n-Hexane
The studies available in both humans and animals indicate that the nervous system is the
primary target of toxicity upon exposure of n-hexane via inhalation. There are no data in humans
and very limited information in animals about the potential effects of n-hexane via the oral route.
Acute (short-term) inhalation exposure of humans to high levels of hexane causes mild central
nervous system effects, including dizziness, giddiness, slight nausea, and headache. Chronic
(long-term) exposure to hexane in air causes numbness in the extremities, muscular weakness,
blurred vision, headache, and fatigue. Inhalation studies in rodents have reported behavioral
68 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.
69 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is
available electronically at http://www.atsdr.cdc.gov/ToxProfiles/TP.asp?id=296&tid=53.
70 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is
available electronically at http://www.atsdr.cdc.gov/ToxProfiles/TP.asp?id=296&tid=53.
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effects, neurophysiological changes and neuropathological effects upon inhalation exposure to n-
hexane. Under the Guidelines for Carcinogen Risk Assessment (U.S. EPA, 2005), the database
for n-hexane is considered inadequate to assess human carcinogenic potential, therefore the EPA
has classified hexane in Group D, not classifiable as to human carcinogenicity.71
4.6.7 Other Air Toxics
In addition to the compounds described above, other toxic compounds might be affected
by this rule, including hydrogen sulfide (HiS). Information regarding the health effects of those
compounds can be found in the EPA's IRIS database.72
4.7 Secondary Air Emissions Impacts
The control techniques to meet the standards are associated with several types of secondary
emissions impacts, which may partially offset the direct 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.
71 U.S. EPA. 2005. Guidelines for Carcinogen Risk Assessment. EPA/630/P-03/001B. Risk Assessment Forum,
Washington, DC. March. Available on the Internet at .
72U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris
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Table 4-6 Secondary Air Pollutant Impacts (short tons per year)
Emissions Category
Total Hydraulically Fractured and Re-
fractured Oil Well Completions
Fugitive Emissions
Pneumatic Pumps
Pneumatic Controllers
Compressors
Total 2020
Emissions Category
Total Hydraulically Fractured and Re-
fractured Oil Well Completions
Fugitive Emissions
Pneumatic Pumps
Pneumatic Controllers
Compressors
Total in 2025
CO2
580,000
minimal
24,000
0
550
610,000
CO2
610,000
minimal
140,000
0
3,300
750,000
NOx
300
minimal
12
0
0
310
NOx
310
minimal
72
0
2
380
2020
PM
10
minimal
0
0
0
10
2025
PM
11
minimal
0
0
0
11
CO
1,600
minimal
66
0
2
1,700
CO
1,700
minimal
400
0
9
2,100
THC
620
minimal
25
0
1
640
THC
640
minimal
150
0
3
790
The secondary emision impacts for regulatory options are equal across the options. This
result holds because the only requirements varied across the options is the coverage (low and
high impact cases of the proposed Option 2) or frequency (Moving from Option 1 to Option 3
increases the frequency of survey and repair under the fugitive emissions requirement) and
secondary emissions from the fugitive emissions requirements are expected to be minimal. We
are not estimating the monetized disbenefits of the secondary emissions of COi because much of
the methane that would have been released in the absence of the flare would have eventually
oxidized into COi in the atmosphere. Note that the COi produced from the methane oxidizing in
the atmosphere is not included in the calculation of the SC-CH4.
However, the EPA does recognize that because the growth rate of the SC-CO2 estimates
are lower than their associated discount rates, the estimated impact of CO2 produced in the future
from oxidized methane would be less than the estimated impact of CO2 released immediately
from flaring, which would imply a small disbenefit associated with flaring. Assuming an average
methane oxidation period of 8.7 years, consistent with the lifetime used in IPCC AR4, the
disbenefits associated with destroying one metric ton of methane and releasing the CO2
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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 CH4 depending on the SC-CCh value or 0.7 percent to
0.9 percent of the SC-CH4 estimates per metric ton for 2020. The analogous estimates for 2025
are $7 to $34 per metric ton CH4 or 0.8 percent to 1.0 percent of the SC-CH4 estimates per metric
ton for 2025.73 While the EPA is not accounting for the CO2 disbenefits at this time, we request
comment on the appropriateness of the monetization of such impacts using the SC-CCh and
aspects of the calculation.
Table 4-7 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 ambient air quality, which would reduce potency of
greenhouse gas emissions, reduce exposure to various harmful pollutants, improve visibility
impairment, and reduce vegetation damage.
Table 4-7 Summary of Emissions Changes (short tons per year, except where noted)
Option 1
Change in
Direct
Emissions
Change in
Secondary
Emissions
Net
Change in
CO2 Eq.
Emissions
Pollutant
Methane
VOC
HAP
CO2
NOx
PM
CO
THC
CO2Eq.
(million
short tons)
CO2Eq.
(million
metric tons)
2020
170,000
120,000
310
610,000
310
10
1,700
640
4.2
3.8
2025
340,000
170,000
1,900
750,000
380
11
2,100
790
8.5
7.7
Proposed
Option 2 (Low)
2020
170,000
120,000
310
610,000
310
10
1,700
640
4.2
3.8
2025
340,000
170,000
1,900
750,000
380
11
2,100
790
8.5
7.7
Proposed
Option 2 (High)
2020
180,000
120,000
400
610,000
310
10
1,700
640
4.4
4.0
2025
400,000
180,000
2,500
750,000
380
11
2,100
790
9.9
9.0
Option 3
2020
190,000
130,000
510
610,000
310
10
1,700
640
4.7
4.2
2025
470,000
200,000
3,200
750,000
380
11
2,100
790
12
11
Note: Totals may not sum due to independent rounding.
73 To calculate the disbenefits associated the complete destruction of a ton of CH4 through flaring, EPA took the
difference between the SC-CO2 at the time of the flaring and in 8.7 years and discounted that value to the time
of the flaring using the same discount rate as used to estimate the SC-CO2. This value was then scaled by 44/16
to account for the relative mass of carbon contained in a ton of CH4 versus a ton of CO2. The value of the SC-
CO2 8.7 years after flaring was estimated by linearly interpolating between the annual SC-CO2 estimates
reported in the TSD and inflated to 2012 dollars.
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Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry. Office of
Air Quality Planning and Standards, Health and Environmental Impacts Division. April.
. Accessed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 2012c. Regulatory Impact Analysis for the
Final Revisions to the National Ambient Air Quality Standards for Paniculate Matter.
EPA-452/R-12-003. Office of Air Quality Planning and Standards, Health and
Environmental Impacts Division. December. Available at:
.
Accessed March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 2012d. Regulatory Impact Analysis: Final
Rulemaking for 2017-2025 Light-Duty Vehicle Greenhouse Gas Emission Standards and
Corporate Average Fuel Economy Standards. EPA-420-R-12-016. Office of
Transportation and Air Quality, Assessment and Standards Division. August.
. Accessed March 30,
2015.
U.S. Environmental Protection Agency (U.S. EPA). 2013. Integrated Science Assessment of
Ozone and Related Photochemical Oxidants (Final Report). U.S. Environmental
Protection Agency, Washington, DC, EPA/600/R-10/076F. February.
. Accessed
March 30, 2015.
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U.S. Environmental Protection Agency (U.S. EPA). 2014a. Health Risk and Exposure
Assessment for Ozone (Final Report). U.S. Environmental Protection Agency, Research
Triangle Park, NC, EPA-452/R-14-004a. August.
. Accessed
March 30, 2015.
U.S. Environmental Protection Agency (U.S. EPA). 2014b. Regulatory Impact Analysis for the
Proposed Ozone NAAQS. U.S. Environmental Protection Agency, Research Triangle
Park, NC, EPA-452/P-14-006. December.
. Accessed March 30,
2015.
U.S. Environmental Protection Agency (U.S. EPA). 2014c. Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2012. EPA/430-R-14-003. April. <
http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/2014.html>.
Accessed April 3, 2015.
U.S. Environmental Protection Agency—Science Advisory Board (U.S. EPA-SAB). 2002.
Workshop on the Benefits of Reductions in Exposure to Hazardous Air Pollutants:
Developing Best Estimates of Dose-Response Functions An SAB Workshop Report of an
EPA/SAB Workshop (Final Report). EPA-SAB-EC-WKSHP-02-001. January.
. Accessed March 30, 2015.
U.S. Environmental Protection Agency—Science Advisory Board (U.S. EPA-SAB). 2008.
Benefits of Reducing Benzene Emissions in Houston, 1990-2020. EPA-COUNCIL-08-
001. July.
. Accessed March 30, 2015.
Waldhoff, S., D. Anthoff, S. Rose, R.S.J. Tol. 2014. "The Marginal Damage Costs of Different
Greenhouse Gases: An Application of FUND." The Open-Access, Open Assessment E-
Journal. 8(31): 1-33. http://dx.doi.org/10.5018/economics-ejournal.ja.2014-31. Accessed
April 3, 2014.
West et al. 2006. "Global health benefits of mitigating ozone pollution with methane emission
controls." Proceedings of the National Academy of Sciences 103(11):3988-3993.
West, J.J., A.M. Fiore. 2005. "Management of tropospheric ozone by reducing methane
emissions." Environmental Science & Technology 39:4685-4691.
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5 STATUTORY AND EXECUTIVE ORDER REVIEWS
5.1 Executive Order 12866, Regulatory Planning and Review and Executive Order
13563, Improving Regulation and Regulatory Review
Under section 3(f)(l) Executive Order 12866 (58 FR 51735, October 4, 1993), this action
is an "economically significant regulatory action" because it is likely to have an annual effect on
the economy of $100 million or more. Accordingly, 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 Office of Management and Budget (OMB) has previously approved the information
collection activities contained in 40 CFR part 60, subpart OOOO under the PRA and has
assigned OMB control number 2060-0673 and ICR number 2437.01; a summary can be found at
77 F.R. 49537. The information collection requirements in today's proposed rule titled,
Standards of Performance for Crude Oil and Natural Gas Facilities for Construction,
Modification, or Reconstruction (40 CFR part 60 subpart OOOOa) have been submitted for
approval to the OMB under the PRA. The ICR document prepared by the EPA has been assigned
EPA ICR Number 2523.01. You can find a copy of the ICR in the docket for this rule, and is
briefly summarized below.
The information to be collected for the proposed NSPS is based on notification,
performance tests, recordkeeping and reporting requirements which will be mandatory for all
operators subject to the final standards. Recordkeeping and reporting requirements are
specifically authorized by section 114 of the CAA (42 U.S.C. 7414). The information will be
used by the delegated authority (state agency, or Regional Administrator if there is no delegated
state agency) to ensure that the standards and other requirements are being achieved. Based on
review of the recorded information at the site and the reported information, the delegated
permitting authority can identify facilities that may not be in compliance and decide which
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facilities, records, or processes may need inspection. 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.
Potential respondents under subpart OOOOa are owners or operators of new, modified or
reconstructed oil and natural gas affected facilities as defined under the rule. None of the
facilities in the United States are owned or operated by state, local, tribal or the Federal
government. All facilities are privately owned for-profit businesses. The requirements in this
action result in industry recording keeping and reporting burden associated with review of the
requirements for all affected entities, gathering relevant information, performing initial
performance tests and repeat performance tests if necessary, writing and submitting the
notifications and reports, developing systems for the purpose of processing and maintaining
information, and train personnel to be able to respond to the collection of information.
The estimated average annual burden (averaged over the first 3 years after the effective
date of the standards) for the recordkeeping and reporting requirements in subpart OOOOa for
the 2,552 owners and operators that are subject to the rule is 92,658 labor hours, with an annual
average cost of $3,163,699. The annual public reporting and recordkeeping burden for this
collection of information is estimated to average 3.9 hours per response. Respondents must
monitor all specified criteria at each affected facility and maintain these records for 5 years.
Burden is defined at 5 CFR 1320.3(b).
5.3 Regulatory Flexibility Act (RFA)
The RFA generally requires an agency to prepare a regulatory flexibility analysis of any
rule subject to notice and comment rulemaking requirements under the Administrative Procedure
Act or any other statute unless the agency certifies that the rule will not have a significant
economic impact on a substantial number of small entities. Small entities include small
businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this rule on small entities, a small entity is
defined as: (1) A small business in the oil or natural gas industry whose parent company has no
more than 500 employees (or revenues of less than $7 million for firms that transport natural gas
5-2
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via pipeline); (2) a small governmental jurisdiction that is a government of a city, county, town,
school district, or special district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is independently owned and operated and
is not dominant in its field.
Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory flexibility
analysis (IRFA) that examines the impact of the proposed rule on small entities along with
regulatory alternatives that could minimize that impact. The complete IRFA is available for
review in the docket and is summarized here.
The IRFA describes the reason why the proposed rule is being considered and describes
the objectives and legal basis of the proposed rule, as well as discusses related rules affecting the
oil and natural gas sector. The IRFA describes the EPA's examination of small entity effects
prior to proposing a regulatory option and provides information about steps taken to minimize
significant impacts on small entities while achieving the objectives of the rule.
The EPA also summarized the potential regulatory cost impacts of the proposed rule and
alternatives in Section 3 of this RIA. The analysis in the IRFA drew upon the same analysis and
assumptions as the analyses presented in RIA. The IRFA analysis is presented in its entirely in
Section 7.3 of the RIA.
Identifying impacts on specific entities is challenging because of the difficulty of
predicting potentially affected new or modified sources at the firm level. To identify potentially
affected entities under the proposed NSPS, the EPA combined information from industry
databases to identify firms drilling and completing wells in 2012, as well as identified their oil
and natural gas production levels for that year.
The EPA based the analysis in the IRFA on impacts estimates for the proposed
requirements for hydraulically fractured and re-fractured oil well completions and well site
fugitive emissions While the IRFA does not incorporate potential impacts from other provisions
of the proposed NSPS, the completions and fugitive emissions provisions represent a large
majority of the estimated compliance costs of the proposed NSPS in 2020 and 2025. Note
incorporating impacts from other provisions in this analysis is a limitation and underestimates
impacts, but the EPA believes that detailed analysis of the two provisions impacts on small
entities is illustrative of impacts on small entities from the proposed rule in its entirety.
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We projected the 2012 base year estimates of incrementally affected facilities to 2020
and 2025 levels based on the same growth rates used to project future activities as described in
the TSD and consistent with other analyses in this RIA. This approach assumes that no other
firms perform potentially affected activities and firms performing oil and natural gas activities in
2012 will continue to do so in 2020 and 2025. While likely true for many firms, this will not be
the case for all firms.
For some firms, we estimated their 2012 sales levels by multiplying 2012 oil and natural
gas production levels reported in an industry database by assumed oil and natural gas prices at
the wellhead. For natural gas, we assumed the $4/Mcf for natural gas. For oil prices, we
estimated revenues using two alternative prices, $70/bbl and $50/bbl. In the results, we call the
case using $70/bbl the "primary scenario" and the case using the $50/bbl as the "low oil price
scenario".
For projected 2020 and 2025 potentially affected activities, we allocated compliance
costs across entities based upon the costs estimated in the TSD and used in the RIA. The RIA
and IRFA also estimates the potential implications of the proposed exclusion for low producing
sites from the fugitive emission requirements. Fewer sites in the program due to this exclusion
will likely lead to lower costs and emissions.
The analysis indicates about 1,200 to 2,100 small entities may be subject to the
requirements for hydraulically fractured and re-fractured oil well completions and fugitive
emissions requirements at well sites. The low end of this range reflects an estimate of how many
entities might be excluded as a result of the low production fugitive emissions exemption. Also,
the cost-to-sales ratios with ratios greater than 1 percent and 3 percent increase from 2020 to
2025 as affected sources accumulate under the proposed NSPS. Cost-to-sales ratios exceeding 1
percent and 3 percent are also reduced from the case without the entities that might be excluded
from fugitive emissions requirements as a result of the low production exemption.
The analysis above is subject to a number of caveats and limitations. These are discussed
in detail in the IRFA, as well as in Section 3 of the RIA.
As required by section 609(b) of the RFA, the EPA also convened a Small Business
Advocacy Review (SBAR) Panel to obtain advice and recommendations from small entity
representatives that potentially would be subject to the rule's requirements. The SBAR Panel
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evaluated the assembled materials and small-entity comments on issues related to elements of an
IRFA. A copy of the full SBAR Panel Report is available in the rulemaking docket.
5.4 Unfunded Mandates Reform Act
This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C.
1531-1538, and does not significantly or uniquely affect 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 implications. It will not have substantial direct
effects on the states, on the relationship between the national government and the states, or on
the distribution of power and responsibilities among the various levels of government. These
final rules primarily affect private industry and would not impose significant economic costs on
state or local governments.
5.6 Executive Order 13175: Consultation and Coordination with Indian Tribal
Governments
This action has tribal implications. However, it will neither impose substantial direct
compliance costs on federally recognized tribal governments, nor preempt tribal law. The
majority of the units impacted by this rulemaking on tribal lands are owned by private entities,
and tribes will not be directly impacted by the compliance costs associated with this rulemaking.
There would only be tribal implications associated with this rulemaking in the case where a unit
is owned by a tribal government or a tribal government is given delegated authority to enforce
the rulemaking.
The EPA consulted with tribal officials under the "EPA Policy on Consultation and
Coordination with Indian Tribes" early in the process 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 stakeholders throughout the rulemaking process.
We provided an update on the methane strategy on the January 29, 2015, NTAA and EPA Air
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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 affecting the oil and natural gas sector, there is
significant tribal interest because of the growth of the oil and natural gas production in Indian
country. The EPA specifically solicits additional comment on this proposed action from tribal
officials.
5.7 Executive Order 13045: Protection of Children from Environmental Health Risks
and Safety Risks
This action is subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it
is an economically significant regulatory action as defined by Executive Order 12866, and the
EPA believes that the environmental health or safety risk addressed by this action has a
disproportionate effect on children. Accordingly, the agency has evaluated the environmental
health and welfare effects of climate change on children.
GHGs including methane contribute to climate change and are emitted in significant
quantities by the oil and gas sector. The EPA believes that the GHG emission reductions
resulting from implementation of these final guidelines will further improve children's health.
The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that
certain populations and life stages, including children, the elderly, and the poor, are most
vulnerable to climate-related health effects. The assessment literature since 2009 strengthens
these conclusions by providing more detailed findings 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 vulnerable to climate change. Impacts to children
are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental
health effects resulting from extreme weather events. In addition, children are among those
especially susceptible to most allergic diseases, as well as health effects associated with heat
5-6
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waves, storms, and floods. Additional health concerns may arise in low income households,
especially those with children, if climate change reduces food availability and increases prices,
leading to food insecurity within households.
More detailed information on the impacts of climate change to human health and welfare
is provided in Section V of this preamble.
5.8 Executive Order 13211: Actions Concerning 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
Management and Budget, a Statement of Energy Effects for certain actions identified as
"significant energy actions." Section 4(b) of Executive Order 13211 defines "significant energy
actions" as any action by an agency (normally published in the Federal Register) that
promulgates or is expected to lead to the promulgation of a final rule or regulation, including
notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking:
(l)(i) that is a significant regulatory action under Executive Order 12866 or any successor order,
and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy;
or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs
as a significant energy action.
This action is not a "significant energy action" as defined in Executive Order 13211 (66
FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect on the
supply, distribution, or use of energy. The basis for these determinations follows.
The EPA used the National Energy Modeling System (NEMS) to estimate the impacts of
the proposed rule on the United States energy system. The NEMS is a publically-available model
of the United States energy economy developed and maintained by the Energy Information
Administration of the DOE and is used to produce the Annual Energy Outlook, a reference
publication that provides detailed forecasts of the United States energy economy.
The EPA modeled the high impact case of the proposed NSPS with respect the low
production exemption from the well site fugitive emissions requirements. As such the NEMS-
5-7
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based estimates of energy system impacts are likely high end estimates. We estimate that natural
gas and crude oil production levels remains essentially unchanged in 2020, while slight declines
are estimated for 2020 for both natural gas (about 4 billion cubic feet (bcf) or about 0.01 percent)
and crude oil 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. Meanwhile, well crude oil prices for
onshore lower 48 production are not estimated to change, despite the incidence of new
compliance costs from the proposed NSPS. Meanwhile, net imports of natural gas are estimated
to decline slightly in 2020 (by about 1 bcf or 0.05 percent) and in 2025 (by about 3 bcf or 0.09
percent). Crude oil imports are estimated to not change in 2020 and increase by about 1,000
barrels per day (or 0.02 percent) in 2025.
Additionally, the NSPS establishes several performance standards that give regulated
entities flexibility in determining how to best comply with the regulation. In an industry that is
geographically and economically heterogeneous, this flexibility is an important factor in
reducing regulatory burden. For more information on the estimated energy effects of this
proposed rule, please see Section 7 of this RIA.
5.9 National Technology Transfer and Advancement Act (NTTAA) and 1 C.F.R. part 51
Section 12(d) of the National Technology Transfer and Advancement Act of 1995
(NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note) directs the EPA to use voluntary
consensus standards (VCS) in its regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards (e.g., materials
specifications, test methods, sampling procedures, and business practices) that are developed or
adopted by VCS bodies. NTTAA directs the EPA to provide Congress, through OMB,
explanations when the Agency decides not to use available and applicable VCS.
The proposed rule involves technical standards. Therefore, the EPA conducted searches
for the Oil and Natural Gas Sector: Emission Standards for New and Modified Sources through
the Enhanced National Standards Systems Network (NSSN) Database managed by the American
National Standards Institute (ANSI). Searches were conducted for EPA Methods 1, 1A, 2, 2A,
5-8
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2C, 2D, 3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 21, 22, and 25A of 40 C.F.R. part 60 Appendix A. No
applicable voluntary consensus standards were identified for EPA Methods 1A, 2A, 2D, 21, and
22. All potential standards were reviewed to determine the practicality of the VCS for this rule.
In this rule, the EPA is proposing to include in a final EPA rule regulatory text for 40 CFR part
60, subpart OOOOa that includes incorporation by reference. In accordance with requirements of
1 CFR 51.5, the EPA is proposing to incorporate by reference ANSI/ASME PTC 19-10-1981,
Flue and Exhaust Gas Analyses (Part 10) to be used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A
and 16A manual portions only and not the instrumental portion. This standard is available from
the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY
10016-5990.
The EPA welcomes comments on this aspect of the proposed rulemaking and,
specifically, invites the public to identify potentially-applicable VCS and to explain why such
standards should be used in this regulation.
5.10 Executive Order 12898: Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations
The EPA believes the human health or environmental risk addressed by this action will
not have potential disproportionately high and adverse human health or environmental effects on
minority, low-income or indigenous populations. The EPA has determined this because the
rulemaking increases the level of environmental protection for all affected populations without
having any disproportionately high and adverse human health or environmental effects on any
population, including any minority, low-income or indigenous populations. The EPA has
provided meaningful participation opportunities for minority, low-income, indigenous
populations and tribes during the pre-proposal period by conducting community calls and
webinars. Additionally, the EPA will conduct outreach for communities after the rulemaking is
finalized.
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6 COMPARISON OF BENEFITS AND COSTS
Tables 6-1 though Table 6-3 present the summary of the benefits, costs, and net benefits
for the NSPS across regulatory options. Table 6-4 provides a summary of the direct and
secondary emissions changes for each regulatory option.
Table 6-1 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in
2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$200 million
$150 million
$43 million
Non-monetized climate benefits
Health effects of PM2.s and ozone
exposure from 120,000 tons of VOC
reduced
Health effects of HAP exposure from
310 tons of HAP reduced
Health effects of ozone exposure from
170,000 tons of methane
Visibility impairment
Vegetation effects
$470 million
$310 million
$160 million
Non-monetized climate benefits
Health effects of PM2.s and ozone
exposure from 170,000 tons of VOC
reduced
Health effects of HAP exposure from
1,900 tons of HAP reduced
Health effects of ozone exposure from
340,000 tons of methane
Visibility impairment
Vegetation effects
1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4)
(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes of
this table, we show the benefits associated with the model average a 3 percent discount rate. However, we
emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the
additional benefit estimates range from $89 million to $530 million in 2020 and $220 million to $1,200 million in
2025 for the proposed option, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission
reductions are 3.8 million metric tons in 2020 and 7.7 million metric tons in 2025. Also, the specific control
technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for
details.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue
from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for
the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not
change when using a 3 percent discount rate.
3 Estimates may not sum due to independent rounding.
6-1
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Table 6-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2
(Proposed Option) in 2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$200 to $210 million
$150 to $170 million
$35 to $42 million
Non-monetized climate benefits
Health effects of PM2.s and ozone
exposure from 120,000 tons of VOC
reduced
Health effects of HAP exposure from
310 to 400 tons of HAP reduced
$460 to $550 million
$320 to $420 million
$120 to $150 million
Non-monetized climate benefits
Health effects of PM2.s and ozone
exposure from 170,000 to 180,000
tons of VOC reduced
Health effects of HAP exposure from
1,900 to 2,500 tons of HAP reduced
Health effects of ozone exposure from Health effects of ozone exposure from
170,000 to 180,000 tons of methane 340,000 to 400,000 tons of methane
Visibility impairment
Vegetation effects
Visibility impairment
Vegetation effects
1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4)
(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes of
this table, we show the benefits associated with the model average a 3 percent discount rate. However, we
emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the
additional benefit estimates range from $88 million to $550 million in 2020 and $220 million to $1,400 million in
2025 for the proposed option, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission
reductions are 3.8 to 4.0 million metric tons in 2020 and 7.7 to 9.0 million metric tons in 2025. Also, the specific
control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. See Section 4.7
for details.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue
from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for
the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not
change when using a 3 percent discount rate.
3 Estimates may not sum due to independent rounding.
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Table 6-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in
2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$220 million
$210 million
$7.6 million
Non-monetized climate benefits
Health effects of PMi.s and ozone
exposure from 130,000 tons of VOC
reduced
Health effects of HAP exposure from
510 tons of HAP reduced
Health effects of ozone exposure from
190,000 tons of methane
Visibility impairment
Vegetation effects
$640 million
$680 million
-$35 million
Non-monetized climate benefits
Health effects of PMi.5 and ozone
exposure from 200,000 tons of VOC
reduced
Health effects of HAP exposure from
3,200 tons of HAP reduced
Health effects of ozone exposure from
470,000 tons of methane
Visibility impairment
Vegetation effects
1 The benefits estimates are calculated using four different estimates of the social cost of methane (SC-CH4)
(model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For purposes
of this table, we show the benefits associated with the model average at a 3 percent discount rate. However we
emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the
additional benefit estimates range from $99 million to $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 COi-equivalent (COi Eq.) methane emission
reductions are 4.2 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control
technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.
2 The engineering compliance costs are annualized 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.
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Table 6-4 Summary of Emissions Changes across Options for the NSPS in 2020 and
2025 (short tons per year, unless otherwise noted)
Option 1
Change in
Direct
Emissions
Change in
Secondary
Emissions
Net
Change in
CO2 Eq.
Emissions
Pollutant
Methane
VOC
HAP
CO2
NOx
PM
CO
THC
CO2Eq.
(million
short tons)
CO2Eq.
(million
metric tons)
2020
170,000
120,000
310
610,000
310
10
1,700
640
4.2
3.8
2025
340,000
170,000
1,900
750,000
380
11
2,100
790
8.5
7.7
Proposed
Option 2 (Low)
2020
170,000
120,000
310
610,000
310
10
1,700
640
4.2
3.8
2025
340,000
170,000
1,900
750,000
380
11
2,100
790
8.5
7.7
Proposed
Option 2 (High)
2020
180,000
120,000
400
610,000
310
10
1,700
640
4.4
4.0
2025
400,000
180,000
2,500
750,000
380
11
2,100
790
9.9
9.0
Option 3
2020
190,000
130,000
510
610,000
310
10
1,700
640
4.7
4.2
2025
470,000
200,000
3,200
750,000
380
11
2,100
790
12
11
Note: Totals may not sum due to independent rounding.
6-4
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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
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 production and consumption of crude oil and natural
gas, and changes in international trade of crude oil and natural gas. We evaluate whether and to
what extent the increased production costs imposed by the proposed rule might alter the mix of
fuels consumed at a national level. The EPA only modeled the energy system impacts of the high
impact case of the proposed NSPS with respect the low production exemption from the well site
fugitive emissions requirements. As such the NEMS-based estimates of energy system impacts
are likely high end estimates.
A brief conceptual discussion about our energy system impacts modeling approach is
necessary before going into detail on NEMS, how we implemented the regulatory impacts, and
presenting results. Economically, it is possible to view the recovered natural gas as an explicit
output or as contributing to an efficiency gain in production at the producer level. For example,
the analysis for the proposed rule shows that performing reduced emissions completions on
hydraulically-fractured oil wells contributes about 75 percent of the natural gas captured by
emissions controls in 2020 and about 32 percent of captured natural gas in 2025. The fugitive
emissions program at well sites is expected to capture about 18 percent of the natural gas
captured by emissions controls in 2020 and about 52 percent of captured natural gas in 2025.
The assumed $4/Mcf price for natural gas is the price paid to producers at the wellhead.
In the natural gas industry, production is metered at or very near to the wellhead, and producers
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are paid based upon this metered production. Depending on the situation, the gas captured by a
REC is sent through a temporary or permanent meter. Payments for the gas are typically made
within 30 days.
In the engineering cost analysis, it is necessary to estimate the expected costs and
revenues from implementing emissions controls at the unit level. Because of this, we estimate the
net costs as expected costs minus expected revenues for representative units. On the other hand,
NEMS models the profit maximizing behavior of representative project developers at a drilling
project level. The net costs of the regulation alter the expected discounted cash flow of drilling
and implementing oil and gas projects, and the behavior of the representative drillers adjusts
accordingly. While in the regulatory case natural gas drilling has become more efficient because
of the gas recovery, project developers still interact with markets for which supply and demand
are simultaneously adjusting. Consequently, project development adjusts to a new equilibrium.
While we believe the cost savings as measured by revenues from selling recovered gas
(engineering costs) and measured by cost savings from averted production through efficiency
gains (energy economic modeling) are approximately the same, it is important to note that the
engineering cost analysis and the national-level cost estimates do not incorporate economic
feedbacks such as supply and demand adjustments.
7.2.7 Description of the Department of Energy National Energy Modeling System
NEMS is a model of U.S. energy economy developed and maintained by the Energy
Information Administration of the U.S. Department of Energy (DOE). NEMS is used to produce
the Annual Energy Outlook, a reference publication that provides detailed forecasts of the energy
economy from the current year to 2040. DOE first developed NEMS in the 1980s, and the model
has undergone frequent updates and expansion since. DOE uses the modeling system extensively
to produce issue reports, legislative analyses, and respond to Congressional inquiries.
EIA is legally required to make the NEMS system 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 produced. Because of the availability of the
NEMS model, numerous agencies, national laboratories, research institutes, and academic and
private-sector researchers have used NEMS to analyze a variety of issues.
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NEMS models the dynamics of energy markets and their interactions with the broader
U.S. economy. The system projects the production of energy resources such as oil, natural gas,
coal, and renewable fuels, the conversion of resources through processes such as refining and
electricity generation, and the quantity and prices for final consumption across sectors and
regions. The dynamics of the energy system are governed by assumptions about energy and
environmental policies, technological developments, resource supplies, demography, and
macroeconomic conditions. An overview of the model and complete documentation of NEMS
can be found at < http://www.eia.gov/forecasts/aeo/>.
NEMS is a large-scale, deterministic mathematical programming model. NEMS
iteratively solves multiple models, linear and non-linear, using nonlinear 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 model after establishing an updated
provisional solution.
NEMS provides what EIA refers to as "mid-term" projections to the year 2040. For this
RIA, we draw upon the same assumptions and model used in the Annual Energy Outlook 2014.74
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 Supply Module (OGSM) of NEMS and domestic and
Canadian natural gas production within the Natural Gas Transmission and Distribution Module
(NGTDM). The OGSM projects domestic oil and gas production from onshore, offshore,
Alaskan wells, as well as having a smaller-scale treatment of Canadian oil and gas production
(U.S. EIA, 2014). The treatment of oil and gas resources is detailed in that oil, shale oil,
conventional gas, shale gas, tight sands gas, and coalbed methane (CBM) are explicitly modeled.
New exploration and development is pursued in the OGSM if the expected net present value of
74 Assumptions for the 2014 Annual Energy Outlook can be found at
.
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extracted resources exceeds expected costs, including costs associated with capital, exploration,
development, production, and taxes. Detailed 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 expenditures for environmental controls required by the
NSPS on new exploratory and developmental oil and gas production activities. We model the
impacts of additional environmental costs, as well as the impacts of additional product recovery.
We explicitly model the additional natural gas recovered when implementing the proposed rule.
While the oil production simulated by the OGSM is sent to the refining module (the
Liquid Fuels Market Module), simulated natural gas production is sent to a transmission and
distribution network captured in the NGTDM. The NGTDM balances gas supplies and prices
and "negotiates" supply and consumption to determine a regional equilibrium between supply,
demand and prices, including imports and exports via pipeline or LNG. Natural gas is
transported through a simplified arc-node representation 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 profitability of new projects. Additional NSPS costs associated with
reduced emission completions for hydraulically fractured oil well completions are added to the
drilling and completion costs of oil wells in the OGSM.
Other costs are operations and maintenance-type costs and are added to fixed operation
and maintenance (O&M) expenses associated with new projects. The additional expenses are
estimated and entered on a per well basis, depending on whether the costs would apply to oil
wells or natural gas wells. We base the per well cost estimates on the engineering costs. Because
we model natural gas recovery, we do not include revenues from additional product recovery in
these costs. This approach is appropriate given the structure of the NEMS algorithm that
estimates the net present value of drilling projects.
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One caveat in introducing new cost requirements into the model is that potential barriers
to obtaining capital may not be adequately incorporated in the model. However, 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 estimated unit-level capital costs of controls that are
newly required at a national-level as a result of the regulation may not incorporate potential
additional transitional costs as the supply of control equipment adjusts to new demand.
Table 7-1 shows the incremental compliance that accrue to new drilling projects as a
result of producers having to comply with the NSPS, across sources anticipated in 2020 and
2025. We estimate those costs as a function of new wells expected to be drilled in a
representative year. To arrive at estimates of the per well costs, we first identify whether costs
will apply primarily to crude oil wells, to natural gas wells, or to both crude oil and natural gas
wells.
Based on the baseline projections of successful 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 prospective drilling project (Table 1).
Hydraulically fractured oil wells completions and fugitives at oil and natural gas well
sites differ slightly from this approach. Drilling and completion costs of new hydraulically
fractured oil wells are incremented by the weighted average of the cost of performing a REC
with completion combustion and completion combustion alone. The resulting 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 two wells per wells site (see TSD for more
details), new oil and gas wells face an increased annual cost of one-half of implementing the well
site fugitive emission requirements.
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Table 7-1 Per Well Costs for Environmental Controls Entered into NEMS (2012$)
Emissions Sources/Points
Well Completions
Hydraulically Fractured Oil
Well Completions
Fugitive Emissions
Oil Production Well Sites
Natural Gas Production
Well Sites
Gathering and Boosting
Stations
Transmission Stations
Storage Facilities
Reciprocating Compressors
Transmission Stations
Storage Facilities
Centrifugal Compressors
Storage Facilities
Pneumatic Controllers -
Transmission and Storage
Stations
Pneumatic Pumps
Well Sites
Reporting and Recordkeeping
Wells Applied
To in NEMS
New
Hydraulically
Fractured Oil
Wells
New Oil Wells
New Gas Wells
New Gas Wells
New Gas Wells
New Gas Wells
New Gas Wells
New Gas Wells
New Gas Wells
New Gas Wells
New Wells
New Wells
Annualized
Cost per Unit
(2012$)
$17,1827 $3723
$2,144
$2,144
$14,028
$13,879
$21,049
$1,748
$2,077
$114,146
$25
$285
$1,381,023*
Per New
Well Costs
Applied in
NEMS
(2012$)
$7,067
$1,072
$1,072
$430
$10
$37
$5
$11
$13
$1
$19
$31
Gas
Recovery
per Unit
(Mcf)
0
38
158
1,222
1,938
5,107
1,122
1,130
0
0
0
0
Per New
Well Gas
Recovery
Applied in
NEMS
(Mcf)
0
19
79
37
1
9
3
6
0
0
0
0
*Note: reporting and recordkeeping costs are assumed to be equally allocated across all new wells.
7.2.2.2 Adding Averted Methane Emissions into Natural Gas Production
A result of controlling methane and VOC emissions from oil and natural gas production
is that methane that would otherwise be lost to the atmosphere can be directed into the natural
gas production stream. We chose to model methane capture in NEMS as an increase in natural
gas industry productivity, ensuring that, within the model, natural gas reservoirs are not
decremented by production gains from methane capture. We add estimates of the quantities of
methane captured (or otherwise not vented or combusted) to the base quantities that the OGSM
model supplies to the NGTDM model. We subdivide the estimates of commercially valuable
averted emissions by region and well type in order to more accurately portray the economics of
implementing the environmental technology. Adding the averted methane emissions in this
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manner has the effect of moving the natural gas supply curve to the right an increment consistent
with the technically achievable emissions transferred into the production stream as a result of the
proposed NSPS.
We enter the increased natural gas recovery into NEMS on a per-well basis for new
natural gas wells, following an estimation procedure similar to that of entering compliance costs
into NEMS on a per-well basis for new wells (Table 7-1). For this analysis, however, we were
unable to incorporate the natural gas recovery from performing RECs on hydraulically fractured
oil well completions or from other emissions control activities at oil well sites. We hope to make
this modification in 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, and changes in international trade of crude oil and
natural gas.75 In each of these estimates, we present 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 and natural gas trade, we focus the analysis on
onshore oil and natural gas production activities in the continental (lower 48) U.S. We do this
because off-shore production is not affected by the proposed NSPS and the bulk of the proposed
rule's impacts are expected in the continental U.S.
We first report estimates of impacts on crude oil and natural gas drilling activities and
production. Table 7-2 presents estimates of successful onshore natural gas and crude oil wells
drilled in the continental U.S.
75 The EPA only modeled the high impact case of the proposed NSPS with respect the low production exemption
from the well site fugitive emissions requirements. As such the NEMS-based estimates of energy system impacts
are likely high end estimates.
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Table 7-2 Successful Oil and Gas Wells Drilled (Onshore, Lower 48 States)
Projection, 2020
Successful Wells Drilled
Natural Gas
Crude Oil
Total
% Change in Successful
Natural Gas
Crude Oil
Total
2012 Baseline
10,965 20,298
26,517 24,660
37,482 44,959
Wells Drilled from Baseline
NSPS
20,299
24,660
44,959
0.00%
0.00%
0.00%
Projection, 2025
Baseline NSPS
24,727 24,800
27,648 27,638
52,375 52,438
0.30%
-0.04%
0.12%
Projection, 2020-25
Baseline NSPS
142,764 142,638
155,201 155,202
297,965 297,840
-0.09%
0.00%
-0.04%
Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption
from the well site fugitive emissions requirements.
Results show that the proposed NSPS will have a relatively small impact on onshore well
drilling in the lower 48 states. Drilling remains essentially unchanged in 2020, but increases for
natural gas wells in 2025, while decreasing for crude oil wells in 2025. The increase in natural
gas well drilling in 2025 is somewhat counter-intuitive as production costs have been increased
under the proposed NSPS. However, given NEMS is a dynamic, multi-period model, it is
important to examine changes over multiple time periods. Natural gas well drilling over the 2020
to 2025 period decreases but about 120 wells total. Crude oil drilling, over the same six-year,
period remains at the same levels.
Table 7-3 shows estimates of the changes in the domestic production of natural gas and
crude oil under the proposed NSPS.
Table 7-3 Annual Domestic Natural Gas and Crude Oil Production (Onshore, Lower
48 States)
Projection, 2020 Projection, 2025 Projection, 2020-25
2012 Baseline NSPS Baseline NSPS Baseline NSPS
Domestic Production
Natural Gas (trillion cubic feet) 22.075 26.577 26.576 28.931 28.927 167.585 167.576
Crude Oil (million barrels/day) 4.599 7.234 7.234 7.064 7.062 7.174 7.173
Natural Gas
Crude Oil
0.00%
0.00%
-0.01%
-0.03%
-0.01%
-0.01%
Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption
from the well site fugitive emissions requirements.
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As indicated by the estimated change in the new well drilling activities, the analysis
shows that the proposed NSPS will have a relatively small impact on onshore natural gas and
crude oil production in the lower 48 states. Again, production levels Drilling remains essentially
unchanged in 2020, while slight declines are 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). Total production over the 2020 to 2025 is also estimated to decline for
natural gas (by about 9 bcf or 0.01 percent) and crude oil (by about 1,000 barrels per day or
about 0.01 percent)
Note this analysis estimates no increase in domestic natural gas production, despite some
environmental controls 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 incorporate into the model the natural gas recovery from
performing RECs on hydraulically fractured oil well completions or from other emissions control
activities at oil well sites. Second, 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 controls 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 from the baseline projections.
Table 7-4 presents estimates of national average 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%
Crude Oil 0.00%
0.14%
0.00%
0.06%
0.00%
Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption
from the well site fugitive emissions requirements.
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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. The
production weighted average price over the 2020 to 2025 period is estimated to increase by
$0.003 per Mcf or about 0.06 percent. Meanwhile, well crude oil prices for onshore lower 48
production are not estimated to change, despite the incidence of new compliance costs from the
proposed NSPS. This is likely result of both the relatively small scale of the costs of the new
compliance requirements, as well as the fact that oil prices are more a function 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 percent), 2025 (by about 3 bcf or 0.09 percent), and
across the 2020 to 2025 period (by about 4 bcf total or about 0.03 percent). Crude oil imports are
estimated to not change in 2020, increase by about 1,000 barrels per day (or 0.02 percent) in
2025 or by about 2,000 barrels per day (or about 0.02 percent) on average during the 2020 to
2025 time period.
Table 7-5 Net Imports of Natural Gas and Crude Oil
Net Imports
Natural Gas (trillion cubic feet)
Crude Oil (million barrels/day)
% Change in Net Imports
Natural Gas
Crude Oil
Projection, 2020
2012 Baseline NSPS
1.515 -1.901 -1.900
8.432 5.781 5.781
-0.05%
0.00%
Projection, 2025
Baseline NSPS
-3.211 -3.208
6.004 6.005
-0.09%
0.02%
Projection, 2020-25
Baseline NSPS
-15.371 -15.367
5.914 5.916
-0.03%
0.02%
Note: reflects estimates of the high impact case of the proposed NSPS with respect the low production exemption
from the well site fugitive emissions requirements.
7.3 Initial Regulatory Flexibility Analysis
The Regulatory Flexibility Act (RFA; 5 U.S.C.§ 601 et seq.), as amended by the Small
Business Regulatory Enforcement Fairness Act (Public Law No. 104-121), provides that
whenever an agency is required to publish a general notice of proposed rulemaking, it must
prepare and make available an initial regulatory flexibility analysis (IRFA), unless it certifies that
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the proposed rale, if promulgated, will not have a significant economic impact on a substantial
number of small entities (5 U.S.C. § 605[b]). Small entities include small businesses, small
organizations, and small governmental jurisdictions. An IRFA describes the economic impact of
the proposed rale on small entities and any significant alternatives to the proposed rale that
would accomplish the objectives of the rale while minimizing significant economic impacts on
small entities. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory
flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along
with regulatory alternatives that could minimize that impact.
7.3.7 Reasons why Action is Being Considered
This action proposes to amend the new source performance standards (NSPS) for the oil
and natural gas source category by setting standards for both methane and volatile organic
compounds (VOC) for certain equipment, processes and activities across this source category.
The EPA is including requirements for methane emissions in this proposal because methane is a
greenhouse gas (GHG), and the oil and natural gas category is currently one of the country's
largest emitters of methane. In 2009, the EPA found that by causing or contributing to climate
change, GHGs endanger both the public health and the public welfare of current and future
generations. The EPA is proposing to amend the NSPS to include standards for reducing
methane as well as VOC emissions across the oil and natural gas source category.
7.3.2 Statement of Objectives and Legal Basis for Proposed Rules
The EPA is proposing to amend the NSPS to include standards for reducing methane as
well as VOC emissions across the oil and natural gas source category. Specifically, we are
proposing both methane and VOC standards for several emission sources not currently covered
by the NSPS (i.e., hydraulically fractured oil well completions, fugitive emissions from well sites
and compressor stations, and pneumatic pumps). In addition, we are proposing methane
standards for certain emission sources that are currently regulated for VOC (i.e., hydraulically
fractured gas well completions, equipment leaks at natural gas processing plants). With respect
to certain equipment that are used across the source category, the current NSPS regulates only a
subset of these equipment (pneumatic controllers, centrifugal compressors, reciprocating
compressors). The proposed amendents would establish methane standards for these equipment
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across the source category and extend the current VOC standards to the remaining unregulated
equipment. Lastly, amendments to the current NSPS are being proposed that improve
implementation of several aspects of the current standards. These improvements result from
reconsideration of certain issues raised in petitions for reconsideration that were received by the
Administrator on the August 16, 2012, final NSPS for the oil and natural gas sector and related
amendments. Except for the implementation improvements and the setting of standards for
methane, these amendments do not change the requirements for operations already covered by
the current standards.
Section 111 of the CAA requires the EPA Administrator to list categories of stationary
sources that, in his or her judgment, cause or contribute significantly to air pollution which may
reasonably be anticipated to endanger public health or welfare. The EPA must then issue
"standards of performance" for new sources in such source categories. The EPA has the
authority to define the source categories, determine the pollutants for which standards should be
developed, and identify within each source category the facilities for which standards of
performance would be established.
CAA Section lll(a)(l) defines "a standard of performance" as "a standard for emissions
of air pollutants which reflects the degree of emission limitation achievable through the
application of the best system of emission reduction which (taking into account the cost of
achieving such reduction and any nonair quality health and environmental impact and energy
requirement) the Administrator determines has been adequately demonstrated." This definition
makes clear that the standard of performance must be based on controls that constitute "the best
system of emission reduction... adequately demonstrated". The standard that the EPA develops,
based on the BSER, is commonly a numerical emissions limit, expressed as a performance level
(e.g., a rate-based standard). Generally, the EPA does not prescribe a particular technological
system that must be used to comply with a standard of performance. Rather, sources generally
can select any measure or combination of measures that will achieve the emissions level of the
standard.
Standards of performance under section 111 are issued for new, modified and
reconstructed stationary sources. These standards are referred to as "new source performance
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standards." The EPA has the authority to define the source categories, determine the pollutants
for which standards should be developed, identify the facilities within each source category to be
covered and set the emission level of the standards.
CAA section 11 l(b)(l)(B) requires the EPA to "at least every 8 years review and, if
appropriate, revise" performance standards unless the "Administrator determines that such
review is not appropriate in light of readily available information on the efficacy" of the
standard. When conducting a review of an existing performance standard, the EPA has discretion
to revise that standard to add emission limits for pollutants or emission sources not currently
regulated for that source category.
7.3.3 Description and Estimate of Affected Small Entities
The industry sectors covered by the final rule were identified during the development of
the engineering cost analysis. The EPA conducted this regulatory flexibility analysis at the
ultimate (i.e., highest) level of ownership, evaluating parent entities.76 The EPA identified the
size of ultimate parent entities by using the Small Business Administration (SBA) size threshold
guidelines.77 The criteria for size determination vary by the organization/operation category of
the ultimate parent entity, as follows:
Table 7-6 SBA Size Standards by NAICS Code
NAICS
Codes
211111
211112
213111
213112
486110
486210
NAICS Industry Description
Crude Petroleum and Natural Gas Extraction
Natural Gas Liquid Extraction
Drilling Oil and Gas Wells
Support Activities for Oil and Gas Operations
Pipeline Transportation of Crude Oil
Pipeline Transportation of Natural Gas
Size Standards
(in millions of dollars)
-
-
-
$38.5
-
$27.5
Size Standards
(in no. of employees)
500
500
500
-
1,500
-
Sources: U.S. Census Bureau, Statistics of U.S. Businesses, 2012. http://www.census.gov/econ/susb/. SBA Size
Standards, 13 CFR 121. 201
We have projections of future potentially affected activities at an aggregate level, but
identifying impacts on specific entities is challenging because of the difficulty of predicting
76 See Section 2.6 of this RIA for more information on oil and natural gas industry firm characteristics and a
breakdown of firms by size at the national level.
77 U.S. Small Business Administration (SBA). 2014. Small Business Size Standards. Effective as of July 14, 2014.
See: http://www.sba.gov/sites/default/files/Size_Standards_Table.pdf.
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potentially affected new or modified source at the firm level. Because of these limitations, we
based the analysis in this IRFA on impacts estimates for the proposed requirements for
hydraulically fractured and re-fractured oil well completions and well site fugitive emissions. We
are able to do this because the base year activity counts for the impacts estimates (as described in
the TSD) for this rule were based on detailed information for 2012 in a dataset of U.S. wells. The
proprietary Drillinglnfo dataset contains a variety of information including oil, condensate, and
natural gas production levels, geographic locations, as well as basin and formation information,
and information about owners/operators of wells, among other data fields.78 As described in the
TSD sections on hydraulically fractured and re-fractured oil well completions and fugitive
emissions, we used the Drillinglnfo dataset to identify and estimate all wells that were completed
in 2012, as well as completions of hydraulically fracture or re-fractured oil wells.79 We used the
field called "common operator" to identify the owner/operator of all wells in this set of new or
modified 2012 wells.
While the IRFA does not incorporate potential impacts from other provisions of the
proposed NSPS, the completions and fugitive emissions provisions represent about 97 percent
and 94 percent of the estimated compliance costs of the proposed NSPS in 2020 and 2025,
respectively (Table 7-7). Note incorporating impacts from other provisions in this analysis is a
limitation, but the EPA believes that detailed analysis of the two provisions impacts on small
entities is illustrative of impacts on small entities from the proposed rule in its entirety.
78 Drillinglnfo is a private company that provides information and analysis to the energy sector. More information is
available at: http://info.drillinginfo.com.
79 The TSD for this proposed rule provides information on this dataset of U.S. wells. Additional details on the
development of this dataset can also be found in the following docketed memo: Memorandum to Mark de
Figueiredo, EPA, from Casey MacQueen and Jessica Gray, ERG. "Drillinglnfo Processing Methodology".
August 27, 2014.
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Table 7-7 Distribution of Estimated Compliance Costs across Sources
Hydraulically-fractured and Re-fractured
Oil Well Completions and Recompletions
Fugitive Emissions at Well-sites1
Other Sources
Total Annualized Costs of Proposed NSPS
Annualized Costs (With Product Recovery, 2012$)
2020 2020 (%) 2025 2025 (%)
$120,000,000 71% $120,000,000 29%
$43,000,000 25% $270,000,000 64%
$5,800,000 3% $30,000,000 7%
$170,000,000 100% $420,000,000 100%
1 Estimates for fugitive emissions requirements based on "high impact" case.
Note: sums may not total due to independent rounding.
To identify potentially affected entities under the proposed NSPS, the EPA combined
ownership information from the Drillinglnfo dataset with information drawn from the Hoover's
Inc. online platform, which includes information about companies NAICS codes, employee
counts, and sales information.80 Note that this analysis assumes that the firms performing
potentially affected activities are also the firms performing activities in the future under the
proposed NSPS. While likely true for many firms, this will not be the case for all firms.
The EPA matched owner/operators from the Drillinglnfo dataset to companies in a
database developed from a download of oil and gas companies in Hoover's online database. The
EPA matched as many records as possible. In the instances where the Drillinglnfo
owner/operator was not the highest level or company ownership, we recorded the highest level of
owner as was identifiable in Hoovers. Linking these two datasets yields information on the
NAICS, employee levels, and revenues of the owner/operators shown in the Drillinglnfo dataset
to have new or modified wells in 2012.
The EPA then used the NAICS codes associated with the matched owner/operators to
determine which owner/operators should be considered to be small entities for this analysis,
based on the SBA size standards above. That said, many Drillinglnfo owner/operators had no
match in Hoovers. Additionally, some Hoovers records lacked the information (employees or
revenues, depending on the NAICS) needed to make a size determination. We initially classified
these as an "unknown" size. See Table 7-8 for a summary of results of this matching exercise.
80 The Hoover's Inc. online platform includes company records that can contain NAICS codes, number of
employees, revenues, and assets. For more information, see: http://www.hoovers.com.
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Table 7-8 No. of Completions in 2012 by Preliminary Firm Size
Number of Completions, 2012
Firm Size Performing Hydraulically Fractured
Well Completions No. of Firms or Re-fractured Oil Wells All Completions
Small 1,000 3,300 12,000
Not Small 67 10,000 21,000
Unknown 1,100 750 6,000
Total 2,200 14,000 39,000
Note: consistent with the cost and emissions analysis, these 2012 completion counts do not include completions in
states where there are state rules with similar requirements as the proposed rules. Counts slightly lower than totals
included in impacts analysis base year estimates as some completions have no owner/operator recorded in the
dataset. Sums may not total due to independent rounding.
Upon analysis of the firms of unknown size, the EPA observed that, on average, the firms
of unknown size perform fewer well completions. For this reason, we made the observation that
the firms of unknown size are more likely to be small than not small. To proceed with the
analysis, we reclassified these firms as small, resulting in the distribution presented in the first
two columns of Table 7-9.
Table 7-9 No. of Completions in 2012 by Firm Size
No. of Completions, 2012
Firm Size Performing
Well Completions
Small
Not Small
Total
No. of Firms
1,100 to 2,200
66 to 67
1,200 to 2,200
Hydraulically Fractured
or Re-fractured Oil Wells
4,000
10,000
14,000
All Completions
7,800 to 18,000
15,000 to 21,000
23,000 to 39,000
Note: consistent with the cost and emissions analysis, these 2012 completion counts do not include completions in
states where there are state rules with similar requirements as the proposed rules. Counts slightly lower than totals
included in impacts analysis base year estimates as some completions have no owner/operator recorded in the
dataset. Sums may not total due to independent rounding.
The proposed NSPS provides an exclusion for low producing sites from the fugitive
emissions requirements.81 A low production site is defined by the average combined oil and
natural gas production for the wells at the site being less than 15 barrels of oil equivalent (boe)
per day.82 While the EPA is proposing an exclusion from fugitive emission requirements for low
production well sites, there is uncertainty in how many well sites this exclusion might affect in
the future. As a result, the analyses in this IRFA, like the RIA, presents a "low" impact case and
81 In the preamble to the proposed rule, EPA is soliciting comment on excluding low production sites from the
fugitive emissions program.
82 Natural gas production is converted to barrels oil equivalent using the conversion of 0.178 barrels of crude oil
equals 1000 cubic feet natural gas.
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"high" impact case for fugitive emissions requirements at well sites. The low impact case
excludes an estimate low production sites, based on the first month of production data from wells
newly completed or modified in 2012.The high impact case includes these well sites. Table 7-9
presents the number of wells completed in the base year of 2012, where the range of wells under
the fugitive emissions requirements reflects the range of the low and high impact cases. Note that
while the number of firms potentially affected goes down substantially, the low production
exclusion from fugitive emissions requirements does not affect the number of affected oil well
completions.
7.3.4 Compliance Cost Impact Estimates
7.3.4.1 Methodology for Estimating Impacts on Small Entities
This section describes how we project the 2012 base year estimates of incrementally
affected facilities to 2020 and 2025 levels, how we estimate costs at the firm level from these
activity estimates, and how we estimated sales for small entities when available data on sales are
incomplete.
New and modified hydraulically fractured oil well completions and well sites in this
IRFA are based on the same growth rates used to project future activities as described in the TSD
and consistent with other analyses in this RIA. These growth rates are consistent with the drilling
activity in the 2014 Annual Energy Outlook. These growth rates are applied to the 2012 base
year estimates for each firm in the database. Table 7-10 and Table 7-11 present future year
estimates of incrementally affected new and modified sources, in the low and high impact cases,
respectively.
Table 7-10 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, Low
Impact Fugitive Emissions Case
No. of Incrementally Affected Sources,
2020
Firm Size
Performing
Well
Completions
Small
Not Small
Total
Hydraulically
Fractured or Re-
fractured Oil
Wells
4,100
11,000
15,100
Gas Well
Sites
980
2,800
3,780
Oil Wells
Sites
3,400
5,900
9,300
No. of Incrementally Affected Sources,
2025
Hydraulically
Fractured or Re-
fractured Oil
Wells
4,200
11,000
15,200
Gas Well
Sites
6,900
20,000
26,900
Oil Wells
Sites
20,000
35,000
55,000
Note: Sums may not total due to independent rounding. Assumes well sites have two wells apiece.
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Table 7-11 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size, High
Impact Fugitive Emissions Case
No. of Incrementally Affected Sources,
2020
Firm Size
Performing
Well
Completions
Small
Not Small
Total
Hydraulically
Fractured or
Re-fractured
Oil Wells
4,100
11,000
15,100
Gas Well
Sites
1,900
3,600
5,500
Oil Wells
Sites
7,900
8,700
16,600
No. of Incrementally Affected Sources,
2025
Hydraulically
Fractured or
Re-fractured
Oil Wells
4,200
11,000
15,200
Gas Well
Sites
13,000
25,000
38,000
Oil Wells
Sites
48,000
52,000
100,000
Note: Sums may not total due to independent rounding. Assumes well sites have two wells apiece.
This approach assumes that no other firms perform potentially affected activities and
firms performing these activities in 2012 will continue to do so in 2020 and 2025. Again, the
analysis in this IRFA is meant to be illustrative of impacts on small entities. Exact predictions of
future activities at the firm level is not possible.
Once the future year activities were estimated we allocated compliance costs across small
entities based upon the costs estimated in the TSD and consistently with other analyses in this
RIA. These cost estimates include estimates of revenue from natural gas recovery at the assumed
value of $4/Mcf in 2012 dollars, again consistent with other analyses in this RIA. For
hydraulically fractured and re-fractured oil well completions, we assumed each small entity is
required to perform RECs/completions and completions in the same proportions assumed in the
TSD and RIA. We also assumed the same proportion would be exploratory or delineation wells
as the TSD and RIA. Table 7-12 shows the distribution of compliance costs estimates across firm
size, year, and whether the low production exemption is in place.
Table 7-12 Distribution of Estimated Compliance Costs1 across Firm Size Classes
Annualized Compliance Costs (2012$) Annualized Compliance Costs (2012$)
Low Impact Case High Impact Case
Firm Size
Small
Not Small
Total
No. of Firms
1,100
66
1,200
2020
43,000,000
100,000,000
150,000,000
2025
88,000,000
190,000,000
280,000,000
No. of Firms
2,200
67
2,200
2020
54,000,000
110,000,000
170,000,000
2025
160,000,000
240,000,000
390,000,000
1 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-fractured oil
well completions and well-site fugitive emissions. As described in Section 7.1.3, these provisions account for the
large majority of the rule's potential impact in 2020 and 2025.
Note: sums may not total due to independent rounding.
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In order to estimate the cost-to-sales ratio, we again combined information from Hoovers
and the Drillinglnfo databases. The Hoovers database has sales information for some, but not all,
small entities estimated in this IRFA analysis to have impacts. To supplement the sales
information, we estimated 2012 sales by multiplying 2012 oil and natural gas production levels
reported in the Drillinglnfo database by assumed oil and natural gas prices at the wellhead. For
natural gas, we assumed the same $4/Mcf for natural gas.83 For oil prices, we estimated revenues
using two alternative prices, $70/bbl and $50/bbl. In the results, we call the case using $70/bbl
the "primary scenario" and the case using the $50/bbl as the "low oil price scenario".84 In the
instances where the 2012 production-derived revenues exceeded the Hoovers revenues, we
replaced the Hoovers estimate with the production-derived estimate as more likely to be an
accurate estimate of sales for 2012.
7.3.4.2 Results
This section presents results of the cost-to-sales ratio analysis for both the primary
scenario and the low oil price scenario. In addition, we present both scenarios for the low and
high impact cases with respect to the low production exemption from the well site fugitive
emissions requirements.
83 The U.S. Energy Information Administration's 2015 Annual Energy Outlook projects 2020 Henry Hub natural gas
prices to be $4.88/MMBtu in its reference case and $4.30/MMBtu in its "low oil" price case in 2013 dollars.
Available at: http://www.eia.gov/beta/aeo/#/?id=14-AEO2015. After adjusting to $/Mcf (using the conversion of
1 MMBtu = 1.208 Mcf) in 2012 dollars (using the GDP-Implicit Price Deflator), these prices are $4.94/Mcf in
the reference case and $4.35/Mcf in the low oil price case. Rounding down to $4/Mcf would likely under-
estimated sales.
84 The 2015 Annual Energy Outlook projects wellhead oil prices to be $75.16/bbl in its reference case and
$54.10/bbl in its "low oil" price case in 2013 dollars. Available at: http://www.eia.gov/beta/aeo/#/?id=14-
AEO2015. After adjusting to 2012 dollars (using the GDP-Implicit Price Deflator), these prices are $74.00/bbl in
the reference case and $53.27/bbl in the low oil price case. Rounding down to $4/Mcf would likely under-
estimated sales.
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Table 7-13 Compliance Costs-to-Sales1 Ratios (Fugitive Emissions Requirements Low
Impact Case) across Firm Size Classes for Primary Scenario and Low Oil Price Scenario2
No. of Small Entities
Greater than 1 percent
Greater than 3 percent
No. of Small Entities
Greater than 1 percent
Greater than 3 percent
2020 (Primary
No. of Small
Entities
1,200
66
22
2025 (Primary
No. of Small
Entities
1,200
130
44
Scenario)
% of Small
Entities
6%
2%
Scenario)
% of Small
Entities
11%
4%
2020 (Low Oil
No. of Small
Entities
1,200
77
25
2025 (Low Oil
No. of Small
Entities
1,200
160
53
Price Scenario)
% of Small
Entities
7%
2%
Price Scenario)
% of Small
Entities
13%
5%
1 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-fractured oil
well completions and well-site fugitive emissions. These provisions account for the large majority of the rule's
potential impact in 2020 and 2025.
2 In the main case, the wellhead prices are assumed to be $4/Mcf for natural gas and $70/bbl for crude oil. In the low
oil price case, the wellhead prices are assumed to be $4/Mcf for natural gas and $50/bbl for crude oil.
Table 7-14 Compliance Costs-to-Sales1 Ratios (Fugitive Emissions Requirements Low
Impact Case) across Firm Size Classes for Primary Scenario and Low Oil Price Scenario2
No. of Small Entities
Greater than 1 percent
Greater than 3 percent
2020 (Primary Scenario)
No. of Small % of Small
Entities Entities
2,100
270 13%
120 6%
2025 (Primary Scenario)
2020 (Low Oil
No. of Small
Entities
2,100
320
140
2025 (Low Oil
Price Scenario)
% of Small
Entities
15%
7%
Price Scenario)
No. of Small % of Small No. of Small % of Small
Entities Entities Entities Entities
No. of Small Entities 2,100 - 2,100
Greater than 1 percent 710 33% 800 38%
Greater than 3 percent 370 17% 410 20%
1 Compliance cost estimates here include only costs of requirements for hydraulically fractured or re-fractured oil
well completions and well-site fugitive emissions. As described in Section 7.1.3, these provisions account for the
large majority of the rule's potential impact in 2020 and 2025.
2 In the main case, the wellhead prices are assumed to be$4/Mcf for natural gas and $70/bbl for crude oil. In the low
oil price case, the wellhead prices are assumed to be$4/Mcf for natural gas and $50/bbl for crude oil.
Comparing Table 7-13 with Table 7-14, about 900 fewer small entities are estimated to
be affected by the examined provision in the low impact fugitive emissions requirements case.
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Cost-to-sales ratios exceeding 1 percent and 3 percent are also reduced from the high impact to
low impact case without the exemption in place by approximately two-thirds. The percent
impacted by greater than 3 percent is about double the percent affected by greater than 1 percent
for each year of analysis in the primary and in the low oil price scenarios. Meanwhile, impacts
greater than 1 percent and 3 percent increase in the low oil price scenarios, as would be expected.
Also as expected the cost-to-sales ratios with ratios greater than 1 percent and 3 percent increase
from 2020 to 2025 as affected sources accumulate under the proposed NSPS.
7.3.5 Caveats and Limitations
The analysis above is subject to a number of caveats and limitations, many of which we
discussed in the presentation of methods and results. It is useful, however, to present a complete
list of the caveats and limitation here.
• Because of data limitations, the analysis presented in the IRFA only examines impacts
on requirements for hydraulically fractured and re-fractured oil well completions and
well site fugitive emissions. While impacts from these requirements constitute a large
proportion of the estimated impacts from the proposed NSPS, the omission of the cost
requirements of other requirements leads to a relative under-estimation of the impacts
on small entities. Also, the impacts from other requirements may affect firms that are
not drilling wells, such as pipeline transmission firms.
• Not all owner/operators listed in the Drillinglnfo database could be identified in the
Hoovers database. These owner/operators tend to have developed relatively few new
or modified wells in 2012. As a result, we assumed these were small entities, whereas
these entities may actually be subsidiaries of larger enterprises. While the impacts
estimates are not affected in the aggregate by this assumption, the assumption likely
leads to an over-estimate of the impact on small entities for the provisions examined.
• The analysis assumes the same population of entities completing wells in 2012 are also
completing wells in 2020 and 2025, according to growth rates developed for the entire
sector. In the future, many of these firms will complete fewer or more wells, and other
firms will complete wells. All of these firms combined may complete new or modified
wells at higher or lower rates depending on economics and technological factors that
are largely unpredictable.
• The approach used to estimate sales for the cost-to-sales might over-estimate or under-
estimate sales depending upon the accuracy of the information in the underlying
databases and the market prices ultimately faced in 2020 and 2025.
7.3.6 Projected Reporting, Recordkeeping and Other Compliance Requirements
The information to be collected for the proposed NSPS is based on notification,
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performance tests, recordkeeping and reporting requirements which will be mandatory for all
operators subject to the final standards. Recordkeeping and reporting requirements are
specifically authorized by section 114 of the CAA (42 U.S.C. 7414). The information will be
used by the delegated authority (state agency, or Regional Administrator if there is no delegated
state agency) to ensure that the standards and other requirements are being achieved. Based on
review of the recorded information at the site and the reported information, the delegated
permitting authority can identify facilities that may not be in compliance and decide which
facilities, records, or processes may need inspection. 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.
Potential respondents under subpart OOOOa are owners or operators of new, modified or
reconstructed oil and natural gas affected facilities as defined under the rule. None of the
facilities in the United States are owned or operated by state, local, tribal or the Federal
government. All facilities are privately owned for-profit businesses. The requirements in this
action result in industry recording keeping and reporting burden associated with review of the
requirements for all affected entities, gathering relevant information, performing initial
performance tests and repeat performance tests if necessary, writing and submitting the
notifications and reports, developing systems for the purpose of processing and maintaining
information, and train personnel to be able to respond to the collection of information.
The estimated average annual burden (averaged over the first 3 years after the effective
date of the standards) for the recordkeeping and reporting requirements in subpart OOOOa for
the 2,552 owners and operators that are subject to the rule is 92,658 labor hours, with an annual
average cost of $3,163,699. The annual public reporting and recordkeeping burden for this
collection of information is estimated to average 3.9 hours per response. Respondents must
monitor all specified criteria at each affected facility and maintain these records for 5 years.
Burden is defined at 5 CFR 1320.3(b).
7.3.7 Related Federal Rules
The New Source Performance Standards (NSPS) issued in 2012 are currently reducing
VOC emissions from several sources in the oil and natural gas industry In addition to the 2012
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NSPS, there are two National Emission Standards for Hazardous Air Pollutants (NESHAP) rules
that apply to certain equipment and processes in the oil and natural gas sector. These rules, listed
below, address air toxics, primarily benzene, toluene, ethylbenzene and xylenes (collectively
referred to as BTEX) and n-hexane. These two rules, which were updated concurrently with the
2012 NSPS, were promulgated under section 112 of the Clean Air Act and are codified in 40
CFR Part 63:
• Subpart HH - Crude Oil and Natural Gas Production (including processing); and
• Subpart HHH - Natural Gas Transmission and Storage.
Additionally, 40 CFR Part 98 Subpart W is a greenhouse gas reporting requirement that
applies to petroleum and natural gas systems. Owners or operators of facilities that contain
petroleum and natural gas systems and emit 25,000 metric tons or more of GHGs per year from
process operations, stationary combustion, miscellaneous use of carbonates, and other source
categories are required to report emissions from all source categories located at the facility for
which emission calculation methods are defined in the rule. Owners or operators are required to
collect emission data; calculate GHG emissions; and follow the specified procedures for quality
assurance, missing data, recordkeeping, and reporting.
7.3.8 Regulatory Flexibility Alternatives
The Panel agrees that the EPA should explore regulatory alternatives and provide
flexibility where appropriate. This flexibility can lessen impacts to small entities as well as
entities not classified as small.
7.3.8.1 Oil Well Exemptions
SERs encouraged the EPA to exempt stripper wells, low pressure oil wells, and any well
that requires artificial lift. SERs recommended that the EPA establish an overall applicability
threshold based on production, emissions, well depth, well type (horizontal), well pressure,
formation, or revenue to limit potential impact of future regulations on small entities.
The SERs offered several threshold alternatives to be applied to the oil well completion
requirements which would significantly reduce compliance costs and burden to small entities that
the SERs asserted would not affect gas recovery benefits. Some of these comments are described
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below. Advocacy believes the EPA had a greater opportunity to advance the discussion by
evaluating these alternatives through analysis of the available data. Advocacy further believes
that there is enough information to conduct analysis of alternatives now. Advocacy notes that
there are several types of thresholds that could be explored by the EPA, such as average
production of nearby wells (by oil field, reservoir, or basin), well length or depth, and gas and
water pressure characteristics. Advocacy encourages the EPA to do so in the future, in advance
of proposal, to facilitate more informed and productive comments from the public which will
lead to a better rulemaking.
The EPA has production and well characteristic data on thousands of oil wells through
Drillinglnfo, which aggregates all well data in the U.S. reported by operators to state agencies. In
this database, the EPA could develop thresholds to target geographical areas or well
characteristics with greater gas recovery potential than areas or characteristics where costs
imposed would achieve little to no benefit. Advocacy believes the EPA should examine the data
in Drillinglnfo and the studies identified in the White paper for potential alternatives that
minimize small entity costs, while achieving significant methane emission benefits. For example,
Advocacy performed its own preliminary analysis of the Drillinglnfo data, which led us to
recommend a production threshold (see below). Advocacy believes the EPA also should consider
the peer review and public comments on the white paper and reassess the size and diversity of
the oil well completions in a more comprehensive fashion. Advocacy believes the EPA should
have provided additional analysis since the publication of the white paper.
The EPA believes that it has reasonably analyzed the available data for this draft
proposed rule, and sufficiently documented this analysis through the rule, the technical support
document (TSD), and the SBREFA process. However, the EPA notes information gaps and has
requested additional data and information through the public comment process.
Gas to Oil Ratio
Advocacy is concerned that the EPA estimate of ten tons of methane reduction per event
for oil well completions may be significantly overestimated, based on its analysis of the 2012
Drilling Info database and SER comments. The 2012 analysis includes hydraulically fractured oil
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well completions with GORs between 300 and 100,000, whereas the 2011 analysis was limited
to GORs up to 12,500.
The Panel recommends that the EPA continue analyzing current data, and assess the
alternatives mentioned by SERs. In an effort to contribute to the panel process, Advocacy
analyzed the EPA data provided. Advocacy found that geographical patterns and well
characteristics exist in the data to suggest common sense thresholds. While a 300 gas to oil ratio
(GOR) threshold provides some relief for small entities, it is problematic because GOR is not
known at time of fracturing when a completion takes place. Advocacy further recommends that
the EPA develop a scheme based on the well characteristics of nearby wells in the basin or
reservoir to provide an estimate for the GOR parameter. However, the location of the well, and
the drill direction are known parameters that could be used. In concert with these other
considerations, Advocacy recommends the EPA consider a GOR cutoff closer to 900, as one
SER suggested.
The EPA believes that a gas-to-oil ratio (GOR) of 300 scf of gas per barrel of oil
produced is an appropriate threshold for facilities to be subject to the well completion provisions
of the NSPS. The reason for the proposed threshold GOR of 300 is that separators typically do
not operate at a GOR less than 300, which is based on industry experience rather than a vetted
technical specification for separator performance85. Though, in theory, any amount of free gas
could be separated from the liquid, the reality is that this is not practical given the design and
operating parameters of separation units operating in the field. The EPA is soliciting comment on
whether a GOR of 300 is the appropriate applicability threshold. Additionally, the EPA
understands that GOR is not known at the time of well completion, and is soliciting comment on
whether the GOR of nearby wells would be a reliable indicator in determining the GOR of a new
or modified well.
Low Production Wells
When mapping average daily associated gas of 90 Mcf or above (isolating stripper wells)
using county level data, Advocacy found that most (85%) of these greater gas recovery oil well
85 On February 24, 2015, API submitted a comment to the EPA stating that oil wells with GOR values less than 300
do not have sufficient gas to operate a separator.
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completions occur in about a third of the counties analyzed. Advocacy contends that there are
potentially large areas that could be exempted from this requirement without forgoing significant
methane emission reduction, or at least phased in to allow time to design proper data collection.
For example, PIOGA comments report an average gas volume of only 74 MCFD in
Pennsylvania stripper oil wells in contrast to Pennsylvania stripper gas wells averaging 532
MCFD.
The EPA understands that low production wells have inherently low emissions from well
completions and many are owned and operated by small businesses. However, the EPA
recognizes that identification of these wells prior to completion events is difficult, especially
considering that drilling of a low production well may be unintentional and may be infrequent,
but production may nevertheless proceed due to economic reasons. The EPA is soliciting
comment and information on emissions associated with low production wells, characteristics of
these wells and supporting information that would help owners/operators and enforcement
personnel identify these wells prior to completion.
Because of these preliminary findings about low production and a lack of evidence that
there will be sufficient gas recovery, the Panel recommends that the EPA further analyze and
consider exempting low production wells (with an average daily production of less than 15 barrel
equivalents) from a REC or combustion requirement during oil well completions.
Vertical Wells
According to a SER comment, vertical wells lack sufficient wellhead pressure or quantity
of gas to be separated during completion. Advocacy recommends that since the white papers laid
the foundation to the materials prepared for the Panel, the EPA should revisit the information
learned through this process, especially as it relates to the specific characteristics of vertical
wells. Therefore, as a regulatory alternative, Advocacy recommends the EPA consider
exempting vertical wells from oil well completion requirements.
The EPA clarifies that both the 2014 white paper analysis of oil well completions and
Drillinglnfo data analysis include vertical wells that are hydraulically fractured. However, the
EPA understands that there are certain physical well characteristics that may inhibit the operation
of a separator, and notes that the rule does not require RECs where their use is not feasible.
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However, the EPA has not seen sufficient data to support the characterization that a separator
will not be able to function for all or the majority of vertical wells that are hydraulically
fractured. However, the EPA recommends soliciting comment on the types of oil wells that will
not be capable of performing a REC or combusting completion emissions due to technical
considerations such as low pressure or low gas content, or other physical characteristics such as
location, well depth, length of hydraulic fracturing, or drilling direction (e.g., horizontal, vertical,
directional).
Low Pressure Oil Wells
Advocacy recommends that "low pressure wells" should be categorically exempt and
could be based on a threshold sales line/gathering line of approximately 250 psi or a simple
water gradient formula of 0.465 psi/foot. The emissions associated with these types of wells are
so low that even if a separator can be operated for some short period of time, the value of gas
does not exceed the cost associated with bringing equipment to the site. As the SERs indicated,
these oil completion requirements can be very costly on small firms, particularly with respect to
small production wells. The expected gas recovery benefits from oil well completions are
expected to be a small fraction of the benefits obtained by the gas wells under the current version
oftheNSPSrule.
The EPA is aware that oil wells cannot perform a REC if there is not sufficient well
pressure or gas content during the well completion to operate the surface equipment required for
a REC. In the 2012 NSPS the EPA did not require low pressure gas wells to perform REC, but
operators were required to control those well completions using combustion. However, the EPA
recommends soliciting comment on the types of oil wells that will not be capable of performing a
REC or combusting completion emissions due to technical considerations such as low pressure
or low gas content, or other physical characteristics such as location, well depth, length of
hydraulic fracturing, or drilling direction (e.g., horizontal, vertical, directional). The EPA defines
low pressure wells as a well with reservoir pressure and true vertical well depth such that 0.445
times the reservoir pressure (in psia) minus 0.038 times the vertical well depth (in feet) minus
67.578 psia is less than the flow line pressure at the sales meter. The EPA recommends soliciting
comment on whether this definition is appropriate for low pressure oil wells.
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Substitution of Combustion over Green Completion / REC Requirements
Advocacy recommends that the EPA substitute flaring for the green completion
requirement (REC), in addition to the consideration of thresholds. This alternative is much more
cost-effective, and particularly important for small firms to have a lower cost alternative that
achieves a 95% reduction. The PIOGA comments also stated that the use of RECs would
adversely impact the productivity and longevity of the stripper oil wells. Alternatively, the EPA
could require larger firms to perform the RECs, while allowing smaller firms (using a firm
revenue cutoff or other small business size indicator) to combust the remaining gas.
The EPA recommends that RECs be implemented on oil wells, except where their use is
not feasible (e.g., technically infeasible for a separator to function, availability of gathering
lines). Compared to combustion alone, the EPA believes that the combination of REC and
combustion will maximize the recovery of natural resources and minimize venting to the
atmosphere. However, the EPA notes that although the flaring in lieu of RECs may be less
costly, flaring contributes secondary environmental impacts, nuisance impacts to nearby
communities and complicates compliance for owners/operators.
Phase - In for Oil Well Completion Requirements
The Panel recommends that the EPA consider phasing in the well completion
requirement over a period of years. The Panel agrees that the EPA solicit comment on whether
the well completion provisions of the proposed rule can be implemented on the effective date of
the rule in the event of potential shortage of REC equipment and, if not, how a phase in could be
structured. The Panel agrees that a phased in approach could be structured to provide for control
of the potentially highest emitting wells first, with other wells being included at a later date. The
Panel recommends that the EPA solicit comment on whether GOR of the well and production
level of the well should be bases for the phasing of requirements for RECs, and if so, what an
appropriate threshold for phase-in should be.
7.3.8.2 Fugitives - Leak Detection Methods
SERs encouraged the EPA to allow a variety of leak detection technologies, including
Method 21, AVO, and soap testing. The EPA asserts that use of OGI can reduce the amount of
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time necessary to conduct fugitive emissions monitoring since multiple fugitive emissions
components can be surveyed simultaneously, reducing the cost of identifying fugitive emissions
compared to alternative leak detection technologies that require a manual screening of each
fugitive emissions component. Advocacy recommends the EPA propose Method 21 or OGI as
allowable alternatives. The EPA contends that while Method 21 is lacking because it does not
allow the detection of malfunctioning equipment that may not be the focus of the survey, and it is
not as cost-effective as OGI, the Panel recommends the EPA solicits comment on whether to
allow EPA Method 21 as an alternative to OGI for monitoring, including the appropriate EPA
Method 21 level repair threshold. The EPA notes that the proposed rule would allow the use
either OGI or Method 21 for resurvey because the resurvey would focus solely on ensuring
repairs resolved the leak at the individual component.
7.3.8.3 Fugitives - Survey Frequency
SERs recommended leak surveys be conducted no more than once per year. Advocacy
has questions about the costs of repair and the emission reductions that be achieved through
increased survey frequency which Advocacy believes the EPA was unable to address
satisfactorily. Advocacy urges the EPA to improve the record basis for its emission reduction
estimates and the cost of repairs for Method 21 and OGI, in order to permit more informed
comment on the alternatives. Advocacy believes the EPA was unable to adequately explain the
basis for the different repair costs vs. frequency for Method 21 and OGI86, or the basis for the
40/60/80% emission reductions based on increasing survey frequency from annual to quarterly.87
The EPA determined that semiannual monitoring will result in identification and repair of
significant fugitive emissions from components, and that using OGI, an operator can survey
multiple fugitive emissions components simultaneously reducing the cost of identifying fugitive
emissions. Additionally, if fugitive emissions are detected at less than one percent of the fugitive
6At this time, the EPA shows annual repair costs that increase linearly with survey frequency for OGI, but are static
for Method 21. For Method 21, the EPA applied the same repair costs whether the frequency was annual,
semiannual or quarterly. For OGI, EPA used double the repair costs for semiannual, and four times the repair
costs for quarterly. Advocacy believes this could lead to a bias in an evaluation of one method vs. the other.
87 Advocacy was also disappointed that EPA was unable to share with the SERs more information that would have
help the SERs formulate their recommendations (including some of the issues addressed above). The EPA
believes the background documents created for the SERs were thorough and accurate, and transparently
presented the data and data sources used in the analysis for the proposed rule. The documents are additionally
available for public review in the docket for the proposed rule.
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emission components at a well site during two consecutive semiannual monitoring surveys, the
proposed rule allows for the monitoring survey frequency for that well site to be reduced to
annually. Advocacy had no information upon which to base a recommendation related to the
proportion of leaking components, but supports analysis of such an approach. Advocacy also
recommends that the EPA provide more analysis and factual foundation for the record to allow
commenters to provide more informed advice.
The Panel agrees that the EPA should solicit comment on an alternate proposal option
based on an initial annual survey frequency. The Panel recommends the EPA solicit comment on
the appropriateness of semiannual monitoring frequency and the proposed provisions for
increasing and decreasing the monitoring frequency.
7.3.8.4 Fugitive Emissions at Well Sites
The Panel recommends not requiring fugitive emission surveys at well production sites,
unless there are potentially significant sources of emissions, such as storage tanks. The Panel
further agrees that well sites with low production wells (i.e., a well with an average daily
production of 15 barrel equivalents or less) should not require fugitive emission surveys.
7.3.8.5 Fugitive Emissions at Production and Processing Sites, and Compressor Stations at
Transmission and Storage Sites
Under Subpart W, gas production and processing sites and compressor stations at
transmission and storage sites are required to annually monitor for fugitive emissions and to
quantify such emissions. The only missing regulatory component to be considered is to add a
requirement to repair detected leaks as appropriate. This is already covered by the May 2015
INGAA Directed Inspection and Maintenance voluntary Program for Transmission and Storage
Compressor Stations. The EPA is already considering this program88 in its recent request for
comment on the voluntary methane reduction program for the oil and gas sector. Advocacy
recommends that the EPA retain the annual requirement, as Advocacy believes this requirement
is entirely duplicative of a fugitives survey requirement, and consider the specific repair
88 US EPA. Natural Gas STAR Methane Challenge Program: Proposed Framework, slide 17 states, "EPA has
received, and is considering, a proposal to structure BMP coverage of natural gas transmission and storage
compressor stations as a Directed Inspection and Maintenance Program."
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requirements for repair identification and repair delay in the DI&M voluntary program as the
components of a mandatory program. Furthermore, the EPA's most recent evaluation of the
survey cost-effectiveness shows that annual surveys are more cost-effective than semi-annual
surveys. Therefore, the Panel recommends the EPA propose options based on semi-annual and
annual monitoring. Advocacy recommends that the EPA should also consider allowing each
facility to tailor the specific program to site-specific considerations, rather than apply the same
requirements uniformly to each plant. The EPA recognizes that Subpart W serves as an
emissions inventory, while this rule's intent is to minimize pollution. The EPA believes that the
additional survey with semiannual OGI monitoring provides additional leak detection, and cost-
effective emission reductions. The EPA recognizes that fugitive emissions may be
underestimated based on emerging studies and will continue to evaluate these studies. The Panel
recommends the EPA propose an alternate option based on an initial annual frequency for well
sites. The Panel recommends that the EPA continue to consider the INGAA DI&M
recommendations for leak repairs in the rulemaking.
7.3.8.6 Well Site Compressors
SERs encouraged the EPA to exempt well site compressors as they are typically rental
units and have irregular service time, and regulation could be cost prohibitive. The Panel agrees
that emissions from well site compressors were extremely low and that cost of control of these
compressors would not be reasonable. The Panel recommends that the EPA maintain the
exemption for well site compressors.
7.3.8.7 Pneumatic Pumps
SERs encouraged the EPA to exempt pneumatic pumps if controls were not already in
place. The Panel agrees that combustion controls should only be required if a control is required
for another source. The Panel recommends the EPA exempt pneumatic pumps without a control
device already located on site.
7.3.8.8 Reciprocating Compressors
The Panel supports the EPA proposal to require replacement of rod packing every 26,000
hours or 3 years in lieu of monitoring hours. The Panel also supports the further consideration of
the alternative developed in the Natural Gas Star Program for condition-based maintenance.
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Advocacy recommends the EPA should carefully study the INGAA recommendations for
condition-based maintenance for rod packing as an alternative to maintaining or replacing rod
packing on a prescribed schedule.89
The EPA recommends that the draft proposed rule retain the rod packing replacement
options and the option to route the rod packing emissions to a process through a closed vent
system under negative pressure.
7.3.8.9 Centrifugal Compressors
Advocacy recommends that the EPA reconsider the requirement of requiring capture and
combustion of gas emissions from wet seal compressors whose emissions don't differ that much
from dry seal compressors, according to INGAA. Advocacy is concerned that requiring
combustion at compressor stations would prove to be unpopular with the surrounding
neighborhood. This requirement would convert an otherwise unobtrusive structure in the
neighborhood into a constant source of combustion and a source of air pollution.
The EPA recommends retaining the requirement for a 95% emissions reduction from wet
seal compressors, which can be achieved by capturing and routing the emissions utilizing a cover
and closed vent system to a control device, or routing the captured emissions to a process. The
EPA notes that dry seal compressors are not affected facilities in the draft proposed rule because
of their inherently low emissions. The EPA also notes that many of these combustors are
enclosed and will be innocuous to the surrounding neighborhood. In addition, the gas liberated
from the barrier fluid during degassing is very clean natural gas, and the combustor is required
under the NSPS to burn cleanly with no visible emissions.
7.3.8.10 Pneumatic Controllers
The Panel agrees with the EPA's recommendation that low-bleed pneumatic controllers
be required in place of high-bleed controllers (i.e., natural gas bleed rate not to exceed 6 scfh).
The Panel recommends the rule continue to treat low-bleed pneumatic controllers as not affected
facilities except at natural gas processing plants, where zero bleed pneumatic controllers are
considered BSER.
1 See INGAA comment on 40 CFR 60 Part OOOO. EPA-HQ-OAR-2010-0505-4104
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7.3.8.11 Recordkeeping and Reporting for High Bleed Controllers
The EPA recommends that owners and operators continue to be permitted to use high
bleed controllers needed for specific functional purposes, but require recordkeeping to document
the justification. The Panel agrees that recordkeeping and reporting requirements should be
minimized wherever possible. However, the Panel notes that a recordkeeping and reporting
requirement that asks companies to justify and document their need for continuous high bleed
devices has caused many companies to reevaluate their need for and change out unnecessary
high bleed pneumatic controllers.
7.3.8.12 Liquids Unloading
Based on the information and data available to the EPA during development of the 2012
NSPS, the Panel agrees that control of liquids unloading emissions is not appropriate at this time.
However, the EPA believes that the emissions from liquids unloading operations are significant,
and so the Panel recommends that the EPA continue to study this issue and solicit information
and data supporting demonstrated control technologies or management practices for reducing
these emissions.
7.4 Employment Impact Analysis
In addition to addressing the costs and benefits of the proposed rule, the EPA has
analyzed the impacts of this rulemaking on employment, which are presented in this section.90
While a standalone analysis of employment impacts is not included in a standard cost-benefit
analysis, such an analysis is of particular concern in the current economic climate given
continued interest in the employment impact of regulations such as this proposed rule. Executive
Order 13563, states, "Our regulatory system must protect public health, welfare, safety, and our
environment while promoting economic growth, innovation, competitiveness, and job creation."
91 A discussion of compliance costs, including reporting and recordkeeping requirements, is
included in Section 3of this RIA. This analysis uses detailed engineering information on labor
90
91
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).
Executive Order 13563 (January 21, 2011). Improving Regulation and Regulatory Review. Section 1. General
Principles of Regulation, Federal Register, Vol. 76, Nr. 14, p. 3821.
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requirements for each of the control strategies identified in this proposed rale in order to estimate
partial employment impacts for affected entities in the oil and gas industry. These bottom-up,
engineering-based estimates represent only one portion of potential employment impacts within
the regulated industry, and do not represent estimates of the net employment impacts of this rule.
First, this section presents an overview of the various ways that environmental regulation can
affect employment. The EPA continues to explore the relevant theoretical and empirical
literature and to seek public comments in order to ensure that the way the EPA characterizes the
employment effects of its regulations is valid and informative. The section concludes with partial
employment impact estimates that rely on engineering-based information for labor requirements
for each of the control strategies identified by the proposed rale.
7.4.1 Employment Impacts of Environmental Regulation
From an economic perspective labor is an input into producing goods and services; if a
regulation requires that more labor be used to produce a given amount of output, that additional
labor is reflected in an increase in the cost of production. Moreover, when the economy is at full
employment, we would not expect an environmental regulation to have an impact on overall
employment because labor is being shifted from one sector to another. On the other hand, in
periods of high unemployment, employment effects (both positive and negative) are possible.
For example, an increase in labor demand due to regulation may result in a short-term net
increase in overall employment as workers are hired by the regulated sector to help meet new
requirements (e.g., to install new equipment) or by the environmental protection sector to
produce new abatement capital resulting in hiring previously unemployed workers. When
significant numbers of workers are unemployed, the opportunity costs associated with displacing
jobs in other sectors are likely to be higher. And, in general, if a regulation imposes high costs
and does not increase the demand for labor, it may lead to a decrease in employment. The
responsiveness of industry labor demand depends on how these forces all interact. Economic
theory indicates that the responsiveness of industry labor demand depends on a number of
factors: price elasticity of demand for the product, substitutability of other factors of production,
elasticity of supply of other factors of production, and labor's share of total production costs.
Berman and Bui (2001) put this theory in the context of environmental regulation, and suggest
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that, for example, if all firms in the industry are faced with the same compliance costs of
regulation and product demand is inelastic, then industry output may not change much at all.
Regulations set in motion new orders for pollution control equipment and services. New
categories of employment have been created in the process of implementing environmental
regulations. When a regulation is promulgated, one typical response of 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 the compliance obligation. Environmental
regulation may increase revenue and employment in the environmental technology industry.
While these increases represent gains for that industry, they translate into costs to the regulated
industries required to install the equipment.
Environmental regulations support employment in many basic industries. Regulated firms
either hire workers to design and build pollution controls directly or purchase pollution control
devices from a third party for installation. Once the equipment is installed, regulated firms hire
workers to operate and maintain the pollution control equipment—much like they hire workers
to produce more output. In addition to the increase in employment in the environmental
protection industry (via increased orders for pollution control equipment), environmental
regulations also support employment in industries that provide intermediate goods to the
environmental protection industry. The equipment manufacturers, in turn, order steel, tanks,
vessels, blowers, pumps, and chemicals to manufacture and install the equipment. Currently in
most cases there is no scientifically defensible way to generate sufficiently reliable estimates of
the employment impacts in these intermediate goods sectors.
Berman and Bui (2001) demonstrate using standard neoclassical microeconomics that
environmental regulations have an ambiguous effect on employment in the regulated sector. The
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 (NOx)
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emissions affects manufacturing employment in the South Coast Air Quality Management
District (SCAQMD), which incorporates Los Angeles and its suburbs. During the time frame of
their study, 1979 to 1992, the SCAQMD enacted some of the country's most stringent air quality
regulations. Using SCAQMD's local air quality regulations, Berman and Bui identify the effect
of environmental regulations on net employment in the regulated industries.92 The authors find
that "while regulations do impose large costs, they have a limited effect on employment"
(Berman and Bui, 2001, p. 269). Their conclusion is that local air quality regulation "probably
increased labor demand slightly" but that "the 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).93
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 employment, but this area of the literature has been
growing. As stated previously in this RIA section, empirical results from Berman and Bui (2001)
suggest that new or more stringent environmental regulations do not have a substantial impact on
net employment (either negative or positive) in the regulated sector. Similarly, Ferris,
Shadbegian, and Wolverton (2014) also find that regulation-induced net employment impacts are
close to zero in the regulated sector. Furthermore, Gray et al (2014) find that pulp mills that had
to comply with both the air and water regulations in the EPA's 1998 "Cluster Rule" experienced
relatively small and not always statistically significant, decreases in employment. Nevertheless,
other empirical research suggests that more highly regulated counties may generate fewer jobs
than less regulated ones (Greenstone 2002, Walker 2011). However, the methodology used in
these two studies cannot estimate whether aggregate employment is lower or higher due to more
stringent environmental regulation, it can only imply that relative employment growth in some
sectors differs between more and less regulated areas. List et al. (2003) find some evidence that
this type of geographic relocation, from more regulated areas to less regulated areas may be
occurring. Overall, the peer-reviewed literature does not contain evidence that environmental
92 Berman and Bui include over 40 4-digit SIC industries in their sample.
93 Including the employment effect of exiting plants and plants dissuaded from opening will increase the estimated
impact of regulation on employment.
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regulation has a large impact on net employment (either negative or positive) in the long run
across the whole economy.
While the theoretical framework laid out by Berman and Bui (2001) still holds for the
industries affected under these emission guidelines, important differences in the markets and
regulatory settings analyzed in their study and the setting presented here lead us to conclude that
it is inappropriate to utilize their quantitative estimates to estimate the employment impacts from
this proposed regulation. In particular, the industries used in these two studies as well as the
timeframe (late 1970's to early 1990's) are quite different than those in this proposed NSPS.
Furthermore, the control strategies analyzed for this RIA include implementing RECs, reducing
fugitive emissions, and reducing emissions from pneumatic controllers, pumps, and reciprocating
and centrifugal compressors, which are very different than the control strategies examined by
Berman and Bui.94 For these reasons we conclude there are too many uncertainties as to the
transferability of the quantitative estimates from Berman and Bui to apply their estimates to
quantify the employment impacts within the regulated sectors for this regulation, though these
studies have usefulness for qualitative assessment of employment impacts.
The preceding sections have outlined the challenges associated with estimating net
employment effects in the regulated sector and in 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 the macro-economy. Given the difficulty with
estimating national impacts of regulations, the EPA has not generally estimated economy-wide
employment impacts of its regulations in its benefit-cost analyses. However, in its continuing
effort to advance the evaluation of costs, benefits, and economic impacts associated with
environmental regulation, the EPA has formed a panel of experts as part of the EPA's Science
Advisory Board (SAB) to advise the EPA on the technical merits and challenges of using
economy-wide economic models to evaluate the impacts of its regulations, including the impact
on net national employment.95 Once the EPA receives guidance from this panel it will carefully
94 More detail on how emission reductions expected from compliance with this rule can be obtained can be found in
Section 3 of this RIA.
95 For further information see:
http://yosemite.epa.gOv/sab/sabproduct.nsf/0/07E67CF77B54734285257BB0004F87ED7OpenDocument
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consider this input and then decide if and how to proceed on economy-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 gas industry. As well as producing much of the
U.S. energy supply, the oil and natural gas industry directly employs a significant number of
people. Table 2-17 shows employment in six oil and natural gas-related NAICS codes from 1990
to 2013.96 The overall trend shows a decline in total industry employment throughout the 1990s,
hitting a low of 314,000 in 1999, but rebounding to a 2013 peak of 620,000. Crude Petroleum
and Natural Gas Extraction (NAICS 211111) and Support Activities for Oil and Gas Operations
(NAICS 213112) employ the majority of workers in the industry. From 1990 to 2013, average
wages for the oil and natural gas industry have increased. Table 2-18 shows real wages (in 2012
dollars) from 1990 to 2013 for the NAICS codes associated with the oil and natural gas industry.
The focus of this part of the analysis is on labor requirements related to the compliance
actions for the proposed rule, of the affected entities within the oil and natural gas sector. We do
not estimate any potential changes in labor outside of the affected sector, and, due to data and
methodology limitations, we do not estimate net employment impacts for the affected sector,
apart from the partial estimate of the labor requirements related to control strategies. This
analysis estimates the labor required to the install, operate, and maintain control equipment and
activities, as well as to perform new reporting and recordkeeping requirements.
It is important to highlight that unlike the typical case where to reduce output negative
production externality (i.e., emissions) a firm often has to reduce production, many of the
emission controls required by the proposed NSPS will simultaneously increase production and
reduce negative externalities. That is, these controls jointly produce environmental
improvements and increase output in the regulated sector. New labor associated with
implementing these controls to comply with the new regulations can also be viewed as additional
labor increasing output while reducing undesirable emissions. To the extent, however, that these
' NAICS 211111, 21112, 213111, 213112, 486110, and 486210.
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rales 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 potential adverse effects on the labor market due to data and
theoretical challenges, as described above.
No estimates of the labor used to manufacture or assemble pollution control equipment or
to supply the materials for manufacture or assembly are included because the EPA does not
currently have this information. The labor requirements analysis uses a bottom-up engineering-
based methodology to estimate employment impacts. The engineering cost analysis summarized
in Chapter 3 of this RIA includes estimates of the labor requirements associated with
implementing the regulations. Each of these labor changes may either be required as part of an
initial effort to comply with the new regulation or required as a continuous or annual effort to
maintain compliance. We estimate up-front and continual, annual labor requirements by
estimating hours of labor required and converting this number to full-time equivalents (FTEs) by
dividing by 2,080 (40 hours per week multiplied by 52 weeks). We note that this type of FTE
estimate cannot be used to make assumptions about the specific number of people involved or
whether new jobs are created for new employees.
The results of this employment analysis of the proposed NSPS are presented in Tables 7-
16 through Table 7-19 for 2020 and 2025 for individual sources regulated under this proposal.
Table 7-20 presents summary-level labor impacts for all sources. The tables break down the
installation, operation, and maintenance estimates by type of pollution control evaluated in the
RIA and present both the estimated hours required and the conversion of this estimate to FTE.
The labor information is based upon the cost analysis presented in the TSD that supports this
proposal, based upon analysis presented in the RIA developed for the 2012 NSPS and NESHAP
Amendments for the Oil and Natural Gas Sector (U.S. EPA, 2012). In addition, for the proposed
NSPS, reporting and recordkeeping requirements were estimated for the entire rale rather than by
anticipated control requirements; the reporting and recordkeeping estimates are consistent with
estimates the 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.
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Table 7-15 presents estimates labor requirements for hydraulic ally fractured oil well
completions. The REC and completion combustion requirements are associated with certain new
and existing oil well completions. While individual completions occur over a short period of
time (days to a few weeks), new wells and other existing wells are completed annually. Because
of these reasons, we assume the REC-related labor requirements are annual.
The per-unit estimates of one-time labor requirements associated with implementing
RECs and completion combustion are drawn from the labor requirements estimated for
implementing RECs on hydraulically fractured well completions in EPA (2012). However, the
labor requirements in that report were based upon a completion that is assumed to last seven days
(218 hours per completion for a REC or 22 hours labor per completion for completion
combustion). In this analysis, completion events for hydraulically fractured oil wells are assumed
to last three days, so we multiply the seven-day requirements by 3/7 (93 hours per completion for
a REC or 9 hours labor per completion for completion combustion).
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Table 7-15 Estimates of Labor Required to Comply with Proposed NSPS for
Hydraulically Fractured Oil Well Completions, 2020 and 2025
Emissions
Source
Emissions
Control
Projected
No. of
Incr.
Affected
Units
Per-unit
One-
time
Labor
Est.
(hrs)
Per-unit
Annual
Labor
Est.
(hrs)
Total
One-
Time
Labor
Estimate
(hrs)
Total
Annual
Labor
Estimate
(hrs)
One-
time Annual
FTE FTE
2020
Hydraulically Fractured and Re-fractured
Development
Oil Wells
Wildcat and
Delineation
Oil Wells
Total
Reduced
Emission
Completion
Completion
Combustion
6,903
7,773
14,676
Oil Well Completions
0
0
N/A
93
9
N/A
0
0
0
644,937
73,289
718,227
0 310
0 35
0 345
2025
Hydraulically Fractured and Re-fractured
Development
Oil Wells
Wildcat and
Delineation
Oil Wells
Total
Reduced
Emission
Completion
Completion
Combustion
6,901
8,066
14,967
Oil Well Completions
0
0
N/A
93
9
N/A
0
0
0
644,751
76,055
720,806
0 310
0 37
0 347
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per-unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum
due to independent rounding.
Table 7-16 and Table 7-17 present estimates of labor requirements for the low and the
high impacts cases for fugitive emissions. Consistent with the cost estimates for fugitive
emissions presented in the TSD, we estimate labor associated with company-level activities and
activities at field sites. Company-level activities include one time activities such as planning the
company's fugitive emissions program and annual requirements such as reporting and
recordkeeping. Field-level activities include semiannual inspection and repair of leaks as
proposed. It is important to note, however, that the compliance costs estimates for leak
inspection were based upon an estimate of the costs to hire a contractor to provide the inspection
service, but the source providing this information does not have a breakdown of the labor
component of the rental cost. As a result, the labor requirements for the fugitives program are
likely underestimates.
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Table 7-16 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive
Emissions, Low Impact Case, 2020 and 2025
Emissions
Emissions Source/ Control
Projected
No. of
Incr.
Affected
Units
Per-unit
One-
time
Labor
(hrs)
Per-unit
Annual
Labor
(hrs)
Total
One-
Time
Labor
(hrs)
Total
Annual
Labor (hrs)
One-
time
FTE
Annual
FTE
2020
Well Sites
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Gathering and Boosting Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Transmission Compressor Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Storage Compressor Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Total
605
13,303
259
259
6
6
15
15
13,583
118.0
0.0
118.0
0.0
118.0
0.0
118.0
0.0
N/A
0.0
14.1
0.0
108.7
0.0
108.7
0.0
212.9
N/A
71,352
0
30,562
0
708
0
1,770
0
104,392
0
187,717
0
28,141
0
652
0
3,193
219,702
34
0
15
0
0
0
1
0
50
0
90
0
14
0
0
0
2
106
2025
Well Sites
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Gathering and Boosting Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Transmission Compressor Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Storage Compressor Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Total
1,004
139,108
259
1,554
6
36
15
90
140,788
118.0
5.4
118.0
0.0
118.0
0.0
118.0
0.0
N/A
0.0
14.1
0.0
108.7
0.0
108.7
0.0
212.9
N/A
118,429
0
30,562
0
708
0
1,770
0
151,469
0
1,962,940
0
168,844
0
3,911
0
19,160
2,154,855
57
0
15
0
0
0
1
0
73
0
944
0
81
0
2
0
9
1,036
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum
due to independent rounding.
7-42
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Table 7-17 Estimates of Labor Required to Comply with Proposed NSPS for Fugitive
Emissions, High Impact Case, 2020 and 2025
Emissions
Emissions Source/ Control
Projected
No. of
Incr.
Affected
Units
Per-unit
One-
time
Labor
(hrs)
Per-unit
Annual
Labor
(hrs)
Total
One-
Time
Labor
(hrs)
Total
Annual
Labor (hrs)
One-
time
FTE
Annual
FTE
2020
Well Sites
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Gathering and Boosting Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Transmission Compressor Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Storage Compressor Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Total
1,004
22,080
259
259
6
6
15
15
22,360
118.0
0.0
118.0
0.0
118.0
0.0
118.0
0.0
N/A
0.0
14.1
0.0
108.7
0.0
108.7
0.0
212.9
N/A
118,429
0
30,562
0
708
0
1,770
0
151,469
0
311,569
0
28,141
0
652
0
3,193
343,555
57
0
15
0
0
0
1
0
73
0
150
0
14
0
0
0
2
165
2025
Well Sites
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Gathering and Boosting Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Transmission Compressor Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Storage Compressor Stations
Company-level Semiannual
Activities Monitoring/
Site-level Activities Maintenance
Total
1,004
139,108
259
1,554
6
36
15
90
140,788
118.0
5.4
118.0
0.0
118.0
0.0
118.0
0.0
N/A
0.0
14.1
0.0
108.7
0.0
108.7
0.0
212.9
N/A
118,429
0
30,562
0
708
0
1,770
0
151,469
0
1,962,940
0
168,844
0
3,911
0
19,160
2,154,855
57
0
15
0
0
0
1
0
73
0
944
0
81
0
2
0
9
1,036
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum
due to independent rounding.
7-43
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Most labor required for fugitive emissions is needed at well sites in the field, which
number in the thousands. Note that the labor requirements estimates increase from 2020 to 2025
as the number of sites regulated under the proposed NSPS accumulates.
Table 7-18 presents labor requirement estimates for reciprocating and centrifugal
compressors. Like the estimates for completions, the per unit labor estimates were based on EPA
(2012). As relatively little labor is required for reciprocating compressors and relatively few
affected centrifugal compressors are expected in the future, the estimates of both one-time and
on-going labor requirements for compressor requirements are minimal.
Table 7-18 Estimates of Labor Required to Comply with Proposed NSPS for
Reciprocating and Centrifugal Compressors, 2020 and 2025
Emissions Source
Emissions
Control
Projected
No. of
Incr.
Affected
Units
Per-unit
One-
time
Labor
Est.
(hrs)
Total
Per-unit One-
Annual Time
Labor Labor
Est. Estimate
(hrs) (hrs)
Total
Annual
Labor
Estimate
(hrs)
One-
time
FTE
Annual
FTE
2020
Compressors
Reciprocating
Centrifugal
Total
Monitoring
and
Maintenance
Route to
Control
67
1
68
1
355
N/A
1 67
0 355
N/A 422
67
0
67
0.0
0.2
0.2
0.0
0.0
0.0
2025
Compressors
Reciprocating
Centrifugal
Total
Monitoring
and
Maintenance
Route to
Control
402
6
408
1
355
N/A
1 67
0 355
N/A 422
402
0
402
0.0
0.2
0.2
0.2
0.0
0.2
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum
due to independent rounding.
Table 7-19 presents the labor requirement estimates for requirements applying to
pneumatic controllers and pneumatic pumps. Note that pneumatic controllers have no one-time
or continuing labor requirements. While the controls do require labor for installation, operation,
and maintenance, the required labor is less than that of the controllers that would be used absent
7-44
-------
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 7-19 Estimates of Labor Required to Comply with Proposed NSPS for Pneumatic
Controllers and Pumps, 2020 and 2025
Emissions
Source
Emissions
Control
Projected
No. of
Incr.
Affected
Units
Per-unit
One-
time
Labor
Est.
(hrs)
Per-unit
Annual
Labor
Est.
(hrs)
Total
One-
Time
Labor
Estimate
(hrs)
Total
Annual
Labor
Estimate
(hrs)
One-
time Annual
FTE FTE
2020
Pneumatic
Controllers
Pneumatic
Pumps
Emissions
Limit
Route to
Control
210
2,962
0
N/A
0
N/A
0
N/A
0
N/A
0 0
N/A N/A
2025
Pneumatic
Controllers
Pneumatic
Pumps
Emissions
Limit
Route to
Control
1,260
17,772
0
N/A
0
N/A
0
N/A
0
N/A
0 0
N/A N/A
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum
due to independent rounding.
Table 7-20 presents the labor estimates across all emissions sources. Two main categories
contain the majority of the labor requirements for the proposed NSPS: implementing reduced
emissions completions (REC) at hydraulically 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 are created for new employees, versus displacing jobs from other
sectors of the economy.
7-45
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Table 7-20 Estimates of Labor Required to Comply with Proposed NSPS, 2020 and 2025
Projected No.
of
Emissions Source Incrementally
Affected Units
(2020)
Total One-
Time Labor
Estimate
(hours)
Total
Annual
Labor
Estimate
(hours)
One-time
FTE
Annual
FTE
2020
Hydraulically Fractured and Re-
fractured Oil Well Completions
Fugitive Emissions
Pneumatic Controllers
Pneumatic Pumps
Reciprocating Compressors
Centrifugal Compressors
Reporting and Recordkeeping
Requirements
Total
15,000
14,000 to
22,000
210
3,000
67
1
All
31,000 to
40,000
0
100,000 to
150,000
0
N/A
67
360
0
100,000 to
150,000
720,000
220,000 to
340,000
0
N/A
67
0
40,000
980,000 to
1,100,000
0
50 to 73
0
N/A
0
0
0
50 to 73
350
110 to 170
0
N/A
0
0
19
470 to 530
2025
Hydraulically Fractured and Re-
fractured Oil Well Completions
Fugitive Emissions
Pneumatic Controllers
Pneumatic Pumps
Reciprocating Compressors
Centrifugal Compressors
Reporting and Recordkeeping
Requirements
Total
15,000
86,000 to
140,000
1,300
18,000
400
6
All
120,000 to
180,000
0
100,000 to
150,000
0
N/A
67
360
0
100,000 to
150,000
720,000
1,400,000 to
2,200,000
0
N/A
400
0
120,000
2,200,000 to
3,000,000
0
50 to 73
0
N/A
0
0
0
50 to 73
350
660 to 1,000
0
N/A
0
0
58
1,100 to
1,400
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by the
per unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Rounded to two
significant digits. Totals may not sum due to independent rounding.
7.5 References
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Gray, W.B., RJ. Shadbegian, C. Wang, and M. Meral. 2014. "Do EPA Regulations Affect Labor
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TT ., j „, , Office of Air Quality Planning and _, U1. ,. XT
United States Qt H H Publication No.
Environmental TT ltu ,„ Standards . EPA-452/R-15-002
„ , ,. . Health and Environmental Impacts Division . ,-AIC
Protection Agency _ , _. , _ , ,T_ August 2015
& J Research Triangle Park, NC &