Regulatory Impact Analysis of the
Final Oil and Natural Gas Sector: Emission
Standards for New, Reconstructed, and
Modified Sources
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EPA-452/R-16-002, May 2016
Regulatory Impact Analysis of the Final Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources
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 Dr.
Beth Miller, U.S. Environmental Protection Agency, Office of Air and Radiation, Research
Triangle Park, North Carolina 27711 (email: miller.elizabeth@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 vn
LIST OF FIGURES ix
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 SUMMARY OF NSPS IMP ACTS CHANGES FROM THE PROPOSAL RIA 1-10
1.6 ORGANIZATION OF THIS REPORT 1-12
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 2-4
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 2-21
2.4.4 International Trade 2-25
2.4.5 Forecasts 2-27
2.5 INDUSTRY COSTS 2-32
2.5.1 Finding Costs 2-32
2.5.2 Lifting Costs 2-33
2.5.3 Operating and Equipment Costs 2-35
2.6 FIRM CHARACTERISTICS 2-37
2.6.1 Ownership 2-37
2.6.2 Size Distribution of Firms in Affected NAICS 2-38
2.6.3 Trends in National Employment and Wages 2-39
2.6.4 Horizontal and Vertical Integration 2-41
2.6.5 Firm-level Information 2-43
2.6.6 Financial Performance and Condition 2-3
2.7 REFERENCES 2-7
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 3-6
3.4.2 Projection of Incrementally Affected Facilities 3-8
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3.4.3 Emissions Reductions 3-12
3.4.4 Product Recovery 3-13
3.4.5 Engineering Compliance Costs 3-15
3.4.6 Comparison of Regulatory Alternatives 3-17
3.5 ENGINEERING COST SENSITIVITY ANALYSIS 3-19
3.5.1 Compliance Costs Estimated Using 3 and? Percent Discount Rates 3-19
3.5.2 Sensitivity of Compliance Costs to Natural Gas Prices 3-20
3.6 DETAILED IMPACTS TABLES 3-22
4 BENEFITS OF EMISSIONS REDUCTIONS 4-1
4.1 INTRODUCTION 4-1
4.2 EMISSION REDUCTIONS FROM THE FINAL NSPS 4-4
4.3 METHANE CLIMATE EFFECTS AND VALUATION 4-5
4.4 VOC AS A PM2.5 PRECURSOR 4-20
4.4.1 PM2.5 Health Effects and Valuation 4-20
4.4.2 Organic PM Welfare Effects 4-24
4.4.3 Visibility Effects 4-25
4.5 VOC AS AN OZONE PRECURSOR 4-25
4.5.1 Ozone Health Effects and Valuation 4-26
4.5.2 Ozone Vegetation Effects 4-27
4.5.3 Ozone Climate Effects 4-27
4.6 HAZARDOUS AIR POLLUTANT (HAP) BENEFITS 4-28
4.6.1 Benzene 4-33
4.6.2 Toluene 4-34
4.6.3 Carbonyl Sulfide 4-35
4.6.4 Ethylbenzene 4-35
4.6.5 Mixed Xylenes 4-36
4.6.6 n-Hexane 4-37
4.6.7 Other Air Toxics 4-37
4.7 SECONDARY AIR EMISSIONS IMPACTS 4-37
4.8 REFERENCES 4-41
5 COMPARISON OF BENEFITS AND COSTS 5-1
5.1 COMPARISON OF BENEFITS AND COSTS ACROSS REGULATORY OPTIONS 5-1
5.2 UNCERTAINTIES AND LIMITATIONS 5-4
6 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS 6-1
6.1 INTRODUCTION 6-1
6.2 ENERGY MARKETS IMPACTS ANALYSIS 6-1
6.2.1 Description of the Department of Energy National Energy Modeling System 6-2
6.2.2 Inputs to National Energy Modeling System 6-3
6.2.3 Energy Markets Impacts 6-7
6.3 FINAL REGULATORY FLEXIBILITY ANALYSIS 6-10
6.3.1 Reasons why the Action is Being Considered 6-11
6.3.2 Significant Issues Raised 6-11
6.3.3 Small Business Administration Comments 6-15
6.3.4 Description and Estimate of Affected Small Entities 6-15
6.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements 6-18
6.3.6 Regulatory Flexibility Alternatives 6-24
6.4 EMPLOYMENT IMPACT ANALYSIS 6-26
6.4.1 Employment Impacts of Environmental Regulation 6-26
6.4.2 Labor Estimates Associated with Final Requirements 6-30
6.5 REFERENCES 6-37
VI
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LIST OF TABLES
Table 1-1 Emissions Sources and Controls Evaluated 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$)
1-8
Table 1-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2 (Finalized Option) in 2020
and 2025 (2012$) 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, 1990-2014 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 U.S. Average First Purchase Price,
1990-2014 2-14
Table 2-5 Natural Gas Production and Well Productivity, 1990-2014 2-16
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 2-19
Table 2-8 U.S. Oil and Natural Gas Pipeline Mileage, 2010-2014 2-21
Table 2-9 Crude Oil Consumption by Sector, 1990-2012 2-22
Table 2-10 Natural Gas Consumption by Sector, 1990-2014 2-24
Table 2-11 Total Crude Oil and Petroleum Products Trade (Million Bbl), 2-26
Table 2-12 Natural Gas Imports and Exports, 1990-2014 2-27
Table 2-13 Forecast of Total Successful Wells Drilled, Lower 48 States, 2010-2040 2-28
Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2012-2040 2-29
Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price 2012-2040 2-31
Table 2-16 SBA Size Standards and Size Distribution of Oil and Natural Gas Firms 2-39
Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-2014 2-40
Table 2-18 Oil and Natural Gas Industry Average Wages by NAICS, 1990-2014 (2012 dollars) 2-41
Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012 2-44
Table 2-20 Top 20 Natural Gas Processing Firms (Based on Throughput), 2009 2-2
Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2014 2-3
Table 2-22 Selected Financial Items from Income Statements (B illion 2008 Dollars) 2-5
Table 2-23 Return on Investment for Lines of Business (all FRS), for 1998, 2003, 2008, and 2009 (percent)... 2-6
Table 2-24 Income and Production Taxes, 1990-2009 (Million 2008 Dollars) 2-7
Table 3-1 Emissions Sources and Controls Evaluated for the NSPS 3-7
Table 3-2 Incrementally Affected Sources under Final NSPS, 2016 to 2025 on an Annual Basis 3-10
Table 3-3 Total Number of Affected Sources for the NSPS in 2020 and 2025 3-11
Table 3-4 Emissions Reductions for Final NSPS Option 2, 2020 and 2025 3-13
Table 3-5 Estimated Natural Gas Recovery (Mcf) for selected Option 2 in 2020 and 2025 3-15
Table 3-6 Engineering Compliance Cost Estimates for Final NSPS Option 2 in 2020 and 2025 (millions 2012$)
3-16
Table 3-7 Comparison of Regulatory Alternatives 3-18
Table 3-11 Annualized Costs using 3 and 7 Percent Discount Rates for Final NSPS Option 2 in 2020 and 2025
(millions 2012$) 3-19
Table 3-12 Annualized Costs Using Natural Gas Prices from $2 to $5 per Mcf 3-21
Table 3-13 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020 3-23
Table 3-14 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025 3-24
Table 3-15 Incrementally Affected Units, Emissions Reductions and Costs, Selected Option 2, 2020 3-25
Table 3-16 Incrementally Affected Units, Emissions Reductions and Costs, Selected Option 2, 2025 3-26
Table 3-17 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020 3-27
Table 3-18 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025 3-28
Table 4-1 Climate and Human Health Effects of Emission Reductions from this Rule 4-2
Table 4-2 Direct Emission Reductions across NSPS Regulatory Options in 2020 and 2025 4-5
Vll
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Table 4-3 Social Cost of Methane (SC-CH4), 2012 - 2050a [in 2012$ per metric ton] (Source: Marten et al,
2014b) 4-16
Table 4-4 Estimated Global Benefits of Methane Reductions* (in millions, 2012$) 4-18
Table 4-5 Monetized Benefits-per-Ton Estimates for VOC in 9 Urban Areas and Nationwide based on Fann,
Fulcher, and Hubbell (2009) in (2012$) 4-23
Table 4-6 Increases in Secondary Air Pollutant Emissions (short tons per year) 4-38
Table 4-7 Summary of Emissions Changes (short tons per year, except where noted) 4-41
Table 5-1 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 1 in 2020 and 2025 (2012$)
5-1
Table 5-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Selected Option 2 in 2020 and 2025
(2012$) 5-2
Table 5-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in 2020 and 2025 (2012$)
5-3
Table 5-4 Summary of Emissions Changes across Options for the NSPS in 2020 and 2025 (short tons per year,
unless otherwise noted) 5-4
Table 6-1 Per Well Costs for Environmental Controls Entered into NEMS (2012$) 6-6
Table 6-2 Successful Oil and Gas Wells Drilled (Onshore, Lower 48 States) 6-8
Table 6-3 Domestic Natural Gas and Crude Oil Production (Onshore, Lower 48 States) 6-8
Table 6-4 Average Natural Gas and Crude Oil Wellhead Price (Onshore, Lower 48 States, 2012$) 6-9
Table 6-5 Net Imports of Natural Gas and Crude Oil 6-10
Table 6-6 SB A Size Standards by NAICS Code 6-15
Table 6-7 Distribution of Estimated Compliance Costs Across Sources 6-16
Table 6-8 No. of Completions in 2012 by Preliminary Firm Size 6-17
Table 6-9 No. of Completions in 2012 by Firm Size 6-18
Table 6-10 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size 6-21
Table 6-11 Distribution of Estimated Compliance Costs1 across Firm Size Classes 6-21
Table 6-12 Compliance Costs-to-Sales1 Ratios across Firm Size Classes for Primary Scenario and Low Oil Price
Scenario2 6-23
Table 6-6 Estimates of Labor Required to Comply with NSPS for Hydraulically Fractured Oil Well
Completions, 2020 and 2025 6-33
Table 6-7 Estimates of Labor Required to Comply with NSPS for Fugitive Emissions, 2020 and 2025 6-34
Table 6-8 Estimates of Labor Required to Comply with NSPS for Reciprocating and Centrifugal Compressors,
2020 and 2025 6-35
Table 6-9 Estimates of Labor Required to Comply with NSPS for Pneumatic Controllers and Pumps, 2020 and
2025 6-36
Table 6-10 Estimates of Labor Required to Comply with NSPS, 2020 and 2025 6-37
Vlll
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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, 1990-2014 2-15
Figure 2-3 U.S. Produced Water Volume by Management Practice, 2007 2-20
Figure 2-4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990-2012 2-23
Figure 2-5 Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-2012 2-25
Figure 2-6 Forecast of Domestic Crude Oil Production and Net Imports, 2010-2040 2-30
Figure 2-7 Costs of Crude Oil and Natural Gas Wells Drilled, 1981-2008 2-32
Figure 2-8 Finding Costs for FRS Companies, 1981-2009 2-33
Figure 2-9 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2009 (3-year Running Average)
2-34
Figure 2-10 Crude Oil Operating Costs and Equipment Costs Indices (1976=100) and Crude Oil Price (in 1976
dollars), 1976-2009 2-36
Figure 2-11 Natural Operating Costs and Equipment Costs Indices (1976=100) and Natural Gas Price, 1976-2009
2-37
Figure 4-1 Path from GHG Emissions to Monetized Damages 4-12
Figure 4-2 2011 NAT A Model Estimated Census Tract Carcinogenic Risk from HAP Exposure from All
Outdoor Sources based on the 2011 National Emissions Inventory 4-30
Figure 4-3 2011 NAT A Model Estimated Census Tract Noncancer (Respiratory) Risk from HAP Exposure from
All Outdoor Sources based on the 2011 National Emissions Inventory 4-31
IX
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1 EXECUTIVE SUMMARY
1.1 Background
The action analyzed in this regulatory impact analysis (RIA) amends 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 rule because methane is a greenhouse gas (GHG),
and the oil and natural gas category is the country's largest emitter 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 amending the NSPS to include standards for reducing methane as well as
VOC emissions across the oil and natural gas source category. Specifically, we are establishing
both methane and VOC standards for several emission sources not covered by the 2012 NSPS
(i.e., hydraulically fractured oil well completions, fugitive emissions from well sites, compressor
stations, pneumatic pumps). In addition, we are establishing methane standards for certain
emission sources that are regulated for VOC under the 2012 NSPS (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 VOC sources
regulated under the 2012 NSPS.
With respect to certain equipment that are used across the source category, the 2012
NSPS regulates only a subset of this equipment (pneumatic controllers, centrifugal compressors,
reciprocating compressors). The new amendents establish methane standards for these equipment
across the source category and extend the VOC standards from the 2012 NSPS to the remaining
unregulated equipment. Lastly, amendments to the 2012 NSPS are established that improve
several aspects of the 2012 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 2012 NSPS for the oil and 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 2012
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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 final 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 final NSPS.1 We also estimate potential impacts of the
rule on national energy markets 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 to represent the
near-term impacts of the rule, and 2025 to represent impacts of the rule over a longer period.
Therefore, the emissions reductions, benefits, and costs by 2020 and 2025 (i.e., including all
emissions reductions, costs, and benefits in all years from 2016 to 2025) would be potentially
significantly greater than the estimated emissions reductions, benefits, and costs provided within
this rule. Affected facilities are facilities that are new or modified since the proposal in
September 2015. In 2020, affected facilities are those that are newly established or modified in
2020, as well as those that have accumulated between 2016 and 2019. The regulatory impact
estimates for 2025 include sources newly affected in 2025 as well as the accumulation of
affected sources from 2016 through 2024 that are 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
1 The analysis in this RIA and the RIA that accompanied the proposal together constitute 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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results that include the additional product recovery and the revenues we expect producers to gain
from the additional product recovery.
The baseline used for the impacts analysis of our NSPS takes into account emissions
reductions conducted pursuant to state regulations covering the relevant operations. A 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 cost of
production that is 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. These impacts are not reflected in the market price of the
goods produced through the polluting process and are referred to as negative externalities. For
this regulatory action, the goods produced, processed, transported, or stored are crude oil, natural
gas, and other hydrocarbon products. If an oil and natural gas firm pollutes the atmosphere while
extracting, processing, transporting, or storing goods, this cost will not be borne by the polluting
firm but by society as a whole. The market price of the products will fail to incorporate the full
cost to society of the pollution related to production. All else held equal, the quantity of oil and
natural gas produced in a competitive market will not be at the socially optimal level. More oil
and natural gas will be produced than would occur if the oil and natural gas producers had to
account for the full 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. Table 1-1 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. Option 2 was selected for promulgation.
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Table 1-1 Emissions Sources and Controls Evaluated for the NSPS
Emissions Point
„ . . „ . , Option 1 Option 2 /->-•-,
Emissions Control ,„. ,, Option 3
(final) r
Well Completions and Recompletions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured Wildcat
and Delineation Oil Wells
Fugitive Emissions
Well Sites
Gathering and Boosting Stations
Transmission Compressor Stations
Pneumatic Pumps
Well Sites
Pneumatic Controllers
Natural Gas Transmission and
Storage
Reciprocating Compressors
Natural Gas Transmission and
Storage
Centrifugal Compressors
Natural Gas Transmission and
Storage
RFC / Combustion X
Combustion X
Planning,
Monitoring and
Maintenance
Planning,
Monitoring and
Maintenance
Planning,
Monitoring and
Maintenance
Route to control X
Emissions limit X
Maintenance X
Route to control X
X
X
X
Annual Semiannual Quarterly
Semiannual Quarterly Quarterly
Semiannual Quarterly Quarterly
X
X
X
X
X
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 requires fugitive emissions survey and repair programs be performed
semiannually (twice per year) at the affected newly drilled or refractured oil and natural gas well
sites, and quarterly at new or modified gathering and boosting stations and new or modified
transmission and storage compressor stations. Option 2 also requires reductions from centrifugal
compressors, reciprocating compressors, and pneumatic controllers and pumps.
Options 1 and 3 differ from the finalized Option 2 with respect to the requirements for
fugitive emissions. Well site fugitive requirements under Option 1 are annual, while new or
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modified gathering and boosting station and new or modified transmission and storage
compressor stations require a semiannual fugitive emission survey and repair program. Less
frequent survey requirements lead to lower costs as well as lower emissions reduction compared
to the selected Option 2. The more stringent Option 3 requires quarterly monitoring for all sites
under the fugitive emissions program. More frequent surveys result in greater emission
reductions, however there are also increased costs, resulting in a net effect of lower net benefits
compared to the finalized Option 2.
1.4 Summary of Results
For the final NSPS, a summary of the key results of the RIA for the final standards
(Option 2) follow. Key results for Options 1 through 3 are summarized in Table 1-2 through
Table 1-4, respectively. Note all dollar estimates are in 2012 dollars:
• Emissions Analysis: The final NSPS is anticipated to prevent significant new emissions,
including 300,000 short tons of methane, 150,000 tons of VOCs and 1,900 tons of
hazardous air pollutants (HAP) in 2020, increasing to 510,000 short tons of methane,
210,000 tons of VOCs, and 3,900 tons of HAP prevented in 2025.2 The CO2-equivalent
(COi Eq.) methane emission reductions are 6.9 million metric tons in 2020 and 11
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).3 The
EPA estimates that, in 2020, the rule will yield monetized climate benefits of $160
million to approximately $950 million; the mean SC-CH4 at the 3% discount rate results
in an estimate of about $360 million in 2020. In 2025, the EPA estimates monetized
climate benefits of $320 million to approximately $1.8 billion; the mean SC-CH4 at the
3% discount rate results in an estimate of about $690 million in 2025.4 While we expect
that the avoided emissions will result in improvements in ambient air quality and
reductions in negative 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.5 This is not to imply that there are no health benefits
2 Estimates are presented in short tons.
3 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.
4 The range of estimates reflects four SC-CH4 estimates and 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.
5 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
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anticipated from the final NSPS; 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 final NSPS are anticipated to have
minor secondary disbenefits.
• Engineering Cost Analysis: The EPA estimates the total capital cost of the final NSPS
to be $250 million for affected sources in 2020 and $360 million for affected sources in
2025. The estimate of total annualized engineering costs of the final NSPS is $390
million in 2020 and $640 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 NSPS are estimated to be $320 million in 2020 and $530 million in 2025,
assuming a wellhead natural gas price of $4/thousand cubic feet (Mcf). The estimated
engineering compliance costs that include product recovery are sensitive to the
assumption about the price of the recovered product. There is also geographic variability
in wellhead prices, which can influence estimated engineering costs. For example,
$l/Mcf change in the wellhead price causes a change in estimated engineering
compliance costs of about $16 million in 2020 and $27 million in 2025, given the EPA
estimates that about 16 million Mcf in 2020 and 27 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 final NSPS is $380 million in 2020 and $630
million in 2025, or $320 million in 2020 and $520 million in 2025, when estimated
revenues from additional natural gas are included.
• Energy Markets Impacts Analysis: The EPA used the National Energy Modeling
System (NEMS) to estimate the impacts of the final rule on the United States energy
markets. We estimate that natural gas and crude oil drilling levels decline slightly over
the 2020 to 2025 period relative to the baseline (by about 0.17 percent for natural gas
wells and about 0.02 percent for crude oil wells). Natural gas production decreases
slightly over the 2020 to 2025 period under the rule relative to the baseline (by about 0.03
percent), while crude oil production does not vary appreciably. Crude oil wellhead prices
for onshore lower 48 production are not estimated to change appreciably over the 2020 to
2025 period relative to the baseline. However, wellhead natural gas prices for onshore
lower 48 production are estimated to increase slightly over the 2020 to 2025 period
relative to the baseline (about 0.20 percent). Net imports of natural gas are estimated to
increase slightly over the 2020 to 2025 period (by about 0.11 percent) relative to the
baseline. Crude oil net imports are not estimated to to change appreciably over the 2020
to 2025 period relative to the baseline.
• Small Entity Analyses: To understand the potential impact of the rule on 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 that it is unable to certify that the final rule
that study are derived from total VOC emissions across all sectors. Larger uncertainties about the relationship
between VOC emissions and PM2.s coupled with the highly localized nature of air quality responses associated
with VOC reductions, 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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will not have a Significant Impact on a Substantial Number of Small Entities (SISNOSE).
The EPA convened a Small Business Advisory Review panel and completed an Inititial
Regulatory Flexibility Analysis before proposing the rule. The EPA also completed a
Final Regulatory Flexibility Analysis for the final rule.
• 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. The
EPA 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 final NSPS is estimated at about 270 FTEs in 2020 and in
2025. The annual labor requirement to comply with the NSPS is estimated at about 1,100
FTEs in 2020 and 1,800 FTEs in 2025. The EPA notes that this type of FTE estimate
cannot be used to identify the specific number of employees 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 Option 1, Table 1-3 presents summary results
for Option 2, and Table 1-4 presents summary results for Option 3.
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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
$290 million
$240 million
$54 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 130,000 tons of VOC
reduced
Health effects of HAP exposure from
1,300 tons of HAP reduced
Health effects of ozone exposure from
250,000 tons of methane
Visibility impairment
Vegetation effects
$540 million
$360 million
$180 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 170,000 tons of VOC
reduced
Health effects of HAP exposure from
2,700 tons of HAP reduced
Health effects of ozone exposure from
390,000 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 $130 million to $780 million in 2020 and $250 million to $1.4 billion in
2025 for Option 1, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission reductions are 5.6
million metric tons in 2020 and 8.9 million metric tons in 2025. Also, the specific control technologies for the
NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for details.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue
from additional natural gas recovery as a result of the NSPS. As can be seen in section 3.5.1 of the final RIA, the
national cost estimates in for this rule are not highly sensitive to the use of a 3 percent or 7 percent discount rate
in this RIA. As a result, the net benefits of the rule are not highly sensitive to choice of discount rate for
annualizing capital costs.
3 Estimates may not sum due to independent rounding.
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Table 1-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 2
(Finalized Option) in 2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$360 million
$320 million
$35 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 150,000 tons of VOC
reduced
Health effects of HAP exposure from
1,900 tons of HAP reduced
Health effects of ozone exposure from
300,000 tons of methane
Visibility impairment
Vegetation effects
$690 million
$530 million
$170 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 210,000 tons of VOC
reduced
Health effects of HAP exposure from
3,900 tons of HAP reduced
Health effects of ozone exposure from
510,000 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, 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 $160 million to $950 million in 2020 and $320 million to $1.8 billion in 2025 for
Option 2, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission reductions are 6.9 million
metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control technologies for the NSPS are
anticipated to have minor secondary disbenefits. See Section 4.7 for details.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue
from additional natural gas recovery as a result of the NSPS. As can be seen in section 3.5.1 of the final RIA, the
national cost estimates in for this rule are not highly sensitive to the use of a 3 percent or 7 percent discount rate
in this RIA. As a result, the net benefits of the rule are not highly sensitive to choice of discount rate for
annualizing capital costs.
3 Estimates may not sum due to independent rounding.
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Table 1-4 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in
2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$420 million
$490 million
-$75 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 160,00 tons of VOC
reduced
Health effects of HAP exposure from
2,400 tons of HAP reduced
Health effects of ozone exposure from
350,000 tons of methane
Visibility impairment
Vegetation effects
$840 million
$880 million
-$38 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 230,000 tons of VOC
reduced
Health effects of HAP exposure from
5,000 tons of HAP reduced
Health effects of ozone exposure from
610,000 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, 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 $190 million to $1.1 billion in 2020 and $390 million to $2.2 billion in 2025 for this
more stringent option, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission reductions are 8
million metric tons in 2020 and 14 million metric tons in 2025. Also, the specific control technologies for the
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. As can be seen in section 3.5.1 of the final RIA, the
national cost estimates in for this rule are not highly sensitive to the use of a 3 percent or 7 percent discount rate
in this RIA. As a result, the net benefits of the rule are not highly sensitive to choice of discount rate for
annualizing capital costs.
3 Estimates may not sum due to independent rounding.
1.5 Summary of NSPS Impacts Changes from the Proposal RIA
This section summarizes major changes from the proposal version of the RIA. These
changes were a result of revised assumptions and technical factors, as well as changes in the rule
itself from proposal. With respect to changes in the rule's provisions from proposal, we focus on
changes that have an effect on estimates of emissions reductions, costs, and benefits.
Changes resulting from revised assumptions and technical factors include:
• Annual Energy Outlook and National Energy Modeling System updates: At
proposal, the Energy Information Administration (EIA) 2014 Annual Energy Outlook
(AEO) was used to derive projections of oil and natural gas well drilling activities. For
this RIA, we used the 2015 AEO, the latest version available at the time of the signature
of the rule. Section 3.4.2 presents a brief discussion comparing the 2014 and 2105 AEOs.
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The EPA also updated the version of the NEMS model from 2014 to 2015 to develop the
energy markets impacts presented in Section 6.2 of this RIA.
• EPA Greenhouse Gas Inventory updates: The EPA updated the unit-level cost and
emissions analyses where possible to reflect recent updates to the Greenhouse Gas
Inventory. In particular, data from the Greenhouse Gas Reporting program and the
Greenhouse Gas Inventory was used to update the equipment and component counts and
potential emissions of the model plants for fugitive emissions.
• Revised first year of regulatory program: At proposal, 2020 was assumed to represent
a single year of potential impacts. However, NSPS-affected facilities are facilities that are
new or modified since the proposal in September 2015. In this final RIA, affected
facilities in 2020 are those that are newly established or modified in 2020, as well as
those that have accumulated between 2016 and 2019. As a result, the years of analysis in
this RIA are 2020, to represent the near-term impacts of the rule, and 2025, to represent
impacts of the rule over a longer period. This methodological change results in a higher
estimate of the number of affected facilities than at proposal and better represents the
impacts of the rule.
• New hydraulically fractured oil well completions with insufficient pressure to
implement REC required to combust completions emissions: Using the formula
estimated to identify hydraulically fractured well completions that would not have
sufficient pressure to perform a REC, approximately 40 percent of oil well completions
that would otherwise be required to perform a REC would be required to combust
emissions rather than implement a REC. The overall proportion of completions that are
assumed to be feasible to REC remains unchanged from the proposal analysis at 50
percent. More detailed discussion is presented in a technical memorandum on this subject
in the docket.6
• Revised unit-level emissions and cost estimates: The EPA revised the cost of control
esimates for fugitive emissions monitoring and pneumatic pumps based on information
provided by commenters.
• Revised approach to projecting affected facilities from historical activity data:
Newly constructed affected facilities are estimated based on averaging the year-to-year
changes in the past 10 years of activity data in the Greenhouse Gas Inventory for
compressor stations, pneumatic pumps, compressors, and controllers. At proposal, this
was done by averaging the increasing years only. The approach was modified to average
the number of newly constructed units in all years.
The changes in the rules requirements that affect emissions, cost, and benefit estimates
include:
• Fugitive emissions: The EPA proposed to exclude low production well sites (e.g., well
sites where the average combined oil and natural gas production is less than 15 barrels of
oil equivalent (boe) per day averaged over the first 30 days of production) from the
standards for the collection of fugitive emissions components at well sites. Based on
[Placeholder for title of low pressure well eequation technical memo]
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analysis in response to comments, the EPA is finalizing the requirement that low
production well sites are regulated under a monitoring and repair standard based on
semiannual monitoring. With respect to fugitive emissions at compressor stations, based
on analysis in response to comments, the EPA is finalizing the requirement to implement
the fugitives program at compressor stations on a quarterly basis, as opposed to the
proposed semiannual (twice per year) basis.
• Hydraulically fractured oil well completions: For the final rule, the EPA refined
requirements that require wells that are not low GOR, low pressure, or
exploration/delineation wells to have a separator on site during completion flowback.
Wells with low GOR (less than 300 scf/of gas per stock barrel of oil produced) are still
excluded from well completion requirements, but, unlike at proposal, they are considered
affected facilities and their exclusion from requirements is provided the owner or
operator maintains records of the low GOR certification, and submit a claim signed by
the certifying official.
• Pneumatic pumps: The EPA changed the definition of an affected pneumatic pump
facility to include only natural gas driven pumps in order to incentivize the use of lower
emitting alternatives. The EPA also exempted chemical injection pumps and portable or
temporary pumps from control requirements.
1.6 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 a
comparison of benefits and costs. Section 6 presents energy markets 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 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 final NSPS.
The outputs of the oil and natural gas industry are inputs for larger production processes
of gas, energy, and petroleum products. As of 2014, the Energy Information Administration
(EIA) estimates that about 515,000 producing natural gas wells are operating in the U.S. The
latest available information from EIA indicates that there were about 536,000 producing oil wells
in the U.S. as of 2011. Domestic dry natural gas production was 25.7 trillion cubic feet (tcf) in
2014, the highest annual production level in U.S. history. The leading five natural gas producing
states in 2014 were Texas, Pennsylvania, Oklahoma, Louisiana and Wyoming. Domestic crude
oil production in 2014 was 3,200 million barrels (bbl), the highest annual level in the U.S. since
1991. The leading five crude oil producing states in 2014 were 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 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 analyses in this RIA. The Industry Profile relies heavily on
background material from the EPA's "Economic Analysis of Air Pollution Regulations: Oil and
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Natural Gas Production" (1996), the EPA's "Sector Notebook Project: Profile of the Oil and Gas
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 the natural gas as well as the reservoir characteristics are likely
to be different across all reservoirs.
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 method to classify hydrocarbons, including crude oil, is through the
measurement of API gravity. API gravity is a weight per-unit of 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 an API gravity of 20° or less,
while a light or naphthenic crude oil, which typically flows freely at atmospheric conditions,
usually has an 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 that 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
exist in a gaseous phase or in a solution with crude oil or other hydrocarbon liquids in natural
underground reservoirs. Natural gas may contain contaminants, such as hydrogen sulfide (fhS),
CO2, mercaptans, and entrained solids.
Natural gas may be classified as a 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 is classified as acid, sour or sweet. Acid gas contains CO2 and/or IHhS, where
the concentration of IHbS is below the threshold to be classified as sour. Acid gas may contain
other contaminants. Natural gas is classified as sour when it contains an HiS concentration of
greater than 0.25 grains per 100 standard cubic feet. Sour gas may also contain other
contaminants. Concentrations of IHbS and CO2, along with organic sulfur compounds, vary
widely among sour gases. The process by which these two contaminants are removed from the
natural gas stream is called sweetening, most commonly performed through amine treating. 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.
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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).
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 well completion
if hydrocarbons are found in sufficient quantities, or to abandonment otherwise.
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 are released down into the drill pipe, which then push
up the walls of the well bore, removing 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, 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
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allowing more oil or natural gas to 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
surface without stopping the drill to switch directions and allowing for a more controlled and
precise drilling trajectory.
Hydraulic fracturing (also referred to as "fracking") has been performed since the 1940s
(U.S. DOE, 2013). Hydraulic fracturing involves pumping fluids into the well under very high
pressures in order to fracture the formation containing the resource. Proppant, a mixture of sand
and other materials, 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 the well is usually drilled into the
bottom, oil-heavy portion of a formation to recover most of the liquid first, with the natural gas
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cap sitting on top. Production sites often handle crude oil and natural gas from more than one
well (Hyne, 2001).
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). When the well lacks enough
pressure itself to drive the resource to the 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, 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
is used but given that coalbed methane reservoirs are frequently associated with
underground water reservoirs, hydraulic fracturing is often restricted (Andrews, 2009).
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2.3.3 Natural Gas Processing
As natural gas is separated from the liquid components, it may contain impurities that
pose potential hazards or other problems. Natural gas conditioning is the process of removing
impurities from the gas stream so it is of sufficient quality to pass through transportation systems
and to be 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.
One concern in natural gas processing is 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 liquid 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 desiccant, a solid desiccant, or 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 and the glycol can then be
reused. Solid desiccants, often materials called molecular sieves, are crystals with high surface
areas that attract water molecules. The solids can be regenerated by heating them above the
boiling point of water and then be reused as well. 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.
The most significant impurity in natural gas is IHbS, which may or may not be contained
in natural gas. HiS is toxic and potentially fatal, at certain concentrations, to humans and it is
corrosive to pipes. It is therefore desirable to remove IHbS as soon as possible in the conditioning
process.
Sweetening, the procedure in which IHhS and sometimes CO2 are removed from the gas
stream, is most commonly performed using amine treatment. In this process, the gas stream is
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exposed to an amine solution, which will react with HiS and separate it 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 increase pressure to improve the movement of natural gas through
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. The EIA7 defines these concepts 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 the 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 the liquefiable portion
and any non-hydrocarbon gases that render it unmarketable have been removed from the natural
gas. 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 total technically recoverable crude oil resources.
Total 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 in
offshore areas. While dry natural gas proved reserves were estimated at 272.5 tcf in 2009, wet
natural gas reserves were estimated at 283.9 tcf. Of the 283.9 tcf, 250.5 tcf (about 88 percent)
were considered to be wet non-associated natural gas, while 33.3 tcf (about 12 percent) were
considered to be wet associated-dissolved natural gas. Associated-dissolved natural gas,
according to EIA, is natural gas that occurs in crude oil reservoirs as free natural gas or in
solution with crude oil.
7 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 l
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).
Table 2-2 and Figure 2-1 show trends in crude oil and natural gas production and reserves
from 1990 to 2014. In Table 2-2, proved ultimate recovery equals the sum of cumulative
production and proved reserves. Cumulative production is the accumulated crude oil or dry
natural gas that has been produced over time. While crude oil and natural gas are nonrenewable
resources, the table shows that proved ultimate recovery rises over time as new discoveries
become 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. Annual production (the difference in cumulate production over
one year) as a percentage of proved reserves has declined over time for both crude oil and natural
gas from around 11 percent in the early 1990s to between 8 and 10 percent over the period from
2006 to 2014 for crude oil and from about 10 percent during the early 1990s to between 7 and 9
percent from 2006 to 2014 for natural gas.
2-10
-------
Table 2-2 Crude Oil and Natural Gas Cumulative Domestic Production, Proved
Reserves, and Proved Ultimate Recovery, 1990-2014
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
2014
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
199,765
201,764
203,822
206,192
208,913
212,092
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
36,385
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
220,447
225,031
230,366
236,721
242,284
248,477
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
1,195,685
1,221,414
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
368,704
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
1,533,949
1,590,118
Source: U.S. Energy Information Administration (U.S. EIA). November 2015. U.S. Crude Oil and Natural Gas
Proved Reserves, 2014. Table 7 and Table 17.
. Accessed January 15, 2016.
Source: U.S. Energy Information Administration (U.S. EIA). 2014. Natural Gas Annual 2014.
. Accessed January 22, 2016.
Source: U.S. Energy Information Administration (U.S. EIA). Crude Oil Production.
. Accessed on January 29, 2016.
Note: Cumulative Crude Oil Production includes Crude Oil plus Lease Condensate Production.
Note: The EIA reports Proved Reserves for Crude Oil and Proved Reserves for Crude Oil plus Lease Condensate
separately. We have reported Proved Reserves for Crude Oil here.
2-11
-------
300,000
<-v
2 250,000
c
a 200,000
* 150,000
® 100,000 -
^ 50,000 -
0
A). Crude Oil
B). Natural Gas
a
o
«
I
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
O Cumulative Production • 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
Source: U.S. Energy Information Administration (U.S. EIA). November 2015. U.S. Crude Oil and Natural Gas
Proved Reserves, 2014. Table 1 and Table 17. .
Accessed January 15, 2016.
Source: U.S. Energy Information Administration (U.S. EIA). 2014. Natural Gas Annual 2014.
. Accessed January 22, 2016.
Source: U.S. Energy Information Administration (U.S. EIA). Crude Oil Production.
. Accessed on January 29, 2016.
Table 2-3 presents the U.S. proved reserves of crude oil and natural gas by state or
producing area as of 2014. Five areas currently account for 79 percent of total proved reserves of
crude oil in the U.S., led by Texas and followed by North Dakota, U.S. Federal Offshore, Alaska,
and California. The top five states in terms of proved reserves of natural gas, Texas,
2-12
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Pennsylvania, Oklahoma, West Virginia, and Wyoming, account for about 67 percent of the U.S.
total proved natural gas reserves.
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)
66
2,855
65
2,854
1,200
70
414
16
534
53
84
230
444
1,476
*
6,043
78
1,241
22
12,272
4,849
555
11
953
36,385
Gas Proved
Dry Natural
(bcf)
2,036
6,745
12,789
2,107
20,851
0
4,359
1,611
22,975
1,845
2,976
558
667
15,283
143
6,034
6,723
31,778
59,873
97,154
8,527
6,685
29,432
27,553
368,704
Reserves by State,
Gas Crude Oil
(% of total)
0.2
7.8
0.2
7.8
3.3
0.2
1.1
0.0
1.5
0.1
0.2
0.6
1.2
4.1
*
16.6
0.2
3.4
0.1
33.7
13.3
1.5
0.0
2.6
100.0
2013
Dry Natural Gas
(% of total)
0.6
1.8
3.5
0.6
5.7
0.0
1.2
0.4
6.2
0.5
0.8
0.2
0.2
4.1
0.0
1.6
1.8
8.6
16.2
26.4
2.3
1.8
8.0
7.5
100.0
Source: U.S. Energy Information Administration (U.S. EIA). November 2015. U.S. Crude Oil and Natural Gas
Proved Reserves, 2014. Table 7 and Table 17.
. Accessed January 15, 2016.
Total may not sum due to independent rounding.
* New York crude oil reserves are included in miscellaneous states
**Miscellaneous for crude oil includes Arizona, Idaho, Missouri, Nevada, New York, South Dakota, Tennessee &
Virginia as well as Illinois, Indiana, and Nebraska.
**Miscellaneous for dry natural gas includes Arizona, Idaho, Illinois, Indiana, Maryland, Missouri, Nebraska,
Oregon, South Dakota & Tennessee as well as Virginia.
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. As of 2014, domestic oil production has recovered to the highest levels since
1991. Table 2-4 shows U.S. production in 2014 at 3,179 million bbl per year.
2-13
-------
Table 2-4 Crude Oil Domestic Production, Wells, Well Productivity, and U.S. Average
First Purchase Price, 1990-2014
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
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
,954
,999
2,058
2,370
2,721
3,179
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
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
3,715
3,844
3,840
N/A
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
87.39
US Average
First Purchase
Price/Barrel
(2012 dollars)
31.56
25.22
23.84
20.75
18.81
20.42
25.32
23.24
14.50
20.45
34.33
27.44
27.85
33.43
43.41
57.51
66.24
71.90
99.69
59.29
77.66
97.50
94.52
94.45
84.60
Source: U.S. Energy Information Administration (U.S. EIA). Crude Oil Production.
. Accessed on January 29, 2016.
Source: U.S. Energy Information Administration (U.S. EIA). U.S. Crude Oil First Purchase Price.
. Accessed on January 22, 2016.
Source: Federal Reserve Bank of St. Louis. Economic Research. Gross Domestic Product: Implicit Price Deflator.
. Accessed February 3, 2016.
Note: 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.
Note: Total Production includes Crude Oil plus Lease Condensate Production.
Average well productivity has also generally decreased since 1990 (Table 2-4 and Figure
2-2), though there are signs of a slight rebounding starting around 2008. These overall
production and productivity decreases are in spite of the fact that average first purchase prices
have generally shown an increasing trend with some decline in 2014.
2-14
-------
A). Crude Oil Wells
700
5,000
1+ 4,0001
-- 3,000 S
-- 2,000;
-- 1,000^
o
o
-Producing Wells (1000s)
Avg. Well Productivity (bbl/well)
B). Natural Gas Wells
70.0
60.0
50.0
'§ 30.0
1 20.0 -
£ 10.0
0.0
600,000
500,000 „ a
'+ 400.000 O |
-- 300,000
- 200,000
- 100,000
0
«
z
-Producina Wells
-Avg. Well Productivity (MMcf/year)
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, 1990-2014.
Source: U.S. Energy Information Administration (U.S. EIA). 2014. Natural Gas Annual 2014.
. Accessed January 22, 2016.
Annual production of natural gas from natural gas wells has increased more than 8000
bcf from the 1990 to 2014 (Table 2-5). The number of wells producing natural gas has nearly
doubled between 1990 and 2014 (Figure 2-2B). While the number of producing wells has
increased overall, average well productivity has declined, despite improvements in exploration
and gas well stimulation technologies. Average well productivity has shown slight improvements
since 2009.
2-15
-------
Table 2-5 Natural Gas Production and Well Productivity, 1990-2014
Natural Gas Gross Withdrawals Natural Gas Well
(Billion Cubic Feet) Productivity
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Total
21,523
21,750
22,132
22,726
23,581
23,744
24,114
24,213
24,108
23,823
24,174
24,501
23,941
24,119
23,970
23,457
23,535
24,664
25,636
26,057
26,816
28,479
29,542
29,523
31,346
Dry Gas
Production 1
17,810
17,698
17,840
18,095
18,821
18,599
18,854
18,902
19,024
18,832
19,182
19,616
18,928
19,099
18,591
18,051
18,504
19,266
20,159
20,624
21,316
22,902
24,033
24,206
25,728
Producing
Wells
269,790
276,987
276,014
282,152
291,773
298,541
301,811
310,971
316,929
302,421
341,678
373,304
387,772
393,327
406,147
425,887
440,516
452,945
476,652
493,100
487,627
514,637
482,822
484,994
514,786
Avg. Well
Productivity
Million Cubic
Feet/Year)
66.0
63.9
64.6
64.1
64.5
62.3
62.5
60.8
60.0
62.3
56.1
52.5
48.8
48.6
45.8
42.4
42.0
42.5
42.3
41.8
43.7
44.5
49.8
49.9
50.0
Source: U.S. Energy Information Administration (U.S. EIA). 2014. Natural Gas Annual 2014.
. Accessed January 22, 2016.
1 Dry gas production is gas production after accounting for gas used repressurizing wells, the removal of
nonhydrocarbon gases, vented and flared gas, and gas used as fuel during the production process.
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 the increasing 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
2-16
-------
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
improvements in well drilling and completion. Similarly, average well depth has increased by an
estimated 1,227 feet 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
2-17
-------
flowback water from hydraulic fracturing activities (ANL 2009). 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 produced water to oil
ratios compared to states like Illinois, Florida, Missouri, Indiana and Kansas.
2-18
-------
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
Crude Oil
(1000 bbl)
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
Total Gas
(bcf)
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
Produced Water
(1000 bbl)
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
Total Oil and
Natural Gas
(1000 bbls oil
equivalent)
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
Barrels
Produced
Water per
Barrel Oil
Equivalent
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.
2-19
-------
Figure 2-3 shows the distribution of produced water management practices in 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. About
one third (34 percent) was injected, typically into wells whose primary purpose is to sequester
produced water. A small percentage (three percent) was discharged into surface water when it
met 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).
11%
3%
34%
51%
D Injection for
Enhanced Recovery
E Injection or
Disposal
D Surface Discharge
I Unknown
Source: Argonne National Laboratory
Figure 2-3 U.S. Produced Water Volume by Management Practice, 2007
The movement of crude oil and natural gas primarily takes place via pipelines. Total
crude oil pipeline mileage decreased during the 1990-2010 period, appearing to follow the
downward supply trend shown in Table 2-4. Since 2010, total crude oil pipeline mileage has
increased by over 12,000 miles (Table 2-8).
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 and deliver it directly to gas processing plants or
compression stations which connect numerous gathering lines to transport gas primarily to
processing plants. Transmission pipelines move large volumes of gas to or from processing
plants and distribution points. From these distribution points, the gas enters a distribution system
that delivers the gas to final consumers. Mileage on the distribution side, distribution mains and
2-20
-------
distribution service, has increased while transmission pipeline and gathering line mileage has
decreased. Since 2010, total natural gas pipeline has increased by over 61,000 miles.
Table 2-8 U.S. Oil and Natural Gas Pipeline Mileage, 2010-2014
Natural Gas
Pipelines (miles)
2010
2011
2012
2013
2014
Distribution
mains
1,229,725
1,238,947
1,247,231
1,255,145
1,266,039
Distribution
Service
872,466
881,955
890,361
894,283
902,772
Transmission
pipelines
304,805
305,058
303,341
302,827
301,806
Gathering
lines
19,626
19,350
16,532
17,369
17,621
Total
2,426,622
2,445,310
2,457,465
2,469,624
2,488,238
Crude Oil
Pipelines
(miles)
Total
54,631
56,100
57,463
61,087
66,700
Source: U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Office of
Pipeline Safety, Annual Report Mileage Summary Statistics, available at as of January 4, 2016.
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 total consumption
basically leveled off 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
percentage of the share of total consumption by the transportation sector rose from 64 percent in
1990 to 71 percent in 2012.
2-21
-------
Table 2-9 Crude Oil Consumption by Sector, 1990-2012
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Total
(million
barrels)
6,178
6,068
6,209
6,277
6,439
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
Residential and
Commercial
7.3
7.3
7.1
6.9
6.6
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
Percent
Industrial
25.1
24.9
26.1
25.3
26.0
25.7
26.1
26.4
25.4
25.6
25.1
25.1
25.2
24.8
25.3
24.2
24.8
24.1
23.0
22.2
22.8
23.2
23.4
of Total
Transportation
Sector
64.3
64.7
64.3
65.0
64.8
66.0
65.2
65.1
65.8
65.5
67.6
67.4
68.3
67.9
67.7
67.3
68.9
69.5
70.4
71.4
71.0
71.1
71.1
Electric
Power
3.3
3.2
2.6
2.9
2.6
1.9
2.0
2.2
3.1
2.8
2.6
2.9
2.2
2.7
2.6
2.6
1.4
1.4
1.1
1.0
0.9
0.7
0.5
Source: U.S. Energy Information Administration.
2-22
-------
70% --
a.
|
o
O
-K—X
Residential and Commercial
Transportation Sector
Industrial
Electric Power
Figure 2-4 Crude Oil Consumption by Sector (Percent of Total Consumption), 1990-
2012
Natural gas consumption has increased over the last twenty years. From 1990 to 2014,
total U.S. consumption increased by an average of about 1.6 percent per year (Table 2-10 and
Figure 2-5). Over this period, the percentage of natural gas consumed by the industrial sector
declined, whereas the percent of total natural gas used for electric power generation increased
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 sector demand has bounced around between about 23 and 19 percent, where the lower
percentage of total demand falls mainly in the years post 2008 with slightly larger dip in 2012.
Commercial sector demand hovered around 13 and 14 percent, also with a slight dip in 2012.
The transportation sector has maintained a fairly constant consumption level of right around 3
percent between 1990 and 2014.
2-23
-------
Table 2-10 Natural Gas Consumption by Sector, 1990-2014
Percent of Total
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Total (tcf)
19.17
19.56
20.23
20.79
21.25
22.21
22.61
22.74
22.25
22.41
23.33
22.24
23.03
22.28
22.40
22.01
21.70
23.10
23.28
22.91
24.09
24.48
25.54
26.16
26.69
Residential
22.9
23.3
23.2
23.8
22.8
21.8
23.2
21.9
20.3
21.1
21.4
21.5
21.2
22.8
21.7
21.9
20.1
20.4
21.0
20.9
19.9
19.3
16.2
18.7
19.1
Commercial
13.7
13.9
13.9
13.8
13.6
13.6
14.0
14.1
13.5
13.6
13.6
13.6
13.7
14.3
14.0
13.6
13.1
13.0
13.5
13.6
12.9
12.9
11.3
12.6
13.0
Industrial
43.1
42.7
43.0
42.7
42.0
42.3
42.8
42.7
42.7
40.9
39.8
38.1
37.5
37.1
37.3
35.0
35.3
34.1
33.9
32.5
33.7
34.0
33.8
34.1
34.2
Electric
Power
16.9
17.0
17.0
16.7
18.4
19.1
16.8
17.9
20.6
21.5
22.3
24.0
24.6
23.1
24.4
26.7
28.7
29.6
28.6
30.0
30.7
30.9
35.7
31.3
30.5
Transportation
3.4
3.1
2.9
3.0
3.2
3.2
3.2
3.3
2.9
2.9
2.8
2.9
3.0
2.7
2.6
2.8
2.8
2.8
2.9
3.0
2.9
2.9
3.0
3.3
3.3
Source: U.S. Energy Information (U.S. EIA). Monthly Energy Review. Table 4.3 Natural Gas Consumption by
Sector data. < http://www.eia.gov/beta/MER/index.cfm?tbl=T04.03#/?f=A&start=1990&end=2014&charted=l-
2-9-13-14>. Accessed February 3, 2016.
Note: Industrial Consumption is reported as Lease and Plant Fuel, Other Industrial: CHP, and Other Industrial:
Non-CHP
2-24
-------
vVcxVcxVcxVoN
•Residential
•Industrial
•Transportation
A Commercial
)( Electric Power
Figure 2-5 Natural Gas Consumption by Sector (Percent of Total Consumption), 1990-
2012
Source: U.S. Energy Information (U.S. EIA). Monthly Energy Review. Table 4.3 Natural Gas Consumption by
Sector data. . Accessed February 3, 2016.
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.
2-25
-------
Table 2-11 Total Crude Oil and
1990-2014
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
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
2,681
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
692
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
3,373
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
128
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
1396
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
1,524
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
2,552
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
-704
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
1,849
Sources: U.S. Energy Information Administration (U.S. EIA). U.S. Imports by Country of Origin.
. Accessed January 22,
U.S. Energy Information Administration (U.S. EIA). U.S. Exports by Destination.
. Accessed January 22, 2016.
2016.
From 1990 to 2007, natural gas imports have increased steadily in both volume and
percentage terms (Table 2-12). Imported natural gas constituted a lower percentage of domestic
natural gas consumption from 2007 through 2014 compared to earlier years. Until recent years,
industry analysts have forecasted 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, is reducing the need for the U.S. to import
natural gas, either via pipeline or shipped LNG.
2-26
-------
Table 2-12 Natural Gas Imports and Exports, 1990-2014
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
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
2,695
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
,514
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
1,181
Percent of U.S.
Consumption
7.5
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
5.0%
4.4%
Source: U.S. Energy Information Administration (U.S. EIA). U.S. Natural Gas Imports & Exports by State.
. Accessed January 21, 2016.
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 most current forecast
information available from the EIA, the 2014 and 2015 Annual Energy Outlook. The 2014 and
2015 Annual Energy Outlook was produced using the National Energy Modeling System
(NEMS), which the EPA uses to analyze the impacts of the final NSPS on the national economy
as is discussed in detail in Section 7.
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
2-27
-------
decline until 2040. Meanwhile, the forecast shows an increase in natural gas drilling in the lower
48 states from the present to 2040, more than doubling during this 25-year period.
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.
Table 2-14 presents forecasts of domestic crude oil production, reserves, imports and
Figure 2-6 depicts these trends graphically. Table 2-14 also shows forecasts of proved reserves in
the lower 48 states. The reserves forecast shows steady growth from 2012 to 2040, with an
increase of 49 percent overall. This increment is smaller than the forecast increase in production
from the lower 48 states during this period, 52 percent, showing production is forecast to grow
2-28
-------
more rapidly than reserves. In addition, Table 2-14 shows average wellhead prices increasing
more than 41 percent from 2012 to 2040, from $96.38 per barrel to $136.13 per barrel in 2013
dollar terms.
Table 2-14 Forecast of Crude Oil Supply, Reserves, and Wellhead Prices, 2012-2040
Domestic Production (million bbls)
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
Source:
2040. <
Total
Domestic
2,373
2,715
3,151
3,404
3,486
3,651
3,786
3,861
3,870
3,837
3,812
3,785
3,786
3,752
3,692
3,682
3,700
3,681
3,665
3,573
3,495
3,448
3,424
3,425
3,407
3,404
3,422
3,420
3,440
Lower
48
Onshore
1,678
2,032
2,422
2,640
2,691
2,790
2,865
2,906
2,933
2,923
2,918
2,918
2,932
2,924
2,869
2,850
2,837
2,802
2,773
2,688
2,622
2,587
2,578
2,580
2,571
2,557
2,541
2,534
2,527
Lower
48
Offshore Alaska
503
495
549
599
637
699
757
797
785
770
757
738
732
712
712
729
766
787
805
804
795
787
777
780
773
766
774
761
790
192
188
180
164
158
162
164
158
153
145
137
129
122
116
110
103
97
92
86
82
77
73
69
66
62
81
107
126
123
Other
Crude
Supply
16
97
47
78
51
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Net
Imports
3,088
2,773
2,563
2,343
2,307
2,156
2,055
1,995
2,012
2,086
2,131
2,181
2,189
2,222
2,285
2,300
2,291
2,321
2,349
2,454
2,533
2,604
2,657
2,683
2,723
2,752
2,748
2,766
2,768
Lower
48 End
of Year
Total Reserves
Crude (million
Supply bbls)
5,476
5,584
5,761
5,826
5,845
5,807
5,841
5,857
5,882
5,924
5,943
5,966
5,975
5,974
5,977
5,982
5,991
6,002
6,014
6,027
6,028
6,052
6,081
6,108
6,130
6,156
6,170
6,187
6,208
U.S. Energy Information Administration (U.S. EIA). April 2015. Annual Energy Outlook
http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf>. Accessed January 25, 2016.
30,051
29,441
31,131
31,966
33,549
34,747
35,948
37,002
37,403
37,760
38,137
38,605
39,066
39,389
39,908
40,633
41,497
42,109
42,593
42,708
42,665
42,795
43,066
43,425
43,609
43,808
44,124
44,234
44,779
2015 with
Lower 48
Average
Wellhead
Price (2013
dollars per
barrel)
96.38
96.51
90.37
53.49
68.35
72.44
72.34
73.79
75.16
76.97
79.27
81.68
84.11
86.57
89.27
92.03
94.89
97.86
100.92
104.19
107.44
110.82
113.86
117.20
120.77
124.33
128.36
132.37
136.13
Projections to
2-29
-------
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
Source: U.S. Energy Information Administration (U.S. EIA). April 2015. Annual Energy Outlook 2015 with
Projections to 2040. < http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf>. Accessed January 25, 2016.
Table 2-15 shows domestic natural gas production is forecast to increase until 2040.
Meanwhile, imports of natural gas via pipeline are eliminated during the forecast period, from
1.37 tcf in 2012 to -2.33 tcf in 2040. Imports of LNG are also expected to be eliminated during
the forecast period, from 0.15 tcf in 2012 to -3.29 tcf in 2040. Dry Gas Production increases
about 47 percent, from 24.06 tcf in 2012 to 35.45 in 2040. Total supply increases about 17
percent, from 25.64 tcf in 2012 to 29.90 tcf in 2040.
2-30
-------
Table 2-15 Forecast of Natural Gas Supply, Lower 48 Reserves, and Wellhead Price
2012-2040
Domestic Production (tcf)
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
Production
24.06
24.40
25.57
26.43
27.30
27.18
27.68
28.27
28.82
29.17
29.53
29.85
30.17
30.51
30.78
31.37
31.94
32.50
33.01
33.19
33.40
33.63
33.84
34.14
34.46
34.75
35.04
35.28
35.45
Supplemental
Natural Gas
0.06
0.05
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
0.06
Net Imports (tcf)
Net
Imports
(Pipeline)
1.37
1.20
1.09
0.83
0.58
0.23
-0.07
-0.29
-0.48
-0.58
-0.72
-0.83
-0.91
-1.01
-1.09
-1.21
-1.31
-1.41
-1.52
-1.60
-1.69
-1.77
-1.83
-1.90
-2.00
-2.09
-2.19
-2.30
-2.33
Net
Imports
(LNG)
0.15
0.09
0.05
-0.03
-0.23
-0.69
-1.05
-1.52
-2.08
-2.37
-2.49
-2.49
-2.49
-2.49
-2.49
-2.69
-2.89
-3.09
-3.29
-3.29
-3.29
-3.29
-3.29
-3.29
-3.29
-3.29
-3.29
-3.29
-3.29
Total
Supply
25.64
25.75
26.77
27.29
27.71
26.78
26.62
26.53
26.33
26.28
26.39
26.60
26.84
27.07
27.27
27.54
27.80
28.06
28.27
28.37
28.49
28.63
28.79
29.01
29.24
29.44
29.62
29.75
29.90
Lower 48
End of
Year Dry
Reserves
(tcf)
298.5
293.2
299.0
300.8
301.5
303.7
305.5
307.5
308.9
310.6
312.1
313.3
314.7
315.7
316.8
319.2
322.2
325.3
328.7
330.8
332.7
334.5
336.5
338.3
339.9
341.5
343.3
344.3
345.2
Average Henry
Hub Spot Price
(2013 dollars
per million
Btu)
2.79
3.73
4.37
3.69
3.70
3.80
4.21
4.55
4.88
5.02
5.09
5.25
5.35
5.46
5.67
5.67
5.67
5.71
5.69
5.91
6.09
6.27
6.45
6.60
6.76
6.84
7.02
7.38
7.85
Source: U.S. Energy Information Administration (U.S. EIA). April 2015. Annual Energy Outlook 2015 with
Projections to 2040. < http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf>. Accessed January 19, 2016
2-31
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2.5 Industry Costs
2.5.7 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
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 the EIA add an additional level of
detail to drilling costs, in that finding costs incorporate the broader costs 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. The 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, offshore and foreign finding costs for the sample of U.S. firms in the 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
2-32
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finding costs dropped from 1981 until the mid-1990s. Interestingly, in the mid-1990s, domestic
onshore, offshore and foreign finding costs converged for a few years. After this period, offshore
finding costs rose faster than domestic onshore and foreign costs.
After 2000, average finding costs rose sharply, with the finding costs for domestic
onshore, 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.
-U.S. Onshore
-U.S. Offshore
-Foreign
Figure 2-8 Finding Costs for FRS Companies, 1981-2009
Source: U.S. Energy Information Administration (U.S. EIA). February 2011. Performance Profiles of Major Energy
Producers, 2009.Figure 17 data. . Accessed January
19, 2016.
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. The 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, the
EIA reports average lifting costs for FRS firms in 2009 dollars on a barrel of oil equivalent basis.
2-33
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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.
Direct lifting costs (excludes taxes and royalties) for domestic production rose a little
more than $2 per barrel of oil equivalent between 1981 and 1985, then declined almost $5 per
barrel of oil equivalent by 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, with foreign lifting costs lower than domestic costs during this period. After
1991, 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.
V V
-Domestic
-Foreign
Figure 2-9 Direct Oil and Natural Gas Lifting Costs for FRS Companies, 1981-2009 (3-
year Running Average)
Source: U.S. Energy Information Administration (U.S. EIA). February 2011. Performance Profiles of Major Energy
Producers, 2009.Figure 15 data. . Accessed January
19, 2016.
2-34
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2.5.3 Operating and Equipment Costs
The EIA report, "Oil and Gas Lease Equipment and Operating Costs 1994 through
2009"8, contains indices and estimated costs for domestic oil and natural gas equipment and
production operations. The indices and cost trends track costs for representative operations in six
regions (California, Mid-Continent, South Louisiana, South Texas, West Texas, and Rocky
Mountains) with producing depths ranging from 2000 to 16,000 feet and low to high production
rates (for example, 50,000 to 1 million cubic feet per day for natural gas).
Figure 2-10 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, but 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. Oil costs and prices
again generally rose between 2000 and 2009, with a peak in 2008. The 2009 index values for
crude oil operating and equipment costs are 154 and 107, respectively.
8 U.S. Energy Information Administration. "Oil and Gas Lease Equipment and Operating Costs 1994 through 2009."
September 28, 2010.
Accessed February 2, 2011.
2-35
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200
1976 1979 1982 1985
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), 1976-20099
Source: U.S. Energy Information Administration. "Oil and Gas Lease Equipment and Operating Costs 1994 through
2009." September 28, 2010.
Accessed February 2, 2011.
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.
9 The last release date for the EIA's Oil and Gas Lease Equipment and Operating Costs analysis was September
2010. Updates have been discontinued.
2-36
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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
Source: U.S. Energy Information Administration. "Oil and Gas Lease Equipment and Operating Costs 1994 through
2009." September 28, 2010.
Accessed February 2, 2011.
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 plants 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.
2.6.1 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,
2-37
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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 54 percent of domestic crude oil, 85 percent of domestic
natural gas, and drill almost 95 percent of the wells in the U.S (IPAA, 2012-13). 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 2012, there were 6,679 firms within the 211111 and 211112 NAICS codes, of
which 6,551 (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 almost 61 percent
of employment listed under these NAICS. The small and large firms within NAICS 21311 are
similarly distributed, with large firms accounting for about 2 percent of firms, but 56 percent of
employment. Within NAICS 486210, large firms compose about 43 percent of total firms and
about 95 percent of employment.
2-38
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Table 2-16 SB A Size Standards and Size Distribution of Oil and Natural Gas Firms
SBA Size
Standard**
(Employees or *Small *Large *Total
NAICS NAICS Description Annual Receipts) Firms Firms Firms
Number of Firms by Firm Size
211111 Crude Petroleum and Natural Gas Extraction 5001 6,444 92 6,536
211112 Natural Gas Liquid Extraction 5002 107 36 143
213111 Drilling Oil and Gas Wells 5003 2,085 59 2,144
213112 Support Activities for Oil and Gas Operations $38.5 million 8,750 127 8,877
486210 Pipeline Transportation of Natural Gas $27.5 million 92 46 138
Total Employment by Firm Size
211111 Crude Petroleum and Natural Gas Extraction 500 47,528 66,996 114,524
211112 Natural Gas Liquid Extraction 500 1,709 8,768 10,477
213111 Drilling Oil and Gas Wells 500 39,628 66,740 106,368
213112 Support Activities for Oil and Gas Operations $38.5 million 126,523 145,834 272,357
486210 Pipeline Transportation of Natural Gas $27.5 million 1,503 31,823 33,326
*These numbers are reported by Enterprise Employment Size <500 and 500+
Sources: U.S. Census Bureau. Statistics of U.S. Businesses. Accessed January 18, 2016.
U.S. Government Publishing Office. Electronic Code of Regulation, Title 13, Chapter 1, Part 121. Accessed January
18, 2016.
U.S. Small Business Administration, Office of Advocacy. 2014. Firm Size Data. Accessed January 5, 2016.
**The SBA size standards for some of the NAICS were updated in February, 2016.
1. Updated to 1,250 employees
2. Updated to 750 employees
3. Updated to 1,000 employees.
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 2014. The overall trend shows a decline in total
industry employment throughout the 1990s, hitting a low of about 314,000 in 1999, but
rebounding to a 2014 peak of about 660,000. 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.
2-39
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Table 2-17 Oil and Natural Gas Industry Employment by NAICS, 1990-2014
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
Source:
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
189,222
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
7,482
U.S. Bureau of Labor Statistics,
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
98,208
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
326,353
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
10,708
Quarterly Census of Employment and Wages,
. Accessed on January
19, 2016.
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
28,242
2014,
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
660,215
From 1990 to 2014, average wages for the oil and natural gas industry have increased.
Table 2-18 shows real wages (in 2012 dollars) from 1990 to 2014 for the NAICS codes
associated with the oil and natural gas industry. 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.
2-40
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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
2014
Oil and Natural Gas Industry Average Wages by NAICS, 1990-2014 (2012
Crude
Petroleum
and Natural
Gas
Extraction
(211111)
74,510
76,016
80,259
81,252
83,014
85,381
88,360
94,353
97,915
103,283
115,071
116,471
115,367
116,216
127,383
133,983
145,726
143,333
153,226
141,818
152,145
156,107
155,735
152,884
157,827
Natural
Gas
Liquid
Extraction
(211112)
69,910
70,026
72,319
72,271
74,311
70,906
72,290
83,408
94,471
93,896
117,532
116,567
108,753
118,377
124,432
134,481
140,751
140,394
132,644
131,569
132,041
120,995
136,353
122,618
123,305
Drilling of
Oil and
Natural
Gas Wells
(213111)
44,213
45,614
45,704
47,508
46,739
48,485
51,280
54,780
55,718
57,242
63,817
64,822
65,257
64,125
66,282
74,521
78,083
86,745
86,886
85,894
86,337
91,928
92,266
92,610
95,454
Support
Activities
for Oil and
Gas Ops.
(213112)
48,033
49,601
51,379
52,674
52,590
53,319
55,426
58,370
60,473
62,786
63,535
64,328
62,876
64,398
65,703
70,786
74,119
76,134
78,468
74,614
77,810
81,479
80,222
80,405
83,364
Pipeline
Trans, of
Crude Oil
(486110)
71,265
72,311
77,977
76,481
79,827
82,756
80,627
82,343
83,066
86,666
85,034
87,404
91,806
91,831
98,426
96,951
96,738
101,563
107,886
106,237
108,906
114,764
120,292
116,055
109,590
Pipeline
Trans, of
Natural
Gas
(486210)
64,482
68,260
70,505
70,810
71,838
75,453
80,141
86,898
88,409
99,165
136,971
128,302
96,055
96,154
98,531
95,061
104,104
111,528
105,176
106,647
112,910
116,320
139,127
116,460
116,679
Total
62,274
63,916
67,466
67,765
68,090
69,667
71,760
75,390
77,429
83,007
91,032
89,458
86,280
86,755
91,002
95,074
100,131
101,771
105,060
102,241
106,572
108,914
108,872
106,881
108,807
Source: U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2014, annual wages per
employee . Accessed on January 21, 2016.
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
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
2-41
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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 increasingly performed by the integrated major companies. Several
natural gas firms operate multiple facilities. However, natural gas wells are not exclusive to
natural gas firms. 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 independent firms have to rely solely on profits generated at
the 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.
2-42
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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,
though now it has been reduced to the top 150. In 2014, 143 public companies are listed; in 2013
there were 139 firms.10 The 2012 list contains four companies that were not on the list in the
previous year. Table 2-19 lists selected statistics for the top 20 companies in 2014. The results
presented in the table reflect a decline in U.S. oil prices.
Net income for the top 134 companies fell about 17.5% between 2013 and 2014 to about
$74 billion. Revenues for these companies increased by about $6 billion from 2013 to 2014,
reaching $920.5 billion. Even though net revenue decreased in 2014, companies continued to
invest. Capital and exploratory spending for the companies in 2014 totaled $226.4 billion, up
9.3% from 2013.
The total worldwide liquids production for the 143 firms increased 8.41 percent 3.32
billion bbl, while total worldwide gas production increased 0.54 percent to a total of 17 tcf (Oil
and Gas Journal, September 7, 2015). Meanwhile, the firms increased both oil and natural gas
production and reserves from 2013 to 2014. Domestic production of liquids increased about
16.73 percent from 2013 to 1.97 billion bbl, and domestic natural gas production was up about
3.95 percent to 12.4 tcf in 2014. US liquids reserves from the OGJ150 firms increased by 9.85%
up to 25.53 billion bbl, and US natural gas reserves increased by 8.56% to 172.92 tcf. For
context, the OGJ150 domestic crude production represents about 62 percent of total domestic
production (3.18 billion bbl, according to EIA) in 2014. The OGJ150 natural gas production
represents about 48 percent of total domestic production (31.3 tcf, according to EIA) in 2014.
1 Oil and Gas Journal. "OGJ150 Earnings Down as US Production Climbs." September 2, 2013.
2-43
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Table 2-19 Top 20 Oil and Natural Gas Companies (Based on Total Assets), 2012
Worldwide
Production
Rank by
Total
Assets
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Company
ExxonMobil Corp.
Chevron Corp.
ConocoPhillips
Anadarko Petroleum Corp.
Occidental Petroleum Corp.
Apache Corp.
Devon Energy Corp.
Chesapeake Energy Corp.
Hess Corp.
Marathon Oil Corp.
EOG Resources Inc.
Noble Energy Inc.
Freeport-McMoRan Inc.
Murphy Oil Corp.
Linn Energy LLC
Continental Resources Inc.
Pioneer Natural Resources Co.
Southwestern Energy Corp.
Whiting Petroleum Corp.
Denbury Resources Corp.
Employees
75,300
64,700
19,100
6,100
11,700
4,950
6,600
5,500
3,045
3,330
3,000
2,735
35,000
1,712
1,800
300
4,075
2,781
1282
1,523
Total
Assets
($Million)
349,493
266,026
116,539
61,689
56,259
55,952
50,637
40,751
38,578
36,011
34,763
22,553
20,834
16,742
16,424
15,145
14,926
14,925
14,020
12,728
Total Net
Revenue Income
($Million) ($Million)
411,939
211,970
55,517
18,470
21,947
13,851
19,566
20,951
11,439
11,258
18,035
5,101
4,710
5,476
4,983
4,802
5,055
4,038
3,085
2,435
33615
19310
6938
-1563
630
-5060
1691
2056
2374
3046
2915
1214
-4479
906
-452
977
930
924
65
635
Liquids
(Million
bbl)
631
508
270
154
163
142.2
129
75.4
89
118
134.7
49
43
55.4
38.8
44.53
48.48
0.466
36.77
25.77
Natural
Gas
(Bcf)
2,645
1,744
1,443
951
331
580
701
1095
197
295
506.3
362
82
162.8
209
114
154.4
765
30.22
8.379
US
Production
Liquids
(Million
bbl)
111
166
172
118
87
70.25
67
75.4
54
68
132
32
43
25
38.8
44.53
48.48
0.466
36.77
25.77
Natural
Gas
(Bcf)
1,346
456
679
951
173
215.8
660
1095
66
113
348.4
189
82
32.3
209
114
154.4
765
30.22
8.379
Net
Wells
Drilled
732
1125
492
854.6
478.8
816.5
481
682
211
666
869
324.4
210
189
699
388.5
502
221
257.1
55.9
Source: Oil and Gas Journal. "OGJ150" September 7, 2015. 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.
Notes: The source for employment figures is Hoovers, a D&B Company. (Data accessed on January 20, 2016. Employee numbers are for 2014)
2-44
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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 throughput 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,
with large firms owning multiple facilities, which also tend to be relatively large (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.
2-1
-------
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 165 companies in 2014 (Oil and Gas Journal. September 7, 2015,
"Gas Pipeline Table," pp. 126-128). 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 2014. 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 Top 20
pipeline companies and the Top 20 firms from the OGJ150. This observation shows that the
pipeline industry is still largely based upon firms serving regional markets.
The top 20 companies maintain about 58 percent of the total pipeline mileage and
transport about 52 percent of the total volume of the industry (Table 2-21). Operating revenues
2-2
-------
of the top 20 companies equaled $13.2 billion, representing 54 percent of the total operating
revenues for major and non-major companies. The top 20 companies also account for 69 percent
of the net income of the industry.
Table 2-21 Performance of Top 20 Gas Pipeline Companies (Based on Net Income), 2014
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Transmission
Company (miles)
Tennessee Gas Pipeline Co.
Texas Eastern Transmission LP
Dominion Transmission Inc.
Transcontinental Gas Pipe Line Co. LLC
Florida Gas Transmission Co. LLC
Columbia Gas Transmission LLC
Northern Natural Gas Co.
Southern Natural Gas Co.
ETC Tiger Pipeline LLC
Kinder Morgan Lousiana Pipeline LLC
Natural Gas Pipeline Co. of America
Rockies Express Pipeline LLC
El Paso Natural Gas Co.
Colorado Interstate Gas Co.
Northwest Pipeline LLC
Dominion Cove Point LNG LP
Texas Gas Transmission LLC
Enable Gas Transmission LLC
Lake Charles LNG Co. LLC1 (new)
Equitrans LP
TOTAL FOR TOP 20
TOTAL FOR ALL COMPANIES
11,917
9,592
3,842
9,183
5,324
9,641
14,781
7,033
196
136
9,122
1,712
10,222
4,225
3,890
136
5,766
5,902
-
900
113,520
195,194
Vol. trans
for others
(MMcf)
2,990,155
2,610,451
1,151,691
4,655,090
902,592
1,379,418
1,025,465
961,725
340,851
2,803
1,417,903
789,454
1,318,671
839,291
686,974
92,710
1,154,029
913,254
-
635,883
23,868,410
46,293,010
Operating
Revenue
($OOOs)
1,192,621
1,165,248
1,042,755
1,413,206
795,990
1,116,715
749,039
577,037
279,299
265,334
651,548
805,485
577,604
402,882
470,050
296,555
406,562
494,067
216,247
268,052
13,186,296
24,514,239
Net
Income
($OOOs)
331,768
318,519
308,512
289,463
234,412
200,271
150,275
146,469
130,851
130,678
116,693
116,630
113,429
108,983
107,172
97,654
97,237
93,115
92,236
92,036
3,276,403
4,776,194
Source: Oil and Gas Journal. September 7, 2015. "Gas Pipeline Table" pp. 126-128.
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 major U.S. energy producers and reports
summary information in the publication "The Performance Profiles of Major Energy
Producers".11 This information is used in annual report to Congress, and is released to the public
in aggregate form. While the companies that report information to the FRS each year changes,
11 The "Performance Profiles of Major Energy Producers 2009" released on February 25, 2011 is the most recent
release of this report.
2-3
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the EIA makes an effort to retain sufficient consistency to reliably evaluate trends. For 2009, 30
companies in the FRS12 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 aggregates a series of financial trends
selected from the FRS firms' financial statements presented in 2008 dollars. The table shows
operating revenues and expenses rising significantly from 1990 to 2008, with operating income
(the difference between operating revenues and expenses) rising as well, followed by all three
financial factors 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, though the decrease
in net income spans both 2008 and 2009 mainly as a factor of oil and natural gas prices declining
significantly during the latter half of 2008.
12 Alenco, Alon USA, Anadarko Petroleum Corporation, Apache Corporation, BP America, Inc., Chalmette,
Chesapeake Energy Corporation, Chevron Corporation, CITGO Petroleum Corporation, ConocoPhillips, Devon
Energy Corporation, El Paso Corporation, EOG Resources, Inc., Equitable Resources, Inc., Exxon Mobil
Corporation, Hess Corporation, Hovensa, Lyondell 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.
2-4
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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 expenses (excluding interest expense), discontinued operations,
extraordinary items, and accounting changes. Totals may not sum due to independent rounding.
Table 2-23 shows the estimated return on investments in percentage terms 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 as a highly profitable line of business in 2008 for the FRS
companies quickly followed by a significant decline in 2009.
2-5
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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
11.9
8.1
10.7
2.4
2.4
17.8
16.3
26.2
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)13 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.
The difference between total current taxes and U.S. federal, state, and local taxes 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.
; Data was withheld in 2009 to avoid disclosure.
2-6
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Table 2-24 Income and Production Taxes, 1990-2009 (Million 2008 Dollars)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009*
US Federal, State,
and Local Taxes
Paid or Accrued
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
Total Current
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
Total
Deferred
-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
Total Income
Tax Expense
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, Form EIA-28 (Financial Reporting System).
*In 2009, data on the U.S. Federal Investment Tax Credit and U.S. State and Local Income Taxes were withheld to
avoid disclosure.
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.
Federal Reserve Bank of St. Louis. Economic Research. Gross Domestic Product: Implicit Price
Deflator. . Accessed February 3,
2016.
Hyne, NJ. 2001. Nontechnical Guide to Petroleum Geology, Exploration, Drilling and
Production. Tulsa, OK: Pen well Books.
Independent Petroleum Association of America. 2009. Profile of Independent Producers.
Accessed
March 30, 2011.
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Independent Petroleum Association of American. 2012-2013. Profile of Independent Producers.
. Accessed on January 30, 2016.
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.
Oil and Gas Journal. September 7, 2015. "OGJ150".
Oil and Gas Journal September 7, 2015. "Gas Pipeline Table", pp.126-128.
Oil and Gas Journal. September 7, 2015. "OGJ150 scores higher production, lower earnings".
. Accessed January 27, 2016.
U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2014,
. Accessed on January 19, 2016.
U.S. Bureau of Labor Statistics, Quarterly Census of Employment and Wages, 2014,
. Accessed on January 21, 2016.
U.S. Census Bureau. Statistics of U.S. Businesses.
. Accessed January 18, 2016.
U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration,
Office of Pipeline Safety. Annual Report Mileage Summary Statistics.
. Accessed January 4, 2016.
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.
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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.
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. Energy Information Administration (U.S. EIA). 2014. Natural Gas Annual 2014.
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U.S. Energy Information Administration (U.S. EIA). November 2015. U.S. Crude Oil and
Natural Gas Proved Reserves, 2014. Table 7 and Table 17.
. Accessed January
15,2016.
U.S. Energy Information Administration (U.S. EIA). U.S. Imports by Country of Origin.
.
Accessed January 22, 2016.
U.S. Energy Information Administration (U.S. EIA). U.S. Exports by Destination.
. Accessed
January 22, 2016.
U.S. Energy Information Administration (U.S. EIA). U.S. Natural Gas Imports & Exports by
State. .
Accessed January 21, 2016.
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U.S. Energy Information Administration (U.S. EIA). April 2015. Annual Energy Outlook 2015
with Projections to 2040. .
Accessed January 25, 2016.
U.S. Energy Information Administration (U.S. EIA). April 2015. Annual Energy Outlook 2015
with Projections to 2040. .
Accessed January 19, 2016.
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Major Energy Producers, 2009. Table 9, Figure 15, and Figure 17 data.
. Accessed January 27, 2016.
U.S. Energy Information Administration (U.S. EIA). Crude Oil Production.
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29, 2016.
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.
Accessed on January 22, 2016.
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Accessed February 1, 2016.
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. Accessed January 5, 2016.
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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-
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New Source Performance Standards and Amendments to the National Emissions
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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 final 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 an overview of
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 detailed Technical Support Document (TSD)
prepared by the EPA for the reader interested in a greater level of detail.14
3.2 Sector Emissions Overview
This section provides estimates of overall emissions from the crude oil and natural gas
industry to provide context for estimated reductions as a result of the 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: 1990-2014 (to be published April 15, 2016) estimates 2014 methane emissions from
Petroleum and Natural Gas Systems (not including petroleum refineries and petroleum
transportation) to be 232 MMt COi Eq. In 2014, total methane emissions from the oil and gas
industry represented 32 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,
2016).
For the analysis supporting this final action, including this RIA, we used the methane
100-year global warming potential (GWP) of 25 to be consistent with and comparable to key
Agency emission quantification programs such as the Inventory of Greenhouse Gas Emissions
and Sinks (GHG Inventory) and the Greenhouse Gas Reporting Program (GHGRP).15 The use of
14 U.S. EPA. 2016. 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.
15 See, for example Table A-l to subpart A of 40 C.F.R. part 98.
3-1
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the 100-year GWP of 25 for methane value is currently required by the UNFCCC for reporting
of national inventories, such as the GHG Inventory. Updated estimates for methane GWP have
been developed by IPCC (2013).16 The most recent 100-year GWP estimates for methane, which
are presented in the IPCC Fifth Assessment Report (AR5, 2013), range from 28-36. In
discussing the science and impacts of methane emissions generally, we use the GWP range of
28-36. When presenting emissions estimates, we use the GWP of 25 for consistency and
comparability with other emissions estimates in the U.S. and internationally.
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. Additional
technical details on the engineering and cost basis of the analysis is presented in 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 techniques that have been proven to reduce emissions from well
completions: reduced emissions completions (RECs) and completion combustion, as well as re-
injecting the natural gas back into the well or another well, using the gas as an on-site fuel
source, or use for another beneficial purpose. 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. Technical barriers to the operation of a separator
16 IPCC, 2013: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth
Assessment Report of the Intergovernmental Panel on Climate Change [Stacker, 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, 1535 pp.
3-2
-------
such as well pressure and flowback composition can limit the feasibility of RECs in some
situations. Other barriers, such as proximity of pipelines, may prevent recovered gas from being
routed to a sales line, but do not necessarily prevent reinjection or on-site use.
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 valves, connectors, pressure relief devices, open-ended lines, flanges,
closed vent systems, and thief hatches or other openings on a controlled storage unit. These
fugitive emissions do not include devices that vent as part of normal operations.
The TSD considers fugitive emissions from production wellsites and compressor stations.
The EPA considered 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 bleed
pneumatic controllers can be classified into two types based on their emissions rates: (1) high-
bleed controllers and (2) low-bleed controllers. 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
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by raising or reducing the pressure of the fluid by means of a positive displacement, a piston or a
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
pumps are generally used to pump 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
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 wellsites 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, several options for
reducing methane and VOC emissions were identified: replace a natural gas-assisted pump with
an instrument air pump, replace a natural gas-assisted pump with a solar-charged direct current
pump (solar pumps), replace a natural gas-assisted pump with an 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
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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 control options reviewed for reducing
emissions from reciprocating compressors include control techniques that limit the leaking of
natural gas past the piston rod packing. This includes replacement of the compressor rod
packing, replacement of the piston rod, and the refitting or realignment of the piston rod.
Emissions from centrifugal compressors depend on the type of seal used: either "wet",
which use oil circulated at 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 NSPS. A detailed
discussion of the methodology used to estimate cost impacts is presented in the TSD.
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. Second, the number of incrementally affected facilities for each type of
equipment or facility are projected. National emissions reductions and cost estimates are
calculated by multiplying representative factors, from the first step, by the estimated number of
affected facilities in each projection year, from the second step. 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.
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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,
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. 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.
Option 2 was selected for promulgation.
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Table 3-1 Emissions Sources and Controls Evaluated for the NSPS
Emissions Point
„ . . „ . , Option 1 Option 2 /->-•-,
Emissions Control ,„. ,, Option 3
(final) r
Well Completions and Recompletions
Hydraulically Fractured
Development Oil Wells
Hydraulically Fractured Wildcat
and Delineation Oil Wells
Fugitive Emissions
Well Sites
Gathering and Boosting Stations
Transmission Compressor Stations
Pneumatic Pumps
Well Sites
Pneumatic Controllers
Natural Gas Transmission and
Storage
Reciprocating Compressors
Natural Gas Transmission and
Storage
Centrifugal Compressors
Natural Gas Transmission and
Storage
RFC / Combustion X
Combustion X
X
X
Planning,
Monitoring and
Maintenance
Planning,
Monitoring and
Maintenance
Planning,
Monitoring and
Maintenance
Annual Semiannual Quarterly
Semiannual Quarterly Quarterly
Semiannual Quarterly Quarterly
Route to control X
Emissions limit X
Maintenance X
Route to control X
X
X
X
X
X
X
The selected 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 requires fugitive emissions survey and repair programs be
semiannually (twice per year) at the affected newly drilled or refractured oil and natural gas well
sites, and quarterly at new or modified gathering and boosting stations and new or modified
transmission and storage compressor stations. Option 2 also requires reductions from centrifugal
compressors, reciprocating compressors, and pneumatic controllers throughout the oil and
natural gas source category.
The unselected Options 1 and 3 differ from the selected Option 2 with respect to the
requirements for fugitive emissions. Option 1 requires fugitive emissions survey and repair
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programs be performed annually at the affected newly drilled or refractured oil and natural gas
well sites, and semiannually at new or modified gathering and boosting stations and new or
modified transmission and storage compressor stations. Fewer surveys being performed leads to
lower costs and emissions reductions than under the selected Option 2. Finally, the more
stringent Option 3 requires quarterly monitoring for all sites under the fugitive emissions
program. More frequent surveys result in higher costs and higher emissions reductions than
Option 2.
3.4.2 Projection of Incrementally Affected Facilities
The second step in estimating national costs and emissions impacts of the final 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
NSPS. Facilities in states with similar state-level requirements and facilities with only
recordkeeping requirements are not included within incrementally affected facilities.
The years of analysis are 2020, to represent the near-term impacts of the rule, and 2025,
to represent impacts of the rule over a longer period. Therefore, the emissions reductions,
benefits, and costs by 2020 and 2025 (i.e., including all emissions reductions, costs, and benefits
in all years from 2016 to 2025) would be potentially significantly greater than the estimated
emissions reductions, benefits, and costs provided within this rule. Affected facilities are
facilities that are new or modified since the proposal in September 2015. In 2020, affected
facilities are those that are newly established or modified in 2020, as well as those that have
accumulated between 2016 and 2019. 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, and also facilities which were newly established
or modified from 2016 through 2024 and are still operating in 2025. The analysis has assumed
that all new equipment and facilities established from 2016 through 2024 are still in operation in
2025. This approach differs from the way affected facilities were estimated in the proposal RIA.
At proposal, 2020 was assumed to represent a single year of potential impacts, and 2025
included newly established or modified facilities from 2020 through 2024. This methodological
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change results in a higher estimate of the number of affected facilities than at proposal and better
represents the impacts of the rule.
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) Annual Energy Outlook (AEO). The EPA derived typical counts for new
compressors, pneumatic controllers, and pneumatic pumps by averaging the year-to-year changes
over the past ten years in the GHG Inventory. New and modified hydraulically fractured oil well
completions and wellsites are based on projections and growth rates consistent with the drilling
activity in the Annual Energy Outlook. For the final RIA, the projections have been updated to
reflect the projections in the 2015 Annual Energy Outlook. In addition, while the projections
used in the proposal RIA were based on the long-term growth trajectory from 2012 to 2025, the
current analysis is based on the full times series in the 2015 AEO reference scenario.
The 2015 Annual Energy Outlook was the most recent projection available at the time the
analysis underlying this RIA was being prepared. The 2015 AEO includes the growth in U.S.
crude oil production over the last two years, along with the late-2014 drop in global crude oil
prices, and reflects how these factors have altered the economics of the oil market. In
comparison to the 2014 AEO reference case, the 2015 AEO reference case shows higher crude
oil production (18 percent higher for 2025 in the 2015 AEO), slightly lower natural gas
production (about 4 percent lower for 2025 in the 2015 AEO), lower Brent spot and West Texas
Intermediate crude oil prices, and lower total wells drilled in the lower 48 states (about 20
percent lower for 2025 in the 2015 AEO).
While it is desirable to analyze impacts beyond 2025 in this RIA, the EPA has chosen not
to largely because of the limited information available on the turnover rate of emissions sources
and controls. For this RIA, we have used the U.S. EIA's National Energy Modelling System
(NEMS) to generate a limited set of future year projections to inform impact estimates for subset
of affected sources. We also used the model to estimate key market impacts of the rules, based
upon EPA's parameterization of regulatory costs and natural gas capture in the model. While
NEMS produces highly regarded projections of production and well drilling, and is useful to
estimate market impacts of the NSPS, it is not a compliance model and does not directly model
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affected units. In addition, in a dynamic industry like oil and natural gas, technological progress
in control technology is also likely to be dynamic. These factors make it reasonable to use 2025
as the latest year of analysis as extending the analysis beyond 2025 would introduce substantial
and increasing uncertainties in projected impacts of the NSPS.
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
Colorado and Wyoming both require RECs for hydraulically fractured oil and gas wells, and
North Dakota requires combustion of completion emissions. 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.
This means that any additional costs and benefits incurred by facilities in these states to comply
with the federal standards beyond the state requirements (e.g., to comply with the on-site
separator requirement) are not reflected in this RIA. A more detailed discussion on the derivation
of the baseline for this rule is presented for each emissions source in the TSD. In section 4.3.1 of
the TSD, Table 4-3 provides a detailed breakout of affected oil well completions.
Table 3-2 Incrementally Affected Sources under Final NSPS, 2016 to 2025 on an
Annual Basis
Incrementally Affected Sources1
Emissions Sources 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Oil Well Completions
and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
13,000
19,000
790
33
96
32,000
13,000
19,000
790
33
96
32,000
13,000
19,000
790
33
96
33,000
13,000
19,000
790
33
96
33,000
13,000
19,000
790
33
96
33,000
13,000
19,000
790
33
96
33,000
13,000
19,000
790
33
96
33,000
13,000
20,000
790
33
96
34,000
14,000
20,000
790
33
96
35,000
14,000
21,000
790
33
96
35,000
1 Incrementally affected sources includes sources that have to change their control activity as a result of the rule.
The table does not include estimate counts of a) affected facilities in states with similar state-level requirements to
the NSPS, b) facilities with only recordkeeping requirements, or c) replacement or modification of existing sources
except in the case of oil well completions and fugitive emissions at wellsites.
Table 3-2 presents the number of affected sources for each year of analysis after
generally accounting for state regulations. In addition to the caveats regarding facilities affected
by state regulations described above, facilities with only recordkeeping requirements are also not
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included within incrementally affected facilities (e.g., wells with low GOR are not included in
the estimate of facilities affected by the oil well completion requirements).
Table 3-3 Total Number of Affected Sources for the NSPS in 2020 and 2025
Emissions Sources
Hydraulically Fractured and Re-fractured Oil Well Completions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total2
Affected
2020
13,0003
94,000
3,900
170
480
110,000
Sources1
2025
14,0003
190,000
7,900
330
960
220,000
1 In addition to newly affected sources in 2020, total affected sources in 2020 include sources that become affected
in the 2016-2019 period and are assumed to be in continued operation in 2020. Similarly, affected sources in 2025
reflect sources newly constructed or modified from 2016 to 2025, assumed to still be in operation in 2025. The table
does not include estimate counts of: a) affected facilities in states already regulating those sources, b) facilities with
only recordkeeping requirements, or c) replacement or modification of existing sources except for oil well
completions and fugitive emissions at wellsites. Estimates are rounded to two significant digits.
2 Totals may not sum due to independent rounding.
3 Affected oil well completions include a mix of RECs and flaring based on subcategory and technical infeasibility
criteria. Exploratory and delineation wells are required to combust emissions. Of development oil well completions,
50% are estimated to be feasible to perform a REC; the remainder would combust emissions (either because they are
unable to implement a REC due to low pressure or other technical infeasibility reasons). See section 4.3.1 of the
TSD for a detailed breakout of affected oil well completions
Table 3-3 presents estimates of the total number of affected sources for this final rule.
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 hydraulically fractured and
re-fractured oil well completions and fugitive emissions at wellsites (a large fraction of the
incrementally affected sources under the fugitive emissions provisions) include both new and
modified sources.
The estimates for other sources are based upon projections of new sources alone, and do
not include replacement or modification of existing sources. While some of these sources are
unlikely to be modified, particularly pneumatic pumps and controllers, the impact estimates may
be under-estimated due to the focus on new sources. In the proposal, the EPA solicited
comments on these projection methods as well as solicits information that would improve our
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estimate of the turnover rates or rates of modification of relevant sources, as well as the number
of wells on wellsites. While the EPA received comments on the projection methods used in the
proposal RIA, we did not receive comments with sufficient information to further incorporate
modification and turnover in the projection methodologies. The EPA has modified its
methodology for using historical inventory information to estimate new sources reflecting
comments received, resulting in lower estimates of the number of new compressor stations,
pumps, compressors, and pneumatic controllers constructed each year. Newly constructed
affected facilities are estimated based on averaging the year-to-year changes in the past 10 years
of activity data in the Greenhouse Gas Inventory for compressor stations, pneumatic pumps,
compressors, and pneumatic controllers. At proposal, this was done by averaging the increasing
years only. The approach was modified to average the number of newly constructed units in all
years. In years when the total count of equipment decreased, there were assumed to be no newly
constructed units.
3.4.3 Emissions Reductions
Table 3-4 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. The detailed description of emissions controls is
provided in the TSD. Please note that all results have been rounded to two significant digits.
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Table 3-4 Emissions Reductions for Final NSPS Option 2, 2020 and 2025
Source/Emissions
Point
Oil Well Completions
and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
Source/Emissions
Point
Oil Well Completions
and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
Methane
(short tons)
120,000
170,000
13,000
4,000
1,300
300,000
Methane
(short tons)
120,000
350,000
26,000
8,100
2,700
510,000
Emissions
VOC
(short tons)
97,000
46,000
3,600
110
37
150,000
Emissions
VOC
(short tons)
100,000
94,000
7,200
220
74
210,000
Reductions, 2020
HAP
(short tons)
12
1,700
140
3
1
1,900
Reductions, 2025
HAP
(short tons)
12
3,600
270
7
2
3,900
Methane
(metric tons CCh Eq.)
2,600,000
3,800,000
290,000
92,000
30,000
6,900,000
Methane
(metric tons CCh Eq.)
2,800,000
7,900,000
590,000
180,000
61,000
11,000,000
3.4.4 Product Recovery
The annualized cost estimates presented below include revenue from additional natural
gas recovery. Several emission controls for the NSPS capture methane and VOC emissions that
would otherwise be vented to the atmosphere. A large proportion of the averted methane
emissions can be directed into natural gas production streams and sold. For the environmental
controls that avert the emission of saleable natural gas, we base the estimated revenues from
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averted natural gas emissions on an estimate of the amount of natural gas that would not be
emitted during one year.
The controls 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 the use of low-bleed pneumatic devices. The 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 EIA's 2015 Annual Energy Outlook reference case projects Henry Hub natural gas prices to
be $4.88/MMBtu in 2020 and $5.46/MMBtu in 2025 in 2013 dollars.17 After adjusting to $/Mcf
(using the conversion of 1 MMBtu = 1.028 Mcf) in 2012 dollars (using the GDP-Implicit Price
Deflator), these prices are $4.94/Mcf in 2020 and $5.52 in 2025. When including the additional
natural gas recovery in the main cost analysis, we assume that producers are paid $4 per
thousand cubic feet (Mcf) for the recovered gas at the wellhead. The $4/Mcf price assumed in
this RIA is intended to reflect the AEO estimate but simultaneously be conservatively low and
also account for markup on the natural gas between the wellhead and the Henry Hub for
processing and transportation.18
Operators in the gathering and boosting, and transmission and storage parts of the
industry do not typically own the natural gas they transport; rather, the operators receive
payment for the transportation service they provide. As a result, the unit-level cost and emission
reduction analyses supporting BSER decisions in the preamble (and presented in Volume 1 of
17 Available at: http://www.eia.gov/forecasts/aeo/tables_ref.cfm.
18 An EIA study indicated that the Henry Hub price is, on average, about 11 percent higher than the wellhead price.
See http://www.eia.gov/oiaf/analysispaper/henryhub/.
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the TSD) do not include estimates of revenue from natural gas recovery as offsets to compliance
costs. From a social perspective, however, the increased financial returns from natural gas
recovery accrues to entities somewhere along the natural gas supply chain and should be
accounted for in the national impacts analysis. An economic argument can be made that, in the
long run, no single entity is going to bear the entire burden of the compliance costs or fully
receive the financial gain of the additional revenues associated with natural gas recovery. The
change in economic surplus resulting from natural gas recovery is going to be spread out
amongst different agents via price mechanisms. Therefore, the most simple and transparent
option for allocating these revenues would be to keep the compliance costs and associated
revenues together in a given source category and not add assumptions regarding the allocation of
these revenues across agents. This is the approach followed in Volume 2 of the TSD, as well as
in the RIA.
Table 3-5 Estimated Natural Gas Recovery (Mcf) for selected Option 2 in 2020 and
2025
Source/Emissions Point
Oil Well Completions and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Total
2020
Gas recovery
(Mcf)
5,700,000
9,800,000
0
180,000
69,000
16,000,000
Value of
recovery
$23,000,000
$39,000,000
$0
$720,000
$280,000
$63,000,000
2025
Gas recovery
(Mcf)
6,100,000
20,000,000
0
360,000
140,000
27,000,000
Value of
recovery
$24,000,000
$80,000,000
$0
$1,400,000
$550,000
$110,000,000
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. In
addition, there is geographic variability in wellhead prices, which can also influence estimated
engineering costs. For Option 2, a $l/Mcf change in the wellhead price causes a change in
estimated engineering compliance costs of about 5 percent. Section 3.5.2 further examines the
sensitivity of national compliance costs to natural gas prices.
3.4.5 Engineering Compliance Costs
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Table 3-6 summarizes the capital and annualized costs and revenue from product
recovery for the evaluated emissions sources and points. The capital costs represent total capital
cost expenditures associated with affected units in 2020 and 2025, including capital cost
expenditures made prior to the analysis year. The detailed description of cost estimates is
provided in TSD. To estimate total annualized engineering compliance costs, we added the
annualized costs of each item without accounting for different expected lifetimes. This approach
is mathematically equivalent to establishing an overall, representative project time horizon and
annualizing costs after consideration of control options that would need to be replaced
periodically within the given time horizon.
Table 3-6 Engineering Compliance Cost Estimates for Final NSPS Option 2 in 2020
and 2025 (millions 2012$)
Compliance Costs, 2020
Source/Emissions Point
Oil Well Completions and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Reporting and Recordkeeping
Total
Capital
Costs1
$150
$77
$21
$1.4
$0.1
$0
$250
Annualized
Costs (without
savings)
$150
$230
$3
$0.9
$0.0
$6.3
$390
Revenue
from
Product
Recovery
$23
$39
$0
$0.7
$0.3
$0
$63
Nationwide
Annualized Costs
with Addl. Revenue
(2012$)
$130
$190
$3.1
$0.2
-$0.27
$6.3
$320
Compliance Costs, 2025
Source/Emissions Point
Oil Well Completions and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Reporting and Recordkeeping
Total
Capital
Costs1
$160
$160
$43
$2.9
$0.2
$0.0
$360
Annualized
Costs (without
savings)
$160
$460
$6
$1.8
$0.0
$6.3
$640
Revenue
from
Product
Recovery
$24
$80
$0
$1.4
$0.6
$0
$110
Nationwide
Annualized Costs
with Addl. Revenue
(2012$)
$130
$380
$6
$0.3
-$0.5
$6.3
$530
1 Capital costs represent total capital costs associated with control of affected sources in 2020 and 2025, including
expenditures made in previous years. Sums may not total due to independent rounding.
Engineering capital costs were annualized using a 7 percent interest rate. Section 3.4
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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 to
annualize capital costs of emissions controls:
• Reduced emissions completions and combustion devices: 1 year
• Fugitive emissions monitoring program design: 8 years
• Reciprocating compressors rod packing: 3.8 - 4.4 years
• Centrifugal compressors and pneumatic pumps: 10 years
• Pneumatic controllers: 15 years
Note the large majority of capital costs are required for the completions fugitive emissions
requirements. Alternative assumptions of the lifetimes of these expenditures are most likely
influence estimates of total compliance costs, where alternative assumptions for compressors,
pumps, and controllers would likely to have relatively small effects.
Reporting and recordkeeping costs were drawn from the information collection
requirements (ICR) in this final rule that have been submitted for approval to the Office of
Management and Budget (OMB) under the Paperwork Reduction Act (see Preamble for more
detail). The 2020 and 2025 reporting and recordkeeping costs in this RIA are assumed to be
equal to the third year cost reporting in the ICR cost estimates ($6.3 million). These
recordkeeping and recordkeeping costs are estimated for the selected Option 2 for all new and
modified facilities regardless of whether they implement additional controls as a result of the
NSPS. While these costs may differ across regulatory options as a result of the varying frequency
of the fugitives program across the options, we do not have the information to estimate the ICR
burden for the unselected Option 1 and 3. As a result, we assume all options have the same
recordkeeping and reporting cost burden. Note also that reporting and recordkeeping costs are
included for all affected entities, regardless of whether they are in states with regulatory
requirements similar to the final NSPS.
3.4.6 Comparison of Regulatory Alternatives
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Table 3-7 presents a comparison of the regulatory alternatives through each step of the
emissions analysis in 2020 and 2025. The requirements between the options vary with respect to
the fugitive emissions requirements. The less stringent Option 1 requires annual monitoring for
well sites under the fugitive emissions program and semi-annual for compressor stations. The
more stringent Option 3 requires quarterly monitoring for all sites under the fugitive emissions
program. Annual, semi-annual, and quarterly fugitive emissions surveys are assumed to result in
reductions in emissions of 40 percent, 60 percent and 80 percent, respectively.19 For more
information on these assumptions, please see Section 4.3.2.2 of the TSD. 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. In addition, the ratio between national compliance costs and national
emissions reductions is presented using both the single pollutant and multipollutant approach.
Table 3-7 Comparison of Regulatory Alternatives
Regulatory Alternative
Option 2
Option 1 (final) Option 3
Impacts in 2020
Affected Sources 110,000 110,000 110,000
Emissions Reductions
Methane Emissions Reduction (short tons/year) 250,000 300,000 350,000
VOC Emissions Reduction (short tons/year) 130,000 150,000 160,000
Natural Gas Recovery (Mcf) 13,000,000 16,000,000 19,000,000
Compliance Costs
Capital Costs (2012$) $240,000,000 $250,000,000 $260,000,000
Annualized Costs Without Addl. Revenue (2012$) $290,000,000 $390,000,000 $570,000,000
Annualized Costs With Addl. Revenue (2012$) $240,000,000 $320,000,000 $490,000,000
Impacts in 2025
Affected Sources 220,000 220,000 220,000
Emissions Reductions
Methane Emissions Reduction (short tons/year) 390,000 510,000 610,000
VOC Emissions Reduction (short tons/year) 170,000 210,000 230,000
19 The EPA performed a sensitivity analysis based on the midpoints of the Method 21 emission reduction efficiency
percentages, which were determined to be 55, 65, and 75 percent for annual, semiannual and quarterly
monitoring, respectively. Even based on this conservative analysis, the EPA finds that the chosen monitoring
frequencies are the BSER for these sources. The EPA additionally concluded that the 40, 60, and 80 percent
emission reduction efficiency percentages are reasonable and accurate. See section 4.3.2.2 of the final TSD for
further information.
3-18
-------
Natural Gas Recovery (Mcf) 20,000,000 27,000,000 33,000,000
Compliance Costs
Capital Costs (2012$) $350,000,000 $360,000,000 $380,000,000
Annualized Costs Without Addl. Revenue (2012$) $440,000,000 $640,000,000 $1,000,000,000
Annualized Costs With Addl. Revenue (2012$) $360,000,000 $530,000,000 $880,000,000
3.5 Engineering Cost Sensitivity Analysis
This section illustrates the sensitivity of engineering cost and emissions analysis results
of Option 2 to choice of discount rate and natural gas prices.
3.5.1 Compliance Costs Estimated Using 3 and 7 Percent Discount Rates
Table 3-8 shows that the choice of discount rate has minor effects on the nationwide
annualized costs of the final rule.
Table 3-8 Annualized Costs using 3 and 7 Percent Discount Rates for Final NSPS
Option 2 in 2020 and 2025 (millions 2012$)
Nationwide Annualized
Costs, 2020
Oil Well Completions and
Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Reporting and Recordkeeping
Total
7 percent
$130
$190
$3.1
$0.16
-$0.27
$6.3
$320
3 percent
$130
$190
$2.5
$0.12
-$0.27
$6.3
$320
Nationwide Annualized
Costs, 2025
7 percent
$130
$380
$6.1
$0.31
-$0.53
$6.3
$530
3 percent
$130
$380
$5
$0.24
-$0.54
$6.3
$520
The choice of discount rate has a small effect on nationwide annualized costs. Discount
rate generally affects estimates of annualized costs for controls with high capital costs relative to
annual 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
3-19
-------
sensitive to interest rate, but these constitute a relatively small part of the total compliance cost
estimates for the rule.
3.5.2 Sensitivity of Compliance Costs to Natural Gas Prices
The annualized compliance cost estimates presented in this RIA include revenue from
additional natural gas recovery, and therefore national compliance costs depend the price of
natural gas. This section examines the sensitivity of national compliance costs to varying natural
gas prices. When including the additional natural gas recovery in the main cost analysis, we
assume that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the
wellhead. As discussed earlier, the $4/Mcf price assumed in this RIA is intended to reflect the
AEO estimate but simultaneously be conservatively low and also account for markup on the
natural gas between the wellhead and the Henry Hub for processing and transportation.
EPA recognizes that current natural gas prices are below $4/Mcf. In 2015, the Henry Hub
Natural Gas Spot Price ranged between about $2 and $3 dollars per MMBtu (about $1.94/Mcf
and $2.91/Mcf, respectively).20 The models used to forecast natural gas prices in the Annual
Energy Outlook are deterministic. A deterministic model does not incorporate potential
stochastic influences and and will therefore producs the same result for each model run using all
else equal. While the Annual Energy Outlook is a commonly referenced publication that
provides mid-term forecasts, the U.S. EIA also produces the Short-Term Energy Outlook
(STEO), which provides confidence intervals for some energy prices over a shorter time frame
based on the prices paid for financial derivatives (e.g., options) based on natural gas. To better
understand the uncertainty associated with the 2020 and 2025 natural gas price assumed in this
analysis, EPA reviewed the March 2016 STEO, which includes monthly forecasted natural gas
prices through 2017.21 While the STEO analysis only extends to the end of 2017, the published
20 Assuming the average heat context of natual gas is 1,028 Btu per cubic foot, 1 Mcf = 1.028 MMBtu. Based on this
assumption, to convert natural gas prices denominated in MMbtu to Mcf, the $/MMbtu is multiplied by 1/1.028
or 0.973.
21 U.S. Energy Information Administration (U.S. EIA). 2016. Short-Term Energy Outlook, March 8, 2016.
March 8, 2016.
3-20
-------
confidence intervals for future natural gas prices can provide some basis for understanding the
potential uncertainty around slightly longer-term forecasts.
In the STEO, forecasted prices are traded futures contracts. Based on this information the
STEO also presents a 95% confidence interval for the price of natural gas through 2017.
However, that the probability analysis uses the Henry Hub spot price, rather than the wellhead
price paid to producer. The EIA analysis projects an expected December 2017 Henry Hub price
of $3.31 per MMBtu ($3.22/Mcf) with a 95 percent confidence interval of $1.45 to $5.25 per
MMBtu ($1.41/Mcf to $5.10/Mcf). While this confidence interval is not for wellhead natural gas
prices, it is relevant for understating the challenges associated with precisely predicting future
natural gas prices.
To analyze the sensitivity of the engineering costs of the rule to assumed natural gas
prices, Table 3-12 presents nationwide annualized costs for each source category assuming
natural gas prices of $2, $3, $4, and $5 per Mcf.
Table 3-9 Annualized Costs Using Natural Gas Prices from $2 to $5 per Mcf
Nationwide Annualized Costs (million
2012$), 2020
Nationwide Annualized Costs
(million 2012$), 2025
Source/Emissions Point $2/Mcf $3/Mcf $4/Mcf $5/Mcf $2/Mcf $3/Mcf $4/Mcf $5/Mcf
Oil Well Completions
and Recompletions
Fugitive Emissions
Pneumatic Pumps
Compressors
Pneumatic Controllers
Reporting and
Recordkeeping
Total
$140
$210
$3.1
$0.52
-$0.13
$6.3
$350
$130
$200
$3.1
$0.34
-$0.20
$6.3
$340
$130
$190
$3.1
$0.16
-$0.27
$6.3
$320
$120
$180
$3.1
-$0.023
-$0.33
$6.3
$310
$150
$420
$6.1
$1
-$0.25
$6.3
$580
$140
$400
$6.1
$0.68
-$0.39
$6.3
$560
$130
$380
$6.1
$0.31
-$0.53
$6.3
$530
$130
$360
$6.1
-$0.046
-$0.67
$6.3
$500
Note that all figures are rounded to two significant digits. Annualized costs are estimated using a 7 percent discount
rate. Totals may not sum due to independent rounding.
For Option 2, a $l/Mcf change in the wellhead price causes a change in estimated
engineering compliance costs of about $16 million in 2020 and $27 million in 2025, in 2012
dollars. In percentage terms, a $1/Mcf reduction in the wellhead price causes about a 5 percent
increase in national compliance costs in either 2020 or 2025. These amounts include revenue
from product recovery in all segments. As decribed above, this approach differs with respect to
3-21
-------
the gathering and boosting and transmission segments between the unit-level cost and emissions
reduction analysis supporting BSER decisions (which is focused on control costs borne by
regulated sources) and this RIA (which is focused on societal costs). Operators in the gathering
and boosting and transmission and storage segments may not own the natural gas they transport,
and so may not be able to offset compliance costs with revenue from product recovery in the
short term. Changes in costs are affected for the oil well completions, fugitive emissions sources,
reciprocating compressors, and pneumatic controllers because control of these sources results in
product recovery. Costs for pumps and centrifugal compressors are not affected because routing
emissions to a control does not result in product recovery. Valued at $4/Mcf, estimated national
gas recovery as a result of the NSPS in the gathering and boosting segment would be about $3
million in 2020 and $6 million in 2025 and in the transmission and storage segment would be
about $2 million in 2020 and $4 million in 2025.
3.6 Detailed Impacts Tables
The following tables show the full details of the costs and emissions reductions by
emissions sources for each regulatory option in 2020 and 2025.
3-22
-------
Table 3-10 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2020
Pr<
Al
I
Ret
Source/Emissions Point
jjected No. of
Ffected Units
For Which
Federal
Regulations
juire Further
Action
Nationwide Emissions Reductions
Methane
(short VOC (short HAP (short
tons/year) tons/year) tons/year)
Methane
(metric tons
C02e)
National Costs
Capital Costs
Annualized
Costs With
Addl.
Revenues
Well Completions and Recompletions
Hydraulically Fractured Development
Oil Wells
Hydraulically Fractured Wildcat and
Dilineation Oil Wells
12,000
990
110,000
9,100
89,000
7,600
11
1
2,400,000
210,000
$140,000,000
$3,700,000
$120,000,000
$3,700,000
Fugitive Emissions
Well Pads
Gathering and Boosting Stations
Tranmission Compressor Stations
94,000
480
45
100,000
10,000
2,600
28,000
2,800
73
1,100
110
2
2,300,000
230,000
59,000
$71,000,000
$1,100,000
$740,000
$100,000,000
$4,200,000
$360,000
Pneumatic Pumps
Well Pads
3,900
13,000
3,600
140
290,000
$21,000,000
$3,100,000
Pneumatic Controllers -
Natural Gas Transmission and
Storage Stations
160
3,500
96
3
79,000
$1,100,000
-$410,000
Reciprocating Compressors
Natural Gas Transmission and
Storage Stations
Centrifigal Compressors
Natural Gas Transmission and
Storage Stations
Reporting and Recordkeeping
TOTAL
5
480
All
110,000
560
1,300
0
250,000
15
37
0
130,000
0
1
0
1,300
13,000
30,000
0
5,600,000
$360,000
$110,000
$0
$240,000,000
$570,000
-$270,000
$6,300,000
$240,000,000
3-23
-------
Table 3-11 Incrementally Affected Units, Emissions Reductions and Costs, Option 1, 2025
Pr.
Al
]
Rei
Source/Emissions Point
ajected No. of
ffected Units
For Which
Federal
Regulations
quire Further
Action
Nationwide Emissions Reductions
Methane
(short VOC (short HAP (short
tons/year) tons/year) tons/year)
Methane
(metric tons
CO2e)
National Costs
Capital Costs
Annualized
Costs With
Addl.
Revenues
Well Completions and Recompletions
Hydraulically Fractured Development
Oil Wells
Hydraulically Fractured Wildcat and
Dilineation Oil Wells
13,000
1,100
110,000
10,000
95,000
8,400
11
1
2,600,000
230,000
$150,000,000
$4,000,000
$130,000,000
$4,000,000
Fugitive Emissions
Well Pads
Gathering and Boosting Stations
Tranmission Compressor Stations
190,000
960
90
210,000
20,000
5,200
58,000
5,600
150
2,200
210
4
4,700,000
460,000
120,000
$150,000,000
$2,300,000
$1,500,000
$200,000,000
$8,300,000
$710,000
Pneumatic Pumps
Well Pads
7,900
26,000
7,200
270
590,000
$43,000,000
$6,100,000
Pneumatic Controllers -
Natural Gas Transmission and
Storage Stations
320
7,000
190
6
160,000
$2,200,000
-$830,000
Reciprocating Compressors
Natural Gas Transmission and
Storage Stations
Centrifigal Compressors
Natural Gas Transmission and
Storage Stations
Reporting and Recordkeeping
TOTAL
10
960
All
220,000
1,100
2,700
0
390,000
31
74
0
170,000
1
2
0
2,700
25,000
61,000
0
8,900,000
$720,000
$220,000
$0
$350,000,000
$1,100,000
-$530,000
$6,300,000
$360,000,000
3-24
-------
Table 3-12 Incrementally Affected Units, Emissions Reductions and Costs, Selected Option 2, 2020
Pr<
Al
I
Rei
Source/Emissions Point
jjected No. of
Ffected Units
For Which
Federal
Regulations
juire Further
Action
Nationwide Emissions Reductions
Methane
(short VOC (short HAP (short
tons/year) tons/year) tons/year)
Methane
(metric tons
CO2e)
National Costs
Capital Costs
Annualized
Costs With
Addl.
Revenues
Well Completions and Recompletions
Hydraulically Fractured Development
Oil Wells
Hydraulically Fractured Wildcat and
Dilineation Oil Wells
12,000
990
110,000
9,100
89,000
7,600
11
1
2,400,000
210,000
$140,000,000
$3,700,000
$120,000,000
$3,700,000
Fugitive Emissions
Well Pads
Gathering and Boosting Stations
Tranmission Compressor Stations
94,000
480
45
150,000
13,000
3,500
42,000
3,800
97
1,600
140
3
3,500,000
310,000
79,000
$75,000,000
$1,100,000
$740,000
$180,000,000
$8,900,000
$880,000
Pneumatic Pumps
Well Pads
3,900
13,000
3,600
140
290,000
$21,000,000
$3,100,000
Pneumatic Controllers -
Natural Gas Transmission and
Storage Stations
160
3,500
96
3
79,000
$1,100,000
-$410,000
Reciprocating Compressors
Natural Gas Transmission and
Storage Stations
Centrifigal Compressors
Natural Gas Transmission and
Storage Stations
Reporting and Recordkeeping
TOTAL
5
480
0
110,000
560
1,300
0
300,000
15
37
0
150,000
0
1
0
1,900
13,000
30,000
0
6,900,000
$360,000
$110,000
$0
$250,000,000
$570,000
-$270,000
$6,300,000
$320,000,000
3-25
-------
Table 3-13 Incrementally Affected Units, Emissions Reductions and Costs, Selected Option 2, 2025
Pr.
Al
]
Rei
Source/Emissions Point
ajected No. of
ffected Units
For Which
Federal
Regulations
quire Further
Action
Nationwide Emissions Reductions
Methane
(short VOC (short HAP (short
tons/year) tons/year) tons/year)
Methane
(metric tons
CO2e)
National Costs
Capital Costs
Annualized
Costs With
Addl.
Revenues
Well Completions and Recompletions
Hydraulically Fractured Development
Oil Wells
Hydraulically Fractured Wildcat and
Dilineation Oil Wells
13,000
1,100
110,000
10,000
95,000
8,400
11
1
2,600,000
230,000
$150,000,000
$4,000,000
$130,000,000
$4,000,000
Fugitive Emissions
Well Pads
Gathering and Boosting Stations
Tranmission Compressor Stations
190,000
960
90
310,000
27,000
7,000
87,000
7,500
190
3,300
280
6
7,100,000
610,000
160,000
$150,000,000
$2,300,000
$1,500,000
$360,000,000
$18,000,000
$1,800,000
Pneumatic Pumps
Well Pads
7,900
26,000
7,200
270
590,000
$43,000,000
$6,100,000
Pneumatic Controllers -
Natural Gas Transmission and
Storage Stations
320
7,000
190
6
160,000
$2,200,000
-$830,000
Reciprocating Compressors
Natural Gas Transmission and
Storage Stations
Centrifigal Compressors
Natural Gas Transmission and
Storage Stations
Reporting and Recordkeeping
TOTAL
10
960
0
220,000
1,100
2,700
0
510,000
31
74
0
210,000
1
2
0
3,900
25,000
61,000
0
11,000,000
$720,000
$220,000
$0
$360,000,000
$1,100,000
-$530,000
$6,300,000
$530,000,000
3-26
-------
Table 3-14 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2020
Pr<
Al
I
Rei
Source/Emissions Point
jjected No. of
Ffected Units
For Which
Federal
Regulations
juire Further
Action
Nationwide Emissions Reductions
Methane
(short VOC (short HAP (short
tons/year) tons/year) tons/year)
Methane
(metric tons
CO2e)
National Costs
Capital Costs
Annualized
Costs With
Addl.
Revenues
Well Completions and Recompletions
Hydraulically Fractured Development
Oil Wells
Hydraulically Fractured Wildcat and
Dilineation Oil Wells
12,000
990
110,000
9,100
89,000
7,600
11
1
2,400,000
210,000
$140,000,000
$3,700,000
$120,000,000
$3,700,000
Fugitive Emissions
Well Pads
Gathering and Boosting Stations
Tranmission Compressor Stations
94,000
480
45
200,000
13,000
3,500
57,000
3,800
97
2,100
140
3
4,600,000
310,000
79,000
$83,000,000
$1,100,000
$740,000
$350,000,000
$8,900,000
$880,000
Pneumatic Pumps
Well Pads
3,900
13,000
3,600
140
290,000
$21,000,000
$3,100,000
Pneumatic Controllers -
Natural Gas Transmission and
Storage Stations
160
3,500
96
3
79,000
$1,100,000
-$410,000
Reciprocating Compressors
Natural Gas Transmission and
Storage Stations
Centrifigal Compressors
Natural Gas Transmission and
Storage Stations
Reporting and Recordkeeping
TOTAL
5
480
0
110,000
560
1,300
0
350,000
15
37
0
160,000
0
1
0
2,400
13,000
30,000
0
8,000,000
$360,000
$110,000
$0
$260,000,000
$570,000
-$270,000
$6,300,000
$490,000,000
3-27
-------
Table 3-15 Incrementally Affected Units, Emissions Reductions and Costs, Option 3, 2025
Pr.
Al
]
Rei
Source/Emissions Point
ajected No. of
ffected Units
For Which
Federal
Regulations
quire Further
Action
Nationwide Emissions Reductions
Methane
(short VOC (short HAP (short
tons/year) tons/year) tons/year)
Methane
(metric tons
CO2e)
National Costs
Capital Costs
Annualized
Costs With
Addl.
Revenues
Well Completions and Recompletions
Hydraulically Fractured Development
Oil Wells
Hydraulically Fractured Wildcat and
Dilineation Oil Wells
13,000
1,100
110,000
10,000
95,000
8,400
11
1
2,600,000
230,000
$150,000,000
$4,000,000
$130,000,000
$4,000,000
Fugitive Emissions
Well Pads
Gathering and Boosting Stations
Tranmission Compressor Stations
190,000
960
90
420,000
27,000
7,000
120,000
7,500
190
4,400
280
6
9,400,000
610,000
160,000
$170,000,000
$2,300,000
$1,500,000
$710,000,000
$18,000,000
$1,800,000
Pneumatic Pumps
Well Pads
7,900
26,000
7,200
270
590,000
$43,000,000
$6,100,000
Pneumatic Controllers -
Natural Gas Transmission and
Storage Stations
320
7,000
190
6
160,000
$2,200,000
-$830,000
Reciprocating Compressors
Natural Gas Transmission and
Storage Stations
Centrifigal Compressors
Natural Gas Transmission and
Storage Stations
Reporting and Recordkeeping
TOTAL
10
960
0
220,000
1,100
2,700
0
610,000
31
74
0
230,000
1
2
0
5,000
25,000
61,000
0
14,000,000
$720,000
$220,000
$0
$380,000,000
$1,100,000
-$530,000
$6,300,000
$880,000,000
3-28
-------
4 BENEFITS OF EMISSIONS REDUCTIONS
4.1 Introduction
The final NSPS is designed to prevent new emissions from the oil and gas sector. For the
NSPS, we predict that there will be climate and ozone benefits from methane reductions, ozone
and PMi.5 health benefits from VOC reductions, and HAP "co-benefits". These co-benefits would
occur because the control techniques to meet the standards simultaneously reduce methane,
VOC, and HAP emissions. The NSPS is anticipated to prevent 300,000 tons of methane, 150,000
tons of VOC, and 1,900 tons of HAP from new sources in 2020. In 2025, the NSPS is estimated
to prevent 510,000 tons of methane, 210,000 tons of VOC, and 3,900 tons of HAP. The CO2-
equivalent (COi Eq.) methane emission reductions are estimated to be 6.9 million metric tons in
2020 and 11 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 $360 million and $690 million using a 3 percent discount rate in 2020 and
2025, respectively.22 The specific control techniques for the 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 markets 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 (PM2.5), and HAP, we have determined that quantification of the VOC-related health
benefits cannot be accomplished for this rule in a defensible way. This is not to imply that these
benefits do not exist; rather, it is a reflection of the difficulties in modeling the direct and indirect
impacts of the reductions in emissions for this industrial sector with the data currently available.
With the data available, we are not able to provide 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 and
22
Table 4-3 presents the methane-related climate effects based on SC-CH4 at discount rates of 2.5, 3, and 5 percent.
4-1
-------
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 Rule
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 those emissions have on ambient PMi.s levels and the health effects associated with PMi.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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Category
Specific Effect
Reproductive and developmental effects (e.g.,
low birth weight, pre-term births, etc)
Cancer, mutagenicity, and genotoxicity effects
Effect Has
Been
Quantified
Effect Has
Been
Monetized
More
Information
PM ISA2-4
PM ISA2-4
Reduced incidence of
mortality from
exposure to ozone
Premature mortality based on short-term study
estimates (all ages)
Premature mortality based on long-term study
estimates (age 30-99)
Ozone ISA3
Ozone ISA3
Hospital admissions—respiratory causes (age >
65)
Hospital admissions—respiratory causes (age
Emergency department visits for asthma (all
ages)
Reduced incidence of
morbidity from
exposure to ozone
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
Ozone ISA3
Ozone ISA3
Ozone ISA3
Ozone ISA3
Ozone ISA3
Ozone ISA3
Ozone ISA2
Ozone ISA2
Ozone ISA2
Reduced incidence of
morbidity from
exposure to HAP
Effects associated with exposure to hazardous
air pollutants such as benzene
ATSDR, IRIS2-3
Improved Environment
Reduced visibility
impairment
Visibility in Class 1 areas
Visibility in residential areas
PM ISA3
PM ISA3
Reduced effects from
PM deposition
(organics)
Effects on Individual organisms and
ecosystems
PM ISA2
Visible foliar injury on vegetation
Reduced vegetation growth and reproduction
Yield and quality of commercial forest
products and crops
Reduced vegetation
and ecosystem effects
from exposure to
ozone
Damage to urban ornamental plants
Carbon sequestration in terrestrial ecosystems
Recreational demand associated with forest
aesthetics
Other non-use effects
Ecosystem functions (e.g., water cycling,
biogeochemical cycles, net primary
productivity, leaf-gas exchange, community
composition)
Ozone ISA3
Ozone ISA3
Ozone ISA3
Ozone ISA2
Ozone ISA3
Ozone ISA2
Ozone ISA2
Ozone ISA2
1 The global climate and related impacts of CO2 and CH4 emissions changes, such as sea level rise, are estimated within each
integrated assessment model as part of the calculation of the SC-COa and SC-CH4. 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.
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4.2 Emission Reductions from the Final 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, wellsites, 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 PlVb.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 future 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 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.
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Table 4-2 shows the direct emissions reductions anticipated for this rale, across the
regulatory options examined. 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. VOC emissions are precursors to secondary formation of
PM2.5 and ozone and reducing these emissions would reduce exposure to these secondary
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 across NSPS Regulatory Options in 2020 and
2025
Pollutant
Methane (short tons/year)
VOC (short tons/year)
HAP (short tons/year)
Methane (metric tons)
Methane (million metric tons COi Eq.)
Methane (short tons/year)
VOC (short tons/year)
HAP (short tons/year)
Methane (metric tons)
Methane (million metric tons COi Eq.)
Option 1
250,000
130,000
1,300
230,000
5.6
390,000
170,000
2,700
360,000
8.9
Option 2
(Final)
2020
300,000
150,000
1,900
280,000
6.9
2025
510,000
210,000
3,900
460,000
11
Option 3
350,000
160,00
2,400
320,000
8.0
610,000
230,000
5,000
550,000
14
4.3 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, which in
turn contributes to increased global warming and continuing climate change. Methane reacts in
the atmosphere to form ozone, which 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
global glaciers and ice, increasingly severe weather events, such as hurricanes of greater
intensity, and sea level rise, among other impacts.
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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.
The oil and gas category emits significant amounts of methane. The public Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2014 (to be published April 15, 2016)
estimates 2014 methane emissions from Petroleum and Natural Gas Systems (not including
petroleum refineries and petroleum transportation) to be 232 MMt COi Eq. In 2014, total
methane emissions from the oil and gas industry represented 32 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, 2016c).
Actions taken to comply with the NSPS are anticipated to significantly decrease methane
emissions from the oil and natural gas sector in the United States. The final standards are
expected to reduce methane emissions annually by about 6.9 million metric tons CO2 Eq. in 2020
and by about 12 million metric tons COi Eq. in 2025. It is important to note that the emission
reductions are based upon predicted activities in 2020 and 2025; however, the EPA did not
forecast sector-level emissions in 2020 and 2025 for this rulemaking. To give a sense of the
magnitude of the reductions, the methane reductions estimated for 2020 are equivalent to about
2.8 percent of the methane emissions for this sector reported in the U.S. GHG Inventory for 2014
(about 232 million metric tons CO2 Eq. are from petroleum and natural gas production and gas
processing, transmission, and storage). Expected reductions in 2025 are equivalent to around 4.7
percent of 2014 emissions. As it is expected that emissions from this sector would increase over
time, the estimates compared against the 2014 emissions would likely overestimate the percent
of reductions from total emissions in 2020 and 2025.
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We calculated the global social benefits of methane emissions reductions expected from
the NSPS using estimates of the social cost of methane (SC-CfU), 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 CCh (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 COi emissions changes in benefit cost
analysis for GHG-related rulemakings since 2008. The SC-COi is a metric that estimates the
monetary value of impacts associated with marginal changes in CO2 emissions in a given year.
Similar the SC-CH4 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.
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-COi estimates and recommended four global values for use in
regulatory analyses. The SC-COi 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
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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
One key methodological aspect discussed in the SC-COi TSDs is the global scope of the
estimates. The SC-COi estimates represent global measures because of the distinctive nature of
the climate change, which is highly unusual in at least three respects. First, emissions of most
GHGs contribute to damages around the world independent of the country in which they are
emitted. The SC-COi must therefore incorporate the full (global) damages caused by GHG
emissions to address the global nature of the problem. Second, the U.S. operates in a global and
highly interconnected economy, such that impacts on the other side of the world can affect our
economy. This means that the true costs of climate change to the U.S. are larger than the direct
impacts that simply occur within the U.S. Third, climate change represents a classic public goods
problem because each country's reductions benefit everyone else and no country can be excluded
from enjoying the benefits of other countries' reductions, even if it provides no reductions itself.
In this situation, the only way to achieve an economically efficient level of emissions reductions
is for countries to cooperate in providing mutually beneficial reductions beyond the level that
would be justified only by their own domestic benefits. In reference to the public good nature of
mitigation and its role in foreign relations, thirteen prominent academics noted that these "are
compelling reasons to focus on a global SCC" (Pizer et al., 2014). In addition, the IWG recently
noted that there is no bright line between domestic and global damages. Adverse impacts on
other countries can have spillover effects on the United States, particularly in the areas of
national security, international trade, public health and humanitarian concerns.27
The 2010 SC-CO2 TSD also noted a number of limitations to the SC-CO2 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
26 Both the 2010 SC-CO2 TSD and the current SC-CO2 TSD are available at:
27 See Response to Comments: Social Cost of Carbon For Regulatory Impact Analysis Under Executive Order
12866, July 2015, page 31, at
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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.28 The limited amount of research linking
climate impacts to economic damages makes the modeling exercise even more difficult. These
individual limitations do not all work in the same direction in terms of their influence on the SC-
CO2 estimates, though taken together they suggest that the SC-COi estimates are likely
conservative. In particular, the IPCC Fourth Assessment Report (2007), which was the most
current IPCC assessment available at the time of the IWG's 2009-2010 review, concluded that
"It is very likely that [SC-CCh estimates] underestimate the damage costs because they cannot
include many non-quantifiable impacts." Since then, the peer-reviewed literature has continued
to support this conclusion. For example, the IPCC Fifth Assessment report (2014) observed that
SC-CO2 estimates continue to omit various impacts, such as "the effects of the loss of
biodiversity among pollinators and wild crops on agriculture."29 Nonetheless, these estimates and
the discussion of their limitations represent the best available information about the social
benefits of CCh 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-CCh estimates from stakeholders through
a range of channels, including public comments on Agency rulemakings that use the SC-CCh in
supporting analyses and through regular interactions with stakeholders and research analysts
implementing the SC-CCh methodology used by the IWG. In addition, OMB sought public
28 Climate change impacts and social cost of greenhouse gases modeling is an area of active research. For example,
see: (1) Howard, Peter, "Omitted Damages: What's Missing from the Social Cost of Carbon." March 13, 2014,
http://costofcarbon.org/files/Omitted_Damages_Whats_Missing_From_the_Social_Cost_of_Carbon.pdf; and (2)
Electric Power Research Institute, "Understanding the Social Cost of carbon: A Technical Assessment," October
2014, www.epri.com.
29 Oppenheimer, M., M. Campos, R.Warren, J. Birkmann, G. Luber, B. O'Neill, and K. Takahashi, 2014: Emergent
risks and key vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global
and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, DJ. Dokken, KJ. Mach, M.D.
Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy,
S. MacCracken, P.R. Mastrandrea, and L.L.White (eds.)]. Cambridge University Press, Cambridge, United
Kingdom and New York, NY, USA, pp. 1039-1099.
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comment on the approach used to develop the SC-CCh estimates through a separate comment
period and published a response to those comments in 2015.30
After careful evaluation of the full range of comments submitted to OMB, 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 in July 2015 to obtain expert
independent advice from the National Academies of Sciences, Engineering and Medicine to
ensure that the SC-COi estimates continue to reflect the best available scientific and economic
information on climate change.31 The Academies then convened a committee, "Assessing
Approaches to Updating the Social Cost of Carbon," (Committee) that is reviewing the state of
the science on estimating the SC-CCh, and will provide expert, independent advice on the merits
of different technical approaches for modeling and highlight research priorities going forward.
While the Committee's review focuses on the SC-CO2 methodology, recommendations on how
to update many of the underlying modeling assumptions will also likely pertain to the SC-CH4
estimates. EPA will evaluate its approach based upon any feedback received from the
Academies' panel.
To date, the Committee has released an interim report, which recommended against doing
a near term update of the SC-COi estimates. For future revisions, the Committee recommended
the IWG move efforts towards a broader update of the climate system module consistent with the
most recent, best available science, and also offered recommendations for how to enhance the
discussion and presentation of uncertainty in the SC-COi estimates. Specifically, the Committee
recommended that "the IWG provide guidance in their technical support documents about how
[SC-COi] uncertainty should be represented and discussed in individual regulatory impact
analyses that use the [SC-CCh]" and that the technical support document for each update of the
estimates present a section discussing the uncertainty in the overall approach, in the models used,
and uncertainty that may not be included in the estimates.32 At the time of this writing, the IWG
30 See.
31 The Academies' review will be informed by public comments and focus on the technical merits and challenges of
potential approaches to improving the SC-COi estimates in future updates.See
.
32 National Academies of Sciences, Engineering, and Medicine. (2016). Assessment of Approaches to Updating the
Social Cost of Carbon: Phase 1 Report on a Near-Term Update. Committee on Assessing Approaches to
Updating the Social Cost of Carbon, Board on Environmental Change and Society. Washington, DC: The
National Academies Press, doi: 10.17226/21898. See Executive Summary, page 1, for quoted text.
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is reviewing the interim report and considering the recommendations. EPA looks forward to
working with the IWG to respond to the recommendations and will continue to follow IWG
guidance on SC-CO2.
The four SC-CCh estimates are: $13, $45, $67, and $130 per metric ton of COi emissions
in the year 2020 (2012 dollars).33 The first three values are based on the average SC-CO2 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
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 lower probability but higher -impact outcomes
from climate change, which are captured further out in the tail of the SC-CCh distribution, and
while less likely than those reflected by the average SC-CO2 estimates, would be much more
harmful to society and therefore, are relevant to policy makers. 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 analysis 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
33 The current version of the SC-COi TSD is available at:
. TheTSDs present
SC-CO2 in $2007. The estimates were adjusted to 2012$ using the GDP Implicit Price Deflator (1.0804). Also
available at: . The SC-COi values have been rounded to two
significant digits. Unrounded numbers from the 2013 SCC TSD were adjusted to 2012$ and used to calculate the
CO2 benefits.
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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).34
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 (Marten and Newbold, 2012; Marten et al. 2014; and Waldhoff et al al. 2014). Gas
comparison metrics, such as the GWP, are designed to measure the impact of non-COi GHG
emissions relative to COi 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
Atmospheric
Concentration
Rjdiiitivo
forcing
impact's
Environmental
and Socio-
tconomic
impacts
Monoti/rd
Source: Marten et al. 2014
Figure 4-1 Path from GHG Emissions to Monetized Damages
The GWP is not ideally suited for use in benefit-cost analyses to approximate the social
cost of non-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-COi 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 CO2 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-CCh estimates in general, and the SC-CCh
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
34 See also Reilly and Richards, 1993; Schmalensee, 1993; Fankhauser, 1994; Marten and Newbold, 2012.
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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 CO2, the temporal independence of
the GWP could lead the GWP approach to underestimate the SC-CH4 with a larger downward
bias under higher discount rates (Marten and Newbold, 2012).35
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-CH4 to overcome those challenges.
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)36. 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-COi estimates developed by the IWG, and most were likely
underestimates due to changes in the underlying science since their publication.
Therefore, the EPA concluded in those rulemaking analyses that the GWP approach
would serve as an interim method of analysis until directly modeled social cost estimates for
non-COi GHGs, consistent with the SC-CCh estimates developed by the IWG, were developed.
35 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.
36 The researchers cited U.S. EPA 2012d include: Fankhauser (1994); Kandlikar (1995); Hammitt et al. (1996); Tol
et al. (2003); Tol (2004); and Hope and Newberry (2006).
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The EPA presented GWP-weighted estimates in sensitivity analyses rather than the main benefit-
cost analyses.37
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-CO2 estimates.38 Specifically, the estimation approach Marten et al used
incorporated 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-CCh 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. Marten et al. also used the same rationale as the IWG to develop global
estimates of the SC-CH4, given that methane is a global pollutant.
In addition, the atmospheric lifetime and radiative efficacy of methane used by Marten et
al. is based on the estimates reported by the IPCC in their Fourth Assessment Report (AR4,
2007), including an adjustment in the radiative efficacy of methane to account for its role as a
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
37 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 .
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 .
38 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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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 climate feedbacks on the carbon cycle for both methane and CO2 (rather than just for CO2 as
was done in AR4).39'40
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.41 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
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.
39 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.
40 Note that this analysis 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).
41 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),
(1.0804) Accessed 3/3/15.
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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
.
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 rulemaking. Forecasted changes in methane emissions in a
given year, expected as a result of the regulatory action, are multiplied by the SC-CH4 estimate
for that year. To obtain a present value estimate, the monetized stream of future non-CO2
benefits are discounted back to the analysis year using the same discount rate used to estimate
the social cost of the non-CO2 GHG emission changes. In addition, the limitations for the SC-
COi estimates discussed above likewise apply to the SC-CH4 estimates, given the consistency in
the methodology.
In early 2015, the EPA 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 application.42 Three reviewers considered seven charge questions that covered
42 For a copy of the peer review responses, see Docket ID EPA-HQ-OAR-2010-0505-5016. Also available at
(see "SCCH4 EPA PEER REVIEW
FILES.PDF").
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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-COi
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-CCh methodology (e.g., those discussed earlier in this
section) and noted that because the SC-CCh and SC-CH4 methodologies are similar, the
limitations also apply to the resulting SC-CH4 estimates. Two of the reviewers concluded that
use of the SC-CH4 estimates developed by Marten et al and published in the peer-reviewed
literature is appropriate in RIAs, 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-COi
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.
The EPA also carefully considered the full range of public comments and associated
technical issues on the Marten et al. SC-CH4 estimates received through this rulemaking and
determined that it would continue to use the estimates in the final rulemaking analysis. Based on
the evaluation of the public comments on this rulemaking, the favorable peer review of the
Marten et al. application, and past comments urging the EPA to value non-CCh GHG impacts in
its rulemakings, the EPA concluded that the estimates represent the best scientific information on
the impacts of climate change available in a form appropriate for incorporating the damages from
incremental methane emissions changes into regulatory analysis. The Agency has valued the
methane benefits expected from this rulemaking using the Marten et al. (2014) SC-CH4 estimates
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and has included those benefits in the main benefits analysis. Please see the Response to
Comments document, section XIII-H-4, for EPA's detailed responses to the comments on
methane valuation.
The estimated methane benefits are presented in Table 4-4 below for years 2020 and
2025 across regulatory options. Applying this approach to the methane reductions estimated for
the final NSPS option (Option 2), the 2020 methane benefits vary by discount rate and range
from about $160 million to approximately $950 million; the mean SC-CH4 at the 3 percent
discount rate results in an estimate of about $360 million in 2020. The methane benefits increase
for Option 2 in 2025 and likewise vary by discount rate, ranging from about $320 million to
approximately $1.8 billion in that year; the mean SC-CH4 at the 3-percent discount rate results in
an estimate of about $690 million in 2025.
Table 4-4 Estimated Global Benefits of Methane Reductions* (in millions, 2012$)
Discount rate and statistic
Million metric tonnes of
methane reduced
Million metric tonnes of
CO2 Eq.
5% (average)
3% (average)
2.5% (average)
3%(95thpercentile)
Option
2020
0.23
5.6
$130
$290
$390
$780
1
2025
0.36
8.9
$250
$540
$690
$1,400
Option
2020
0.28
6.9
$160
$360
$480
$950
2 (final)
2025
0.46
11
$320
$690
$890
$1,800
Option
2020
0.32
8.0
$190
$420
$560
$1,100
3
2025
0.55
14
$390
$840
$1,100
$2,200
*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 rule's climate-related benefits are associated with methane
reductions, but some climate-related impacts are expected from the rule'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 time scales of hours to days, methane emissions
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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 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.
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-COi 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 proposal requested comment on the application
of the Sarofim et al. (2015) for this benefits analysis as an approach to estimating the ozone
related mortality benefits resulting from the methane reductions expected from this rulemaking.
Some commenters objected to the inclusion of these benefits because they argue that methane is
not a VOC, whereas one commenter agreed that there is a connection between methane
emissions, higher ozone levels, and therefore human mortality. While the EPA does consider the
methane impacts on ozone to be important, there remain unresolved questions regarding several
methodological choices involved in applying the Sarofim et al. (2015) approach in the context of
an EPA benefits analysis, and therefore the EPA is not including a quantitative analysis of this
effect in this rule at this time.
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4.4 VOC as a PM2.5 Precursor
This ralemaking would reduce emissions of VOC, which are a precursor to PlVb.5. Most
VOC emitted are oxidized to COi rather than to PM, but a portion of VOC emission contributes
to ambient PMi.5 levels as organic carbon aerosols (U.S. EPA, 2009a). Therefore, reducing these
emissions would reduce PlVb.5 formation, human exposure to PMi.5, and the incidence of PlVb.5-
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 |^g/m3.
Due to data limitations regarding potential locations of new and modified sources
affected by this ralemaking, we did not perform the air quality modeling needed to quantify
PM2.5 benefits associated with reducing VOC emissions for this rule. Due to the high degree of
variability in the responsiveness of PMi.5 formation to VOC emission reductions, we are unable
to estimate the effect that reducing VOC will have on ambient PlVb.5 levels without air quality
modeling. However, we provide the discussion below for context regarding findings from
previous modeling.
4.4.1 PM2.s Health Effects and Valuation
Reducing VOC emissions would reduce PMi.5 formation, human exposure, and the
incidence of PM2.5-related health effects. Reducing exposure to PMi.5 is associated with
significant human health benefits, including avoiding mortality and respiratory morbidity.
Researchers have associated PMi.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
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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
PMi.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 PMi.5 in the underlying
epidemiology studies.
Fann, Fulcher, and Hubbell (2009) examined how the monetized benefit-per-ton
estimates of reducing ambient PMi.5 varies by the location of the emission reduction, the type of
source emitting the precursor, and the specific precursor controlled. This study employed a
reduced form air quality model to estimate changes in ambient PM2.5 from reducing 12 different
combinations of precursor emissions and emission sources, including reducing directly emitted
carbonanecous particles, nitrogen oxides, sulfur oxides, ammonia, and VOCs for nine urban
areas and nationwide. For each precursor/source combination in each location, the study authors
then estimated the total monetized health benefits associated with the PMi.5 change and divided
these benefits by the corresponding emissions changes to generate benefit-per-ton estimates.The
estimates from this study can provide general context for the unquantified VOC benefits in this
rulemaking. Specifically, Fann, Fulcher, and Hubbell (2009) found that the monetized benefit-
per-ton of reducing VOC emissions ranged from $560 in Seattle, WA to $5,700 in San Joaquin,
CA, with a national average of $2,400. These estimates assume a 50 percent reduction in VOC,
from the Laden et al. (2006) mortality function (based on the Harvard Six Cities study, a large
cohort epidemiology study in the Eastern U.S., an analysis year of 2015, a 3 percent discount
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rate, and 2006$). Additional benefit-per-ton estimates are available from this dataset using
alternate assumptions regarding the relationship between PlVb.5 exposure and premature mortality
from empirical studies and those 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. 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 reflect the range of epidemiology studies and the range of the
urban areas is $300 to $7,500 per ton of VOC reduced (2012$).43 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.44 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 general 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.
43 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.
44 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 VOC in 9 Urban Areas and Nationwide based on Fann, Fulcher, and
Hubbell (2009) in (2012$)
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
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
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
* The estimates in this table provide general context regarding the potential magnitude of monetized benefits from reducing VOC emissions, but these urban
areas were not chosen based on the locations of VOC emissions from the oil and gas sector. Coupled with other uncertainties, these VOC benefit-per-ton
estimates are not appropriate to calculate monetized benefits of this rule. 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 theVOC benefit-per-ton estimates by approximately 13
percent. Assuming a 25 percent reduction in VOC emissions would decrease the VOC benefit-per-ton estimates by 13 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 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 counter to the
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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 wellsites, 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, 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, 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).45 After updating the currency year to 2012$, this implies a
45 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 $1,100 per ton of VOC reduced. Since EPA conducted the
analysis of industrial boilers, EPA published the Integrated Science Assessment for Ozone (U.S.
EPA, 2013), the Health Risk and Exposure Assessment for Ozone (U.S. EPA, 2014a), and the
RIA for the proposed Ozone NAAQS (U.S. EPA, 2014b). Therefore, the ozone mortality studies
applied in the boiler analysis, while current at that time, do not reflect the most updated literature
available. The selection of ozone 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). The IPCC AR5 estimated that the contribution to current warming
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levels of increased tropospheric ozone concentrations resulting from human methane, NOx, and
VOC emissions was 0.5 W/m2, or about 30 percent as large a warming influence as elevated COi
concentrations. 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 60 percent since 1990. However, despite this
decline, the 2011 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, 2015).46 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.47 The most recent NATA was conducted for
calendar year 2011 and was released in December 2015. 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 2011 NATA, the EPA estimates that less than 1 percent of census tracts
nationwide have increased cancer risks greater than 100 in a million. The average national cancer
risk is about 40 in a million. Nationwide, the key pollutants that contribute most to the overall
46 The 2011 NATA is available on the Internet at http://www.epa.gov/national-air-toxics-assessment/2011-national-
air-toxics-assessment.
47 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 2011 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. (2015) 2011 National-Scale Air
Toxics Assessment, .
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cancer risks are formaldehyde and benzene.4M9 Secondary formation (e.g., formaldehyde
forming from other emitted pollutants) was the largest contributor to cancer risks, while
stationary, mobile, biogenics, and background sources contribute lesser amounts to the remaining
cancer risk.
Noncancer health effects can result from chronic,50 subchronic,51 or acute52 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 2011
NATA, about 80 percent 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 2011 NATA indicate that acrolein is the primary driver for noncancer respiratory risk.
Figure 4-2 and Figure 4-3 depict the 2011 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 seventeen times acrolein
emissions on a national basis in the EPA's 2011 National Emissions Inventory (NEI). However,
the Integrated Risk Information System (IRIS) reference concentration (RfC) for acrolein is
considerably lower than that for acetaldehyde, this results in 2011 NATA estimates of
nationwide chronic respiratory noncancer risks from acrolein being over three times that of
48 Details on EPA's approach to characterization of cancer risks and uncertainties associated with the 2011 NATA
risk estimates can be found at .
49 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 .
50 Chronic exposure is defined in the glossary of the Integrated Risk Information System (IRIS) database
() 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).
51 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).
52 Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less.
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acetaldehyde.53 Thus, it is important to account for the toxicity and exposure, as well as the mass
of the targeted emissions.
AK
Figure 4-2 2011 NATA Model Estimated Census Tract Carcinogenic Risk from HAP
Exposure from All Outdoor Sources based on the 2011 National Emissions Inventory
53 Details on the derivation of IRIS values and available supporting documentation for individual chemicals (as well
as chemical values comparisons) can be found at .
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AK
PR and VI
Figure 4-3 2011 NATA Model Estimated Census Tract Noncancer (Respiratory) Risk
from HAP Exposure from All Outdoor Sources based on the 2011 National Emissions
Inventory
Due to methodology and data limitations, we were unable to estimate the benefits
associated with the hazardous air pollutants that would be reduced as a result of this rule. In a
few previous analyses of the benefits of reductions in HAP, EPA has quantified the benefits of
potential reductions in the incidences of cancer and noncancer risk (e.g., U.S. EPA, 1995). In
those analyses, EPA relied on unit risk factors (URF) and reference concentrations (RfC)
developed through risk assessment procedures. The URF is a quantitative estimate of the
carcinogenic potency of a pollutant, often expressed as the probability of contracting cancer from
a 70-year lifetime continuous exposure to a concentration of one |^g/m3 of a pollutant. These
URFs are designed to be conservative, and as such, are more likely to represent the high end of
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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
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, 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), 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, 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, 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 etal, 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. 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 3,400 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.54'55'56 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
54 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: .
55 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.
56 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.57'58 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.59-60
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
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
57 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.
58 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens
available at: .
59 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197.
60 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541-554.
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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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
sulfide has not undergone a complete evaluation and determination under U.S. 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
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
.
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 .
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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
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
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.
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 .
69 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is
available electronically at .
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number of effects in the nervous system including headaches, dizziness, fatigue, tremors, and
impaired motor coordination.70 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
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 (ffoS). Information regarding the health effects of those
compounds can be found in 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 4-6 shows the
estimated secondary emissions associated with combustion of emissions as a result of the rule. In
70 Agency for Toxic Substances and Disease Registry (ATSDR), 2007. The Toxicological Profile for xylene is
available electronically at .
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: .
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particular, combustion-related emissions result from the control of oil well completions (i.e.,
exploratory and delineation wells and development wells where RECs are infeasible and
pneumatic pumps and centrifugal compressors (because the requirement for these sources is to
route to control). More details on the estimation of secondary impacts for each emissions
category are presented in the TSD. Relative to the direct emission reductions anticipated from
this rule, the magnitude of these secondary air pollutant increases is small.
Table 4-6 Increases in Secondary Air Pollutant Emissions (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
890,000
minimal
100,000
3,900
0
1,000,000
C02
950,000
minimal
200,000
7,800
0
1,200,000
NOx
460
minimal
52
2
0
510
NOx
490
minimal
100
4
0
600
2020
PM
17
minimal
2
0
0
19
2025
PM
18
minimal
4
0
0
22
CO
2,500
minimal
290
11
0
2,800
CO
2,700
minimal
570
22
0
3,200
THC
940
minimal
110
4
0
1,100
THC
1,000
minimal
220
8
0
1,200
The secondary emission impacts for regulatory options are equal across the options. This
result holds because the only requirements varied across the options is the frequency of survey
and repair requirements. 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.
The COi impacts in Table 4-6 are the emissions that are expected to occur from natural
gas emissions that are captured by emissions controls and combusted. However, because of the
atmospheric chemistry associated with the natural gas emissions, most of the carbon in the VOCs
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and CH4 emissions expected in the absence of combustion-related emissions controls would have
eventually oxidized forming CCh in the atmosphere and led to approximately the same long-run
COi concentrations as with controls.73 Therefore, most of the impact of these CO2 contribution to
atmospheric concentrations from the flaring of CH4 and VOC versus future oxidization is not
additional to the impacts that otherwise would have occurred through the oxidation process.
However, there is a shift in the timing of the contribution of atmospheric COi concentration
under the policy case (in which case natural gas emissions that are captured by emissions
controls are combusted). In the case of VOCs, the oxidization time in the atmosphere is
relatively short, on the order of hours to months, so from a climate perspective the difference
between emitting the carbon immediately as CCh during combustion or as VOCs is expected to
be negligible. In the case of CH4, the oxidization time is on the order of a decade, so the timing
of the contribution to atmospheric COi concertation will differ between the baseline and policy
case. Because the growth rate of the SC-COi estimates are lower than their associated discount
rates, the estimated impact of COi produced in the future via oxidized methane from these fossil-
based emissions may be less than the estimated impact of CCh released immediately from
combusting emissions, which would imply a small disbenefit associated with the earlier release
of CO2 during combustion of the CH4 emissions.
In the proposal RIA, the EPA solicited comment on the appropriateness of monetizing the
impact of the earlier release of COi due to combusting methane and VOC emissions from oil and
gas sites and a new potential approach for approximating this value using the SC-COi. This
illustrative analysis provides a method for evaluating the estimated emissions outcomes
associated with destroying one metric ton of methane by combusting fossil-based emissions at
oil and gas sites (flaring) and releasing the CO2 emissions immediately versus releasing them in
the future via the methane oxidation process. This illustrative analysis as provided in the
proposal demonstrated that the potential disbenefits of flaring—i.e., an earlier contribution of
CO2 emissions to atmospheric concentrations -are minor compared to the benefits of flaring—
i.e., avoiding the release of and associated climate impacts from CH4 emissions. EPA did not
receive any comments regarding the appropriate methodology for conducting such an analysis,
73 The social cost of methane (SC-CH4) used previously in this chapter to monetize the benefits of the CH4
emissions reductions does not include the impact of the carbon in CH4 emissions after it oxidizes to COi.
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but did receive one comment letter that voiced general support for monetizing the secondary
impacts.
In consideration of this comment while recognizing the challenges and uncertainties
related to estimation of these secondary emissions impacts for this rulemaking, EPA has
continued to examine this issue in the context of this regulatory analysis—i.e, the combusting of
fossil-based CH4 at oil and gas sites—and explored ways to improve this illustrative analysis.
Specifically, EPA has modified the illustrative analysis by updating the oxidization process of
CH4 to be dynamic and consistent with the modeling that underlies the SC-CH4 estimates. Also
for this illustrative analysis, EPA assumed an average methane oxidation period of 12 years,
consistent with the perturbation lifetime-folding time used in IPCC AR4. The estimated
disbenefits associated with destroying one metric ton of methane through combustion of
emissions at oil and gas sites and releasing the CO2 emissions in 2020 instead of being released
in the future via the methane oxidation process are found to be small relative to the benefits of
flaring. Specifically, the disbenefit is estimated to be about $15 per metric ton CH4 (based on
average SC-COi at 3 percent) or roughly one percent of the SC-CH4 estimate per metric ton for
2020. The analogous estimate for 2025 is $18 per metric ton CH4 or about one percent of the SC-
CH4 estimates per metric ton for 2025.74>75
74 To calculate the COi related impacts associated the complete destruction of a ton of CH4 emissions through
flaring for this illustrative application, EPA took the difference between the SC-COi at the time of the flaring and
the discounted value of the CO2 impacts assuming a geometric decay of CH4 via the oxidation process with a 12
year e-folding time using the same discount rate as used to estimate the SC-COi. 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 COi. More specifically,
the impacts of shifting the COi impacts are calculated as
(44/16)
SC-C02, - l-e- SC-C02t
where * * is the year the CH4 is destroyed, r is the discount rate, and T is the time horizon of the analysis.
Ideally the time horizon, T, would be sufficiently long to capture the period in which nearly all of the CH4 is
expected to have been oxidized. In this analysis we use the 2100 as the time horizon, making the assumption that
the SC-COi remains constant after 2050, the last year for which the IWG provides estimates. This methodology
improves upon the one presented at proposal by updating the oxidization process of CH4 to be dynamic and
consistent with the modeling that underlies the SC-CH4 estimates.
75 The EPA also calculated these estimates using additional SC-COi values, specifically the average SC-COi at
discount rates of 5 and 2.5 percent and the 95th percentile at 3 percent. Applying these values, the estimates of
the disbenefit of releasing COi emissions in 2020 instead of in the future via methane oxidation ranges from $7
to $40 per metric ton CH4. The corresponding estimates for 2025 range from $9 to $51 per metric ton CH4.
4-40
-------
It is important to note that there are challenges and uncertainties related to this illustrative
method and estimates, which was developed to analyze secondary fossil-based emissions from
combustion. For example, these dollar per ton CH4 estimates cannot readily be applied to the
total CH4 emissions reductions presented in section 3 without additional information about the
downstream outcomes associated with the recovered gas that is not flared - e.g., whether some of
that captured gas going to be burned or leaked somewhere down the line.
The EPA will continue to study this issue and assess the complexities involved in estimating the
net emissions effects associated with secondary fossil-based emissions, including differences in
the timing of contributions to atmospheric COi concentrations. Given the uncertainties related to
estimating net secondary emissions effects and that the EPA has not yet received appropriate
input and review on some aspects of these calculations, the EPA is not including monetized
estimates of the impacts of small changes in the timing of atmospheric COi concentration
increases in the final benefits estimates in this RIA. The EPA will continue to follow the
scientific literature on this topic and update its methodologies as warranted.
Table 4-7 provides a summary of the direct and secondary emissions changes. Based on
the summary and analysis above, the net impact of both the direct and secondary impacts of this
final rule 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
Secondary
Emissions
Pollutant
Methane
VOC
HAP
CO2
NOx
PM
CO
THC
2020
-250,000
-130,000
-1,300
1,000,000
510
19
2,800
1,100
2025
-390,000
-170,000
-2,700
1,200,000
600
22
3,200
1,200
Option 2 (final)
2020
-300,000
-150,000
-1,900
1,000,000
510
19
2,800
1,100
2025
-510,000
-210,000
-3,900
1,200,000
600
22
3,200
1,200
Option 3
2020
-350,000
-160,000
-2,400
1,000,000
510
19
2,800
1,100
2025
-610,000
-230,000
-5,000
1,200,000
600
22
3,200
1,200
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5 COMPARISON OF BENEFITS AND COSTS
5.1 Comparison of Benefits and Costs across Regulatory Options
Tables 5-1 though Table 5-3 present the summary of the benefits, costs, and net benefits
for the NSPS across regulatory options. Table 5-4 provides a summary of the direct and
secondary emissions changes for each regulatory option.
Table 5-1 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
$290 million
$240 million
$54 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 130,000 tons of VOC
reduced
Health effects of HAP exposure from
1,300 tons of HAP reduced
Health effects of ozone exposure from
250,000 tons of methane
Visibility impairment
Vegetation effects
$540 million
$360 million
$180 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 170,000 tons of VOC
reduced
Health effects of HAP exposure from
2,700 tons of HAP reduced
Health effects of ozone exposure from
390,000 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 $130 million to $780 million in 2020 and $250 million to $1.4 billion in
2025 for Option 1, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission reductions are 5.6
million metric tons in 2020 and 8.9 million metric tons in 2025. Also, the specific control technologies for the
NSPS are anticipated to have minor secondary disbenefits. See Section 4.7 for details.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue
from additional natural gas recovery as a result of the NSPS. As can be seen in section 3.5.1 of the final RIA, the
national cost estimates in for this rule are not highly sensitive to the use of a 3 percent or 7 percent discount rate
in this RIA. As a result, the net benefits of the rule are not highly sensitive to choice of discount rate for
annualizing capital costs.
3 Estimates may not sum due to independent rounding.
5-1
-------
Table 5-2 Summary of the Monetized Benefits, Costs, and Net Benefits for Selected
Option 2 in 2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$360 million
$320 million
$35 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 150,000 tons of VOC
reduced
Health effects of HAP exposure from
1,900 tons of HAP reduced
Health effects of ozone exposure from
300,000 tons of methane
Visibility impairment
Vegetation effects
$690 million
$530 million
$170 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 210,000 tons of VOC
reduced
Health effects of HAP exposure from
3,900 tons of HAP reduced
Health effects of ozone exposure from
510,000 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, 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 $160 million to $950 million in 2020 and $320 million to $1.8 billion in 2025 for
Option 2, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission reductions are 6.9 million
metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control technologies for the NSPS are
anticipated to have minor secondary disbenefits. See Section 4.7 for details.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue
from additional natural gas recovery as a result of the NSPS. As can be seen in section 3.5.1 of the final RIA, the
national cost estimates in for this rule are not highly sensitive to the use of a 3 percent or 7 percent discount rate
in this RIA. As a result, the net benefits of the rule are not highly sensitive to choice of discount rate for
annualizing capital costs.
3 Estimates may not sum due to independent rounding.
5-2
-------
Table 5-3 Summary of the Monetized Benefits, Costs, and Net Benefits for Option 3 in
2020 and 2025 (2012$)
2020
2025
Total Monetized Benefits1
Total Costs2
Net Benefits3
Non-monetized Benefits
$420 million
$490 million
-$75 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 160,00 tons of VOC
reduced
Health effects of HAP exposure from
2,400 tons of HAP reduced
Health effects of ozone exposure from
350,000 tons of methane
Visibility impairment
Vegetation effects
$840 million
$880 million
-$38 million
Non-monetized climate benefits
Health effects of PM2.5 and ozone
exposure from 230,000 tons of VOC
reduced
Health effects of HAP exposure from
5,000 tons of HAP reduced
Health effects of ozone exposure from
610,000 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, 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 $190 million to $1.1 billion in 2020 and $390 million to $2.2 billion in 2025 for this
more stringent option, as shown in Section 4.3. The COi-equivalent (COi Eq.) methane emission reductions are 8
million metric tons in 2020 and 14 million metric tons in 2025. Also, the specific control technologies for the
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. As can be seen in section 3.5.1 of the final RIA, the
national cost estimates in for this rule are not highly sensitive to the use of a 3 percent or 7 percent discount rate
in this RIA. As a result, the net benefits of the rule are not highly sensitive to choice of discount rate for
annualizing capital costs.
3 Estimates may not sum due to independent rounding.
A break-even analysis answers the question: "What would the benefits need to be for the
benefits to exceed the costs?" While a break-even approach is not equivalent to a benefits
analysis or even a net benefits analysis, we feel the results are illustrative, particularly in the
context of previously modeled benefits. For Options 1 and 2 (final selected option), the
monetized climate benefits from methane emission reductions already exceed the costs, which
renders a break-even analysis for these options unnecessary. For Option 3, the monetized net
benefits are estimated to be -$73 million and -$37 million and the estimated VOC emission
reductions are 160,000 and 230,000 tons for 2020 and 2025, respectively. Thus, a break-even
analysis suggests that the VOC emissions would need to be valued at $460 per ton in 2020 and
$160 per ton in 2025 for the total monetized benefits of Option 3 to exceed costs, assuming that
5-3
-------
the health benefits from HAP emission reductions and the ozone health benefits from methane
emission reductions are zero. Previous assessments have shown that the PMi.5 health benefits
associated with reducing VOC emissions were valued at $300 to $7,500 per ton of VOC
emissions reduced in specific urban areas and ozone health benefits from reducing VOC
emissions were valued at $260 to $1,100 per ton of VOC emissions reduced. These break-even
estimates assume that all other pollutants have zero value. Of course, it is inappropriate to
assume that the value of reducing any of these pollutants is zero. Thus, the real break-even point
is actually lower than the estimates provided above because the other pollutants each have non-
zero benefits that should be considered. Furthermore, a single pollutant can have multiple effects
(e.g., VOCs contribute to both ozone and PMi.5 formation that each have health and welfare
effects) that would need to be summed in order to develop a comprehensive estimate of the
monetized benefits associated with reducing that pollutant.
Table 5-4 Summary of Emissions Changes across Options for the NSPS in 2020 and
2025 (short tons per year, unless otherwise noted)
Option 1
Reduction in
Direct
Emissions
Secondary
Emissions
Pollutant
Methane
VOC
HAP
C02
NOx
PM
CO
THC
2020
-250,000
-130,000
-1,300
1,000,000
510
19
2,800
1,100
2025
-390,000
-170,000
-2,700
1,200,000
600
22
3,200
1,200
Option
2020
-300,000
-150,000
-1,900
1,000,000
510
19
2,800
1,100
2 (final)
2025
-510,000
-210,000
-3,900
1,200,000
600
22
3,200
1,200
Option 3
2020
-350,000
-160,000
-2,400
1,000,000
510
19
2,800
1,100
2025
-610,000
-230,000
-5,000
1,200,000
600
22
3,200
1,200
5.2 Uncertainties and Limitations
Throughout the RIA, we considered a number of sources of uncertainty, both
quantitatively and qualitatively, regarding emissions reductions, benefits, and costs of the rule.
We summarize the key elements of our discussions of uncertainty here:
• Projection methods and assumptions: As discussed in Section 3.4.2, 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
5-4
-------
accumulates. The large majority of impacts of the rule (completion requirements at
hydraulically fractured oil well completions and fugitive emissions requirements at
wellsites) are based on projections and growth rates consistent with the drilling activity in
the 2015 Annual Energy Outlook. To the extent actual drilling activities diverge from the
Annual Energy Outlook projections, the projected regulatory impacts estimated in this
document will diverge.
Years of analysis: The years of analysis are 2020, to represent the near-term impacts of
the rule, and 2025, to represent impacts of the rule over a longer period, as discussed in
Section 3.4.2. While it is desirable to analyze impacts beyond 2025 in this RIA, the EPA
has chosen not to do this largely because of the limited information available on the
turnover rate of emissions sources and controls. Extending the analysis beyond 2025
would introduce substantial and increasing uncertainties in projected impacts of the
NSPS.
State regulations in baseline: In preparing the impacts analysis, the EPA reviewed state
regulations and permitting requirements, as discussed in Section 3.4.2. Applicable
facilities in these states with similar requirements to the final NSPS are not included in
the estimates of incrementally affected facilities presented in the RIA. This means that
any additional costs and benefits incurred by facilities in these states to comply with the
federal standards beyond the state requirements are not reflected in this RIA.
Wellhead natural gas prices used to estimate revenues from natural gas recovery:
The annualized compliance cost estimates presented in this RIA include revenue from
natural gas recovery resulting from emissions reductions. As a result, national
compliance costs depend the price of natural gas. The sensitivity of national compliance
costs to assumptions about wellhead natural gas prices are examined in Section 3.5.2.
Monetized methane-related climate benefits: The EPA considered the uncertainty
associated with the social cost of methane (SC-CH/0 estimates, which were used to
calculate the global social benefits of methane emissions reductions expected from the
NSPS. The modeling underlying the development of the SC-CH4 estimates, which is
consistent with the modeling assumptions underlying the interagency working group's
SC-CO2 estimates, addressed uncertainty in several ways. For example, the analysis
addressed uncertainty in following areas: differences in model structure through an
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ensemble of three integrated assessment models; sensitivity of the SC-CH4 estimates to
key exogenous projections by using five different socioeconomic and emissions
forecasts; and three discount rates to reflect some uncertainty about how interest rates
may change over time and the possibility that climate damages are positively correlated
with uncertain future economic activity. The application of four point estimates also
helps reflect uncertainty. Chapter 4 of this RIA provides a comprehensive discussion
about the methodology and application of the SC-CH4 as well as consideration of several
types of secondary emissions impacts, which may partially offset the direct benefits of
this rule.
Non-monetized benefits: Numerous categories of health, welfare, and climate benefits
are not quantified and monetized in this RIA. These unquantified benefits, including
benefits from reducing emissions of methane, VOCs and HAP, are described in detail in
Chapter 4.
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6 ECONOMIC IMPACT ANALYSIS AND DISTRIBUTIONAL ASSESSMENTS
6.1 Introduction
This section includes three sets of analyses for the final NSPS:
• Energy Markets Impacts
• Final Regulatory Flexibility Analysis
• Employment Impacts
6.2 Energy Markets Impacts Analysis
We use the National Energy Modeling System (NEMS) to estimate the impacts of the
final NSPS on U.S. energy markets. 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.
A brief conceptual discussion about our energy markets 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 a given
cost. For example, the analysis for the rule shows that performing reduced emissions
completions on hydraulically-fractured oil wells would account for about 36 percent of the
natural gas captured by emissions controls in 2020 and about 23 percent of captured natural gas
in 2025. The fugitive emissions program at well sites is expected to account for about 62 percent
of the natural gas captured by emissions controls in 2020 and about 75 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 are paid based upon this metered production.
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
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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.
6.2.1 Description of the Department of Energy National Energy Modeling System
NEMS is a model of the 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 significant expansion since. DOE uses the modeling system
extensively to produce issue reports, legislative analyses, and respond to Congressional inquiries.
The 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.
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 the website: http://www.eia.gov/forecasts/aeo/.
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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 module 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 2015.76
The RIA baseline is consistent with that of the Annual Energy Outlook 2015, which is used
extensively in Section 2 in the Industry Profile.
6.2.2 Inputs to National Energy Modeling System
To model potential impacts associated with the final 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 and
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
extracted resources exceeds expected costs, including costs associated with capital, exploration,
development, production, and taxes. Detailed technology and reservoir-level production
economics govern findings and success rates and costs.
The structure of the OGSM is amenable to analyzing potential impacts of the 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 rule.
76 Assumptions for the 2015 Annual Energy Outlook can be found at
.
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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.
6.2.2.1 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. Regulatory 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 regulatory 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.
In general, the cost of capital in the model will implicitly capture potential barriers to
obtaining additional capital financing for the industry on average. However, the model may not
fully capture heterogeneity in the cost of capital across the industry, and therefore, may not fully
capture distributional impacts across the industry as a result of firm specific characterisitics that
cause them to have varying access to additional capital. An additional caveat to this analysis is
that the modeling does not attempt to represent potential constraints on the supply of specific
capital equipment, which may or may not be binding in practice.
Table 6-1 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
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2025. We estimate those costs as a function of new wells anticipated 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.
We divide the estimated compliance costs for the given emissions point by the
appropriate number of expected new crude oil and natural gas 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.
Hydraulically fractured oil well 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. 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 6-1 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$)
Varies3
$2,285
$2,285
$25,050
$27,370
$42,093
$1,748
$2,077
$114,146
$25
$774
$6,200,000b
Per Well
Costs
Applied
in NEMS
(2012$)
$4,590
$905
$1,101
$284
$13
$25
$3
$4
$0
$0
$15
$154
Natural
Gas
Recovery
per Unit
(Mcf)
0
191°
73
1,629
1,673
5,899
1,122
1,130
0
144
0
0
Per Well
Natural
Gas
Recovery
Applied
in NEMS
(Mcf)
0
38
18
18
1
3
2
2
0
2
0
0
a Since compliance costs vary across hydraulically fractured oil well completions, this table uses the weighted
average costs by completion cost type.
b Reporting and recordkeeping costs are assumed to be equally allocated across all new wells.
c Natural gas recovery at oil well sites is the weighted average of the recovery expected from oil well sites and oil
well (associated gas) sites. See TSD for detailed description of these model well sites.
6.2.2.2 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
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implementing the environmental technology. Adding the averted methane emissions in this
manner has the effect of moving the natural gas supply curve to the right in an increment
consistent with the technically achievable emissions transferred into the production stream as a
result of the final NSPS. We enter the increased natural gas recovery into NEMS on a per-well
basis for new wells, following an estimation procedure similar to that of entering compliance
costs into NEMS on a per-well basis for new wells (Table 6-1).
6.2.3 Energy Markets Impacts
We estimate impacts to drilling activity, price and quantity changes in the production of
crude oil and natural gas, and changes in international trade of crude oil and natural gas. In each
of these estimates, we present estimates for the baseline years of 2020 and 2025 and predicted
results for 2020 and 2025 under the final rule. We also present impacts over the 2020 to 2025
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 offshore production is
not affected by the NSPS and the bulk of the rule's impacts are expected to be in the continental
U.S.
We first report estimates of impacts on crude oil and natural gas drilling activities and
production. Table 6-2 presents estimates of successful onshore natural gas and crude oil wells
drilled in the continental U.S.
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Table 6-2 Successful Oil and Gas Wells Drilled (Onshore, Lower 48 States)
Projection, 2020 Projection, 2025
2012
Successful Wells Drilled
Natural Gas 10,490
Crude Oil 28,496
Total 38,986
% Change in Successful
Natural Gas
Crude Oil
Total
Baseline
10,501
27,455
37,956
Wells Drilled
NSPS Baseline
10,481 12,200
27,463 29,244
37,944 41,444
from Baseline
0.19%
0.03%
0.03%
NSPS
12,145
29,231
41,376
-0.45%
-0.04%
-0.16%
Projection, 2020-25
Baseline NSPS
65,896 65,785
168,768 168,736
234,664 234,521
-0.17%
-0.02%
-0.06%
Results show that the final NSPS will have a relatively small impact on onshore well
drilling in the lower 48 states. Drilling remains essentially unchanged in 2020, with very slight
increases both oil and natural gas wells, relative to the baseline. Meanwhile, drilling of both
natural gas and crude oil wells decreases slightly in 2025, relative to the baseline. The small
increase in drilling in 2020 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 periods. Crude oil drilling over the 2020 to 2025
period decreases overall but by about 30 wells total, or about 0.02 percent, relative to the
baseline. Natural gas drilling, over the same period remains declines by about 110 wells total, or
about 0.17 percent, relative to the baseline.
Table 6-3 shows estimates of the changes in the domestic production of natural gas and
crude oil under the NSPS.
Table 6-3 Domestic Natural Gas and Crude Oil Production (Onshore, Lower 48 States)
Projection, 2020 Projection, 2025 Projection, 2020-25
2012
Domestic Production
Natural Gas (trillion cubic feet) 22. 158
Crude Oil (million bbls/day) 4.597
Baseline
26.544
8.031
NSPS Baseline NSPS Baseline
26.537 28.172 28.163 164.130
8.031 8.027 8.028 48.084
NSPS
164.086
48.086
% Change in Domestic Natural Gas and Crude Oil Production (Onshore, Lower 48 States)
Natural Gas
Crude Oil
-0.03% -0.03%
0.00% 0.01%
-0.03%
0.00%
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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. Crude oil production remains essentially unchanged
in 2020 and 2025 (with changes around or less than 0.01 percent in both years), relative to the
baseline. While slightly increasing over the time horizon, the overall change in crude oil
production is less than 0.01 percent, relative to the baseline. Natural gas production is estimated
to decrease slightly during the 2020-25 period, by around 0.03 percent, relative to the baseline.
Note this analysis estimates very little change in domestic natural gas production, despite
some environmental controls anticipated in response to the rule capture natural gas that would
otherwise be emitted (about 16 bcf in 2020 and 27 bcf in 2025). 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 6-4 presents estimates of national average wellhead natural gas and crude oil prices
for onshore production in the lower 48 states.
Table 6-4 Average Natural Gas and Crude Oil Wellhead Price (Onshore, Lower 48
States, 2012$)
2012
Projection
Baseline
Lower 48 Average Wellhead Price
Natural Gas (2012$ per Mcf) 2.566 4.428
Crude Oil (2012$ per barrel) 94.835 73.920
% Change in Lower 48 Average Wellhead Price from
Baseline
Natural Gas
Crude Oil
,2020
NSPS
4.441
73.918
0.29%
0.00%
Projection, 2025
Baseline
5.184
85.219
NSPS
5.190
85.218
0.12%
0.00%
Projection,
Baseline
4.880
79.530
2020-25
NSPS
4.890
79.527
0.20%
-0.01%
Wellhead crude oil prices for onshore lower 48 production are not estimated to change
meaningfully in 2020 or 2025, or over the 2020-25 period, relative to the baseline. The
production-weighted average price for wellhead crude oil over the 2020 to 2025 period is not
estimated to change more than 0.01 percent, relative to the baseline. Meanwhile, wellhead
natural gas prices for onshore lower 48 production are estimated to increase slightly in response
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to the rale in 2020 by about 0.29 percent and by about 0.12 percent in 2025, relative to the
baseline. The production-weighted average price for wellhead natural gas over the 2020 to 2025
period is estimated to increase by around 0.2 percent, relative to the baseline.
Table 6-5 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
1.519 -2.557 -2.554
8.459 5.513 5.513
0.12%
0.00%
Projection, 2025
Baseline NSPS
-3.502 -3.498
6.073 6.072
0.11%
-0.02%
Projection, 2020-25
Baseline NSPS
-18.959 -18.939
5.857 5.857
0.11%
0.00%
Meanwhile, as shown in Table 6-5, net imports of natural gas are estimated to increase
slightly in 2020 and 2025 relative to the baseline (by about 0.12 percent and 0.11 percent,
respectively) relative to the baseline. Net imports of natural gas are also expected to increase by
about 0.11 percent across the 2020 to 2025 period under the rule. Crude oil imports are not
estimated to change in 2020 and to decrease slightly in 2025 by about 0.02 percent relative to the
baseline. Over the 2020 to 2025 period, net imports of crude oil are not estimated to change in
response to the rale.
6.3 Final 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. 104121), provides that
whenever an agency publishes a final rale after a general notice of proposed rulemaking is made,
it must prepare and make available a final regulatory flexibility analysis (FRFA), unless it
certifies that the rule, if promulgated, will not have a significant economic impact on a
substantial number of small entities (5 U.S.C. §605[b]). Small entities include small businesses,
small organizations, and small governmental jurisdictions. A FRFA describes the economic
impact of the rale on small entities and any significant alternatives to the rule that would
accomplish the objectives of the rale while minimizing significant economic impacts on small
entities. Pursuant to section 604 of the RFA, the EPA prepared a final regulatory flexibility
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analysis (FRFA) that examines the impact of the final rule on small entities along with regulatory
alternatives that could minimize that impact.
Prior to publication of the proposed rule, the EPA prepared an initial regulatory flexibility
analysis (IRFA) and convened a Small Business Advocacy Review (SBAR) Panel consisting of
the Director of the Sector Policies & Programs Division of the EPA Office of Air Quality
Planning & Standards, the Administrator of the Office of Information and Regulatory Affairs
within the Office of Management and Budget, and the Chief Counsel for Advocacy of the Small
Business Administration. The IRFA and Final SBAR Panel Report can be found in the docket to
this rulemaking at EPA-HQ-OAR-2010-0505.
6.3.1 Reasons why the Action is Being Considered
The EPA is finalizing amendments to subpart OOOO due to reconsideration of certain
issues raised in petitions for reconsideration that were received by the Administrator, which
include implementation improvements. The EPA is also finalizing a new subpart, 40 CFR 60,
subpart OOOOa, which includes: standards for greenhouse gas (GHG) emissions (in the form of
limitations on methane) from certain facilities that are covered by current VOC standards in the
oil and natural gas source category, and standards for GHG and VOC emissions from facilities
across the source category that are currently unregulated, including hydraulically fractured oil
well completions; fugitive emissions from well sites and compressor stations; pneumatic pumps;
and centrifugal compressors, reciprocating compressors and pneumatic controllers in the
transmission and storage segment. The EPA is including requirements for methane emissions
in subpart OOOOa because methane is a 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.77
6.3.2 Significant Issues Raised
The EPA received comments on the proposed standards related to the potential impacts
on small entities and requests for comments that were included based on the SBAR Panel
77 "Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air
Act," 74 FR 66496 (Dec. 15, 2009) ("2009 Endangerment Finding").
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Recommendations. See sections VI and VIII of the preamble to the final rule and the RTC
Document in Docket ID EPA-HQ-OAR-2010-0505 for more detailed responses.
Low production wells: Several commenters supported the proposed exemption of low
production well sites from the fugitive monitoring requirements. Commenters noted that
marginal wells generate relatively low revenue and these wells are often drilled and operated by
small companies.
Response: While these commenters did provide support for the proposed low production
well exemption, other commenters indicated that low production well sites have the potential to
emit substantial amounts of fugitive emissions, and that a significant number of wells would be
excluded from fugitive emissions monitoring based on this exemption. We did not receive data
showing that low production well sites have lower emissions than non-low production well sites.
In fact, the data that were provided indicated that the potential emissions from these well sites
could be as significant as the emissions from non-low production well sites since the type of
equipment and the well pressures are more than likely the same. In discussions with
stakeholders, they indicated that well site fugitive emissions are not based on production, but
rather on the number of pieces of equipment and components. Therefore, we believe that the
emissions from low production and non-low production well sites are comparable and we did not
finalize the proposed exclusion of low production well sites from fugitive emissions monitoring.
REC costs: Commenters stated that small operators have higher well completion costs,
and typically conduct completions less frequently. Generally, small operators lack the purchasing
power to get the discounted prices service companies offer to larger operators. However,
commenters did not provide specific cost information.
Response: The BSER analysis is based on the averages of nationwide data. It is possible
for a small operator to have higher than the nationwide average completion costs, however, the
daily completion cost provided by the commenters is not significantly different than the EPA's
estimate. Therefore, we do not believe that the cost of RECs disfavor small businesses.
Phase-in period for RECs: Commenters stated that the EPA should create a compliance
phase-in period of at least 6 months for the REC requirements, to accommodate small operators.
Commenters stated that REC equipment is in short supply, and this will drive up REC costs.
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Commenters stated that small entities lack the purchasing power of larger operators, which
makes it difficult to obtain the needed equipment before the compliance period begins.
Response: We agree that complianc with the REC requirements I the final rule could be
burdensome for some in the near term due to the unavailability of REC equipment. As discussed
in section VI of the preamble, the final rule provides a phase-in approach that would allow a
quick build-up of the REC supplied in the near term.
Alternatives to OGI technology: Several commenters indicated that the EPA should allow
alternatives to OGI technology as the cost is excessive for small operators.
Response: In the final rule, the EPA is allowing Method 21 with a repair threshold of 500
ppm as an alternative to OGI. We believe this alternative will alleviate some of the burden on
small entities.
Basing monitoring frequency on the percentage of leaking components: Commenters
indicated that using a percentage of components, rather than a set number of components, to
determine the frequency of surveys is also unfair to small entities since a small site will have
fewer fugitive emission components than a larger site. Commenters stated that smaller entities
are much more likely to operate these smaller sites, and thus are more likely to have a higher
frequency survey requirements under the percentage-based system.
Response: The EPA agrees that imposing a performance based monitoring schedule
would require operators to develop a program that would require extensive administration to
ensure compliance. We believe that the potential for a performance-based approach to encourage
greater compliance is outweighed in this case by these additional burdens and the complexity it
would add. Therefore, the EPA is finalizing a fixed monitoring frequency instead of performance
based monitoring.
Timing of initial fugitive monitoring periods: Commenters stated that the requirement to
conduct surveys for affected facilities using OGI technology within 30 days of the well
completion or within 30 days of modification is overly restrictive. Additionally, commenters
stated that small operators may not be able to find vendors available to survey a small number of
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wells within the required timeframe. One commenter stated that contractors will be in high
demand and may give scheduling preference to larger clients versus small business entities.
Response: EPA considered these and other comments and concluded that the proposed
time of 30 days within a well completion or modification is not enough time to complete the
necessary preparations for the initial monitoring survey. In addition, other commenters pointed
out that first date of production should be the trigger, rather than the date of well completion.
Therefore, for the collection of fugitive emissions components at a new or modified well site, we
are finalizing that the initial monitoring survey must take place within [insert date 1 year after
publication of the final rule in the Federal Register] or within 60 days of the startup of
production, whichever is later. We believe this extended timeframe for compliance will alleviate
some of the burden on smaller operators.
Third party compliance: Commenters believe that requiring third party compliance audits
will be a significant burden on small entities. One commenter said that a third-party audit
requirement will dramatically increase the costs of the program and have a negative competitive
impact on smaller, less funded operators.
Response: While the EPA continues to believe that independent third party verification
can furnish more, and sometimes better, data about regulatory compliance, we have explored
alternatives to the independent third party verification. Specifically, the "qualified professional
engineer" model was assessed to focus on the element of engineering design. The final rule
requires a professional engineer certification of technical infeasibility of connecting a pneumatic
pump to an existing control device, and a professional engineer design of closed vent systems.
These certifications will ensure that the owner or operator has effectively assessed appropriate
factors before making a claim of infeasibility and that the closed vent system is properly
designed to verify that all emissions from the unit being controlled in fact reach the control
device and allow for proper control. We believe this simplified approach will reduce the burden
imposed on all affected facilities, including those owned by small businesses.
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6.3.3 Small Business Administration Comments
The Chief Counsel for Advocacy of the Small Business Administration (SBA) did not
file any comments in response to the proposed rule.
6.3.4 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.78 The EPA identified the
size of ultimate parent entities by using the SBA size threshold guidelines.79 The criteria for size
determination vary by the organization/operation category of the ultimate parent entity, as can be
seen in Table 6-6.
Table 6-6 SBA Size Standards by NAICS Code
-,.,„„ Size Standards Size Standards
JNA1CS
Codes NAICS Industry Description (in millions of dollars) (in no. of employees)
211111 Crude Petroleum and Natural Gas Extraction - 1,250
211112 Natural Gas Liquid Extraction - 750
213111 Drilling Oil and Gas Wells - 1,000
213112 Support Activities for Oil and Gas Operations $38.5
486110 Pipeline Transportation of Crude Oil - 1,500
486210 Pipeline Transportation of Natural Gas $27.5
Sources: U.S. Census Bureau, Statistics of U.S. Businesses, 2012. . 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
potentially affected new or modified sources at the firm level. Because of these limitations, we
based the analysis in this FRFA on impacts estimates for the final 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)
78 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.
79 U.S. Small Business Administration (SBA). 2016. Small Business Size Standards. Effective as of February 26,
2016. See: .
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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.80 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.81 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 FRFA does not incorporate potential impacts from other provisions of the final
NSPS, the completions and fugitive emissions provisions represent about 98 percent of the
estimated compliance costs of the final NSPS in 2020 and 2025 (Table 6-7). Not 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 rule in its entirety.
Table 6-7 Distribution of Estimated Compliance Costs Across Sources
Annualized Costs (With
2020 2020 (%)
Hydraulically-fractured and Re-fractured Oil Well
Completions and Recompletions
Fugitive Emissions at Well Sites
Other Sources
Total Annualized Costs of Proposed NSPS
$130,000,000
$190,000,000
$8,000,000
$320,000,000
39%
59%
2%
100%
Product Recovery, 2012$)
2025 2025 (%)
$130,000,000
$380,000,000
$11,000,000
$530,000,000
25%
73%
2%
100%
Note: sums may not total due to independent rounding.
To identify potentially affected entities under the NSPS, the EPA combined ownership
information from the Drillinglnfo dataset with information drawn from the Hoover's Inc. online
80 Drillinglnfo is a private company that provides information and analysis to the energy sector. More information is
available at: http://info.drillinginfo.com.
81 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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platform, which includes information about companies, such as NAICS codes, employee counts,
and sales information.82 Note that this analysis assumes that the firms performing potentially
affected activities are also the firms performing activities in the future under the 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 6-8 for a summary of results of this matching exercise.
Table 6-8 No. of Completions in 2012 by Preliminary Firm Size
Firm Size Performing
Well Completions
Small
Not Small
Unknown
Total
No. of Firms
951
150
1,118
2,219
Number of Completions,
Hydraulically Fractured
or Re-fractured Oil Wells All
2,998
10,674
676
14,348
2012
Completions
10,360
22,866
5,762
38,988
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 are slightly lower than
totals included in the impacts analysis base year estimates as some completions have no owner/operator recorded in
the dataset. Sums may not total due to independent rounding.
82 The Hoover's Inc. online platform includes company records that can contain NAICS codes, number of
employees, revenues, and assets. For more information, see: .
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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 6-9.
Table 6-9 No. of Completions in 2012 by Firm Size
Firm Size Performing
Well Completions
Small
Not Small
Total
No. of Firms
2,069
150
2,219
No. of Completions,
2012
Hydraulically Fractured
or Re-fractured Oil Wells All Completions
3,674
10,674
14,348
16,122
22,866
38,988
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 are slightly lower than
totals included in the impacts analysis base year estimates as some completions have no owner/operator recorded in
the dataset. Sums may not total due to independent rounding.
6.3.5 Projected Reporting, Recordkeeping and Other Compliance Requirements
The information to be collected for the 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 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
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action result in an 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 training 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
2,554 owners and operators that are subject to the rule is 98,438 labor hours, with an annual
average cost of $3,361,074. The annual public reporting and recordkeeping burden for this
collection of information is estimated to average 20 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).
6.3.5.1 Methodology for Estimating Compliance Cost 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
FRFA are based on the same growth rates used to project future activities as described in the
TSD and are consistent with other analyses in this RIA. These growth rates are consistent with
the drilling activity in the 2015 Annual Energy Outlook. These growth rates are applied to the
2012 base year estimates for each firm in the database.
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sources.
Table 6-10 presents future year estimates of incrementally affected new and modified
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Table 6-10 No. of Incrementally Affected Sources in 2020 and 2025 by Firm Size
No. of Incrementally Affected
2020
Firm Size
Performing
Well
Completions
Small
Not Small
Total
Hydraulically
Fractured or Re-
fractured Oil
Wells
3,500
10,000
14,000
Gas Well
Sites
5,600
11,000
17,000
Sources,
Oil Well
Sites
33,000
44,000
77,000
No. of Incrementally Affected
2025
Hydraulically
Fractured or Re-
fractured Oil
Wells
3,800
11,000
15,000
Gas Well
Sites
11,000
24,000
35,000
Sources,
Oil Well
Sites
68,000
86,000
160,000
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 FRFA 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 $4/Mcf in 2012 dollars, again consistent with other analyses in this RIA. For
hydraulically fractured and re-fractured oil well completions, we assumed each small entity is
required to perform RECs and combustion in the same proportions assumed in the TSD and RIA.
We also assumed the same proportion would be exploratory or delineation wells as the TSD and
RIA. Table 6-11 shows the distribution of compliance costs estimates across firm size and year.
Table 6-11 Distribution of Estimated Compliance Costs1 across Firm Size Classes
Firm Size
Small
Not Small
Total
No. of Firms
2,069
150
2,219
Annualized Compliance Costs (2012$)
2020
110,000,000
200,000,000
310,000,000
2025
190,000,000
320,000,000
510,000,000
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 6.1.3, 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 FRFA 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.
6.3.5.2 Compliance Cost Impact Estimate Results
This section presents results of the cost-to-sales ratio analysis for both the primary
scenario and the low oil price scenario. The percent of small entities with cost-to-sales ratios
exceeding 1 percent and 3 percent in 2020 and 2025 are greater under the low oil price scenario,
as would be expected due to lower estimated sales revenues from a lower oil price. Also, as
expected, the entities with cost-to-sales ratios greater than 1 percent and greater than 3 percent
increase from 2020 to 2025 in both the main case and the low oil price scenario as affected
sources accumulate under the NSPS.
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: . 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 $4.80/Mcf in
the reference case and $4.323/Mcf in the low oil price case. Rounding down to $4/Mcf likely under-estimates
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: . 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.
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Table 6-12 Compliance Costs-to-Sales1 Ratios across Firm Size Classes for Primary
Scenario and Low Oil Price Scenario2
No. of Small
Greater than
Greater than
No. of Small
Greater than
Greater than
Entities
1 percent
3 percent
Entities
1 percent
3 percent
2020 (Main
No. of Small
Entities
2,031
564
289
2025 (Main
No. of Small
Entities
2,031
824
419
Case)
% of Small
Entities
-
28%
14%
Case)
% of Small
Entities
-
41%
21%
2020 (Low
No. of Small
Entities
2,043
648
344
2025 (Low
No. of Small
Entities
2,043
924
502
Oil Price Case)
% of Small
Entities
-
32%
17%
Oil Price Case)
% of Small
Entities
-
45%
25%
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.
6.3.5.3 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 limitations here.
• Because of data limitations, the analysis presented in the FRFA 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 final NSPS, the omission of the estimated
costs 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
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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 ratio 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.
6.3.6 Regulatory Flexibility Alternatives
The EPA considered three major options for this final rule. The option EPA is finalizing
contains reduced emission completion (REC) and completion combustion requirements for a
subset of newly completed oil wells that are hydraulically fractured or refractured. This option
requires fugitive emissions survey and repair programs be performed semiannually (twice per
year) at the affected newly drilled or refractured oil and natural gas well sites, and quarterly at
new or modified gathering and boosting stations and new or modified transmission and storage
compressor stations. Additionally this option requires reductions from centrifugal compressors,
reciprocating compressors, pneumatic controllers, and pneumatic pumps throughout the oil and
natural gas source category.
The other options considered differ from the finalized option with respect to the
requirements for fugitive emissions. One option exempted low production well sites from the
well site fugitive requirements. This less stringent option was analyzed as an alternative to
reduce burden on small entities. However, it was rejected because we believe that low production
well sites have the same type of equipment and components as production well sites with
production greater than 15 boe per day. Since we did not receive additional data on equipment or
component counts for low production wells, we believe that a low production well model plant
would have the same equipment and component counts as a non-low production well site. This
would indicate that the emissions from low production well sites could be similar to that of non-
low production well sites. Additionally, we did not receive data showing that low production
well sites have lower methane or VOC emissions than well sites. In fact, the data that were
provided indicated that the potential emissions from these well sites could be as significant as the
emissions from non-low production well sites since the type of equipment and the well pressures
are more than likely the same. In discussions with industry stakeholders, they indicated that well
site fugitive emissions are not based on production, but rather on the number of pieces of
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equipment and components. Therefore, we believe that the emissions from low production and
non-low production well sites are comparable, and low production well sites were included in the
selected option.
Lastly, the more stringent option required quarterly monitoring for all sites under the
fugitive emissions program. This option lead to greater emission reductions, however it was not
selected because it increased costs, resulting in a net effect of lower net benefits compared to the
finalized option.
In addition, the EPA is preparing a Small Entity Compliance Guide to help small entities
comply with this rule. The guide will be available on the World Wide Web approximately 60
days after promulgation of the rule, at
https://www3.epa.gov/airquality/oilandgas/implement.html.
The EPA notes that the IRFA includes numerous recommendations made by the SBAR
Panel85. The EPA considered these recommendations during the development of the proposal and
final rule. The rationale for the EPA's acceptance or rejection of each recommendation can be
found in the relevant discussion of each emission source throughout the preamble to the
proposal, final rule, and RTC. Though all comments were seriously considered, the EPA is
unable to incorporate all suggestions without compromising the effectiveness of the final
regulation. Changes to the rule from proposal that may benefit small entities due to comments
received include allowing both OGI and Method 21 as acceptable monitoring technology,
replacing a performance based monitoring schedule with a fixed frequency, lengthening the time
of initial fugitive monitoring from within 30 days to the later of either [insert date 1 year after
publication of the final rule in the Federal Register] or with 60 days of the startup of
production, and simplified the third party verification of technical infeasibility requirements.
Though these are not monetized, we believe the flexibility and simplifications these changes
have added to the rule result in a reduced burden on small entities.
85 The final SBAR Panel report is found at .
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6.4 Employment Impact Analysis
In addition to addressing the costs and benefits of the final rule, the EPA has analyzed the
impacts of this rulemaking on employment, which are presented in this section.86 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 final 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."87 A discussion of
compliance costs, including reporting and recordkeeping requirements, is included in Section 3
of this RIA. This analysis uses detailed engineering information on labor requirements for each
of the control strategies identified in this final rule in order to estimate partial employment
impacts for affected entities in the oil and gas industry. These bottom-up, engineering-based
estimates represent only one portion of 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 rule.
6.4.1 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 a net impact on overall
employment because labor is being shifted from one sector to another. On the other hand, in
86 The employment analysis in this RIA is part of the 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).
87 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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periods of high unemployment, net 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
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
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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.
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. Berman and Bui (2001) developed an innovative
approach to examine how an increase in local air quality regulation that reduces nitrogen oxides
(NOx) 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.88 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).89
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
88 Berman and Bui include over 40 4-digit SIC industries in their sample.
89 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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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
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 net employment impacts
from this final 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 final 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.90 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 net 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
90 More detail on how emission reductions expected from compliance with this rule can be found in Section 3 of this
RIA.
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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.91 Once the EPA receives guidance from this panel it will carefully
consider this input and then decide if and how to proceed on economy-wide modeling of net
employment impacts of its regulations.
6.4.2 Labor Estimates Associated with Final Requirements
Section 2 of the RIA, in Table 2-17 and Table 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 2014.92 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 2014 peak of about 660,000. 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 2014,
average wages for the oil and natural gas industry increased. Table 2-18 shows real wages (in
2012 dollars) from 1990 to 2014 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 final 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
91 For further information see:
http://yosemite.epa.gOv/sab/sabproduct.nsf/0/07E67CF77B54734285257BB0004F87ED7OpenDocument
92 NAICS 211111, 21112, 213111, 213112, 486110, and 486210.
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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 a firm often has to reduce
production in order to reduce output of negative production externalities (i.e., emissions), many
of the emission controls required by the final NSPS will simultaneously increase production and
reduce negative externalities. That is, these controls jointly produce environmental
improvements and increase output in the regulated sector. Therefore, 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. However, these rules may require
unprofitable investments for some operators, and 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 limitations
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 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 employees involved or
whether new jobs are created for new employees.
The results of this employment analysis of the NSPS are presented in Table 6-13 through
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Table 6-16 for 2020 and 2025 for individual sources regulated under this rule. Table 6-17
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 rule, 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 final NSPS, reporting and
recordkeeping requirements were estimated for the entire rule rather than by anticipated control
requirements. The reporting and recordkeeping estimates are consistent with estimates the EPA
submitted as part of its Information Collection Request (ICR), the estimated costs which are
included in the cost estimates presented in Chapter 3.
Table 6-13 presents estimates of labor requirements for hydraulically fractured oil well
completions. The REC and completion combustion requirements are associated with certain new
and existing oil well completions. While individual well completions take place over a short
period of time (days to a few weeks), the overall industry completes new wells and re-completes
some existing wells every year. Because of the continuing nature of new and existing well
completions, annually, at the industry level, we report the REC-related labor requirements in
annual units.
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 6-13 Estimates of Labor Required to Comply with NSPS for Hydraulically
Fractured Oil Well Completions, 2020 and 2025
Per Unit Total
Projected No. One- Per Unit One- Total
„ . . „ ,„ . , of time Annual Time Annual
Emissions Source/Control T . •• T i. ri. ri. ri. r\
Incrementally Labor Labor Labor Labor One-
Affected Estimate Estimate Estimate Estimate time Annual
Units (2020) (hours) (hours) (hours) (hours) FTE FTE
2020
Hydraulically Fractured Oil Well Completions and
Recompletions
Completions where REC
and completion 7,500 0 93 0 700,000 0 340
combustion is required
Completions where
completion combustion is 5,600 090 53,000 0 25
required
Total 13,000 N/A N/A 0 760,000 0 360
2025
Hydraulically Fractured Oil Well Completions and
Recompletions
Completions where REC
and completion 8,000 0 93 0 750,000 0 360
combustion is required
Completions where
completion combustion is 6,000 090 57,000 0 27
required
Total 14,000 N/A N/A 0 800,000 0 390
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 6-14 presents estimates of labor requirements for fugitive emissions. Consistent
with the cost estimates for fugitive emissions presented in Section 5 of 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. 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 remain uncertain.
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Table 6-14 Estimates of Labor Required to Comply with NSPS for Fugitive Emissions,
2020 and 2025
Projected No.
of
Incrementally
Emissions
Emissions Source Control
Affected
Units (2020)
Per Unit
One-
time
Labor
Estimate
(hours)
Per Unit
Annual
Labor
Estimate
(hours)
Total
One-
Time
Labor
Estimate
(hours)
Total
Annual
Labor
Estimate
(hours)
One-
time
FTE
Annual
FTE
2020
Well Sites
Company-level Planning
Monitoring
Site-level and
Maintenance
Gathering and Boosting Stations
Company-level Planning
Monitoring
Site-level and
Maintenance
Transmission Compressor Stations
Company-level Planning
Monitoring
Site-level and
Maintenance
Storage Compressor Stations
Company-level Planning
Monitoring
Site-level and
Maintenance
Total
4,300
94,000
480
480
20
20
25
25
94,000
120
0.0
120
0.0
120
0.0
120
0.0
N/A
0.0
14
0.0
110
0.0
110
0.0
210
N/A
500,000
0
57,000
0
2,400
0
3,000
0
560,000
0
1,300,000
0
52,000
0
2,100
0
5,300
1,400,000
240
0
27
0
1
0
1
0
270
0
640
0
25
0
1
0
3
660
2025
Well Sites
Company-level Planning
Monitoring
Site-level and
Maintenance
Gathering and Boosting Stations
Company-level Planning
Monitoring
Site-level and
Maintenance
Transmission Compressor Stations
Company-level Planning
Monitoring
Site-level and
Maintenance
Storage Compressor Stations
Company-level Planning
Monitoring
Site-level and
Maintenance
Total
4,300
190,000
480
960
20
40
25
50
190,000
120
5.4
120
0.0
120
0.0
120
0.0
N/A
0.0
14
0.0
110
0.0
110
0.0
210
N/A
500,000
0
57,000
0
2,400
0
3,000
0
560,000
0
2,700,000
0
100,000
0
4,300
0
11,000
2,800,000
240
0
27
0
1
0
1
0
270
0
1,300
0
50
0
2
0
5
1,400
Note: Full-time equivalents (FTE) are estimated by first multiplying the projected number of affected units by theper
unit labor requirements and then multiplying by 2,080 (40 hours multiplied by 52 weeks). Totals may not sum due to
independent rounding.
6-34
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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 final NSPS accumulates.
Table 6-15 presents labor requirement estimates for monitoring and maintainence
requirements for reciprocating compressors and routing emissions to a control device for
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 6-15 Estimates of Labor Required to Comply with NSPS for Reciprocating and
Centrifugal Compressors, 2020 and 2025
Emissions Source
Emissions
Control
Projected
No. of
Incr.
Affected
Units
Per-unit
One-
time
Labor
Est.
(hrs)
Per-unit
Annual
Labor
Est.
(hrs)
Total
One-
Time
Labor
Estimate
(hrs)
Total
Annual
Labor
Estimate
(hrs)
One-
time
FTE
Annual
FTE
2020
Compressors
Reciprocating
Centrifugal
Total
Monitoring
and
Maintenance
Route to
Control
160
5
170
1
360
N/A
1
0
N/A
160
1,800
2,000
160
0
160
0
1
1
0
0
0
2025
Compressors
Reciprocating
Centrifugal
Total
Monitoring
and
Maintenance
Route to
Control
320
10
330
1
360
N/A
1
0
N/A
160
1,800
2,000
320
0
320
0
1
1
0
0
0
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 6-16 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,
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and maintenance, the required labor is less than that of the controllers that would be used absent
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 6-16 Estimates of Labor Required to Comply with NSPS for Pneumatic
Controllers and Pumps, 2020 and 2025
Emissions
Source
Emissions
Control
Projected
No. of Incr.
Affected
Units
Per-unit
One-
time
Labor
Est.
(hrs)
Per-unit
Annual
Labor
Est.
(hrs)
Total
One-
Time
Labor
Estimate
(hrs)
Total
Annual
Labor
Estimate
(hrs)
One-
time
FTE
Annual
FTE
2020
Pneumatic
Controllers
Pneumatic
Pumps
Emissions
Limit
Route to
Control
480
3,900
0
N/A
0
N/A
0
N/A
0
N/A
0
N/A
0
N/A
2025
Pneumatic
Controllers
Pneumatic
Pumps
Emissions
Limit
Route to
Control
960
7,900
0
N/A
0
N/A
0
N/A
0
N/A
0
N/A
0
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 6-17 presents the labor estimates across all emissions sources. Two main categories
contain the majority of the labor requirements for the final 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
final NSPS is estimated at 270 FTEs in 2020 and in 2025. The annual labor requirement to
comply with final NSPS is estimated at about 1,100 FTEs in 2020 and 1,800 FTEs in 2025. We
note that this type of FTE estimate cannot be used to identify the specific number of employees
involved or whether new jobs are created for new employees, versus displacing jobs from other
sectors of the economy.
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Table 6-17 Estimates of Labor Required to Comply with NSPS, 2020 and 2025
Emissions Source
Projected No.
of
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
13,000
94,000
480
3,900
160
5
All
110,000
0
560,000
0
N/A
160
1,800
0
570,000
760,000
1,400,000
0
N/A
160
0
180,000
2,300,000
0
270
0
N/A
0
1
0
270
360
660
0
N/A
0
0
88
1,100
2025
Hydraulically Fractured and
Re-fractured Oil Well
Completions
Fugitive Emissions
Pneumatic Controllers
Pneumatic Pumps
Reciprocating Compressors
Centrifugal Compressors
Reporting and
Recordkeeping Requirements
Total
14,000
190,000
960
7,900
320
10
All
220,000
0
560,000
0
N/A
160
1,800
0
570,000
800,000
2,800,000
0
N/A
320
0
180,000
3,800,000
0
270
0
N/A
0
1
0
270
390
1,400
0
N/A
0
0
88
1,800
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.
6.5 References
Berman, E. and L. T. M. Bui. 2001. "Environmental Regulation and Labor Demand: Evidence
from the South Coast Air Basin." Journal of Public Economics 79(2): 265-295, docket nr.
EPA-HQ-OAR-2011-0135 at
Ferris, A., RJ. Shadbegian, and A. Wolverton. 2014. "The Effect of Environmental Regulation
on Power Sector Employment: Phase I of the Title IV SCh Trading Program." Journal of
the Association of Environmental and Resource Economists 5:173-193.
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Gray, W.B., RJ. Shadbegian, C. Wang, and M. Meral. 2014. "Do EPA Regulations Affect Labor
Demand? Evidence from the Pulp and Paper Industry." Journal of Environmental
Economics and Management: 68, 188-202.
Greenstone, M. 2002. "The Impacts of Environmental Regulations on Industrial Activity:
Evidence from the 1970 and 1977 Clean Air Act Amendments and the Census of
Manufactures." Journal of Political Economy 110(6): 1175-1219.
List, J. A., D. L. Millimet, P. G. Fredriksson, and W. W. McHone. 2003. "Effects of
Environmental Regulations on Manufacturing Plant Births: Evidence from a Propensity
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U.S. Bureau of Labor Statistics.
U.S. Census Bureau (Census).
U.S. Energy Information Administration (U.S. EIA). 2014. Oil and Gas Supply Module of the
National Energy Modeling System: Model Documentation 2014. July 2014.
Accessed May 10,2015.
U.S. Energy Information Administration (U.S. EIA). 2014. Model Documentation Report:
Natural Gas Transmission and Distribution Module of the National Energy Modeling.
June 2014.
Accessed May 10,2015.
U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis: Final
New Source Performance Standards and Amendments to the National Emissions
Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry.
Accessed December 19, 2014.U.S. Small Business Administration (U.S. SBA), Office of
Advocacy. 2010. A Guide for Government Agencies, How to Comply with the Regulatory
Flexibility Act, Implementing the President's Small Business Agenda and Executive
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Walker, R. 2011. "Environmental Regulation and Labor Reallocation." American Economic
Review: 101(3):442-447.
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United States Office of Air Quality Planning and Standards Publication No.
Environmental Protection Health and Environmental Impacts Division EPA-452/R-16-002
Agency Research Triangle Park, NC May 2016
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