Methane and Other Air Pollution Issues in
Natural Gas Systems
Updated September 17, 2020
Congressional Research Service
https://crsreports.congress.gov
R42986

Methane and Other Air Pollution Issues in Natural Gas Systems

Summary
Natural Gas Systems and Air Pollution
Congressional interest in U.S. energy policy has often focused on ways through which the United
States could secure more economical, reliable, and cleaner fossil fuel resources both domestical y
and international y. Recent expansion in natural gas production, primarily as a result of new or
improved technologies (e.g., hydraulic fracturing, directional dril ing) used on unconventional
resources (e.g., shale, tight sands, and coalbed methane) has made natural gas an increasingly
significant component in the U.S. energy supply. This expansion, however, has prompted
questions about the potential impacts of natural gas systems on human health and the
environment, including impacts on air quality.
The natural gas supply chain contributes to air pollution in several ways, including (1) the
leaking, venting, and combustion of natural gas in the course of production operations; and (2)
the combustion of other fossil fuel resources or other emissions during associated operations.
Emission sources include pad, road, and pipeline construction; wel dril ing, completion, and
flowback activities; and gas processing and transmission equipment such as controllers,
compressors, dehydrators, pipes, and storage vessels. Pollutants include, most prominently,
methane (i.e., the principal component of natural gas) and volatile organic compounds (VOCs)—
of which the natural gas industry is one of the highest-emitting industrial sectors in the United
States—as wel as nitrogen oxides, sulfur dioxide (SO2), and various forms of hazardous air
pollutants (HAPs).
Federal Air Standards for the Sector
Under the Obama Administration, the U.S. Environmental Protection Agency (EPA) promulgated
air standards for several source categories in the crude oil and natural gas sector on August 16,
2012. These standards revise previously existing rules and promulgate new ones to regulate
emissions of VOCs, SO2, and HAPs from many production and processing activities that had
never before been covered by federal standards (including, most notably, VOC controls on new
hydraulical y fractured natural gas wel s). In an extension of these regulations, and in conjunction
with the Obama Administration’s Climate Action Plan, EPA promulgated additional rules on June
3, 2016, “to set standards for methane and VOC emissions from new and modified oil and gas
production sources, and natural gas processing and transmission sources” not covered by the 2012
rule. Further, the U.S. Department of the Interior, Bureau of Land Management (BLM),
promulgated a “Waste Prevention, Production Subject to Royalties, and Resource Conservation”
rule on November 18, 2016, to target natural gas emissions on federal and Indian lands as a
potential waste of public resources and loss of royalty revenue.
In a direct response to the Obama-era standards, and in line with his campaign promises,
President Trump signed Executive Order 13783 on March 28, 2017. The order—entitled
“Promoting Energy Independence and Economic Growth”—requires agencies to review existing
regulations and “appropriately suspend, revise, or rescind those that unduly burden” domestic
energy production and use. Section 7 of the order specifical y directs the EPA Administrator and
the Secretary of the Interior to review several regulations related to domestic oil and gas
development, including EPA’s 2016 methane standards and BLM’s 2016 waste prevention rule.
Both agencies promulgated rulemakings to revise or rescind requirements of the rules. BLM
finalized its revisions on September 28, 2018. EPA finalized its revisions on September 14, 2020,
and September 15, 2020.
Congressional Research Service

Methane and Other Air Pollution Issues in Natural Gas Systems

Scope and Purpose of This Report
This report provides information on the natural gas industry and the types and sources of air
pollutants in the sector. It examines the role of the federal government in regulating these
emissions, including the provisions in the Clean Air Act and other statutes, and EPA’s and other
agencies’ regulatory activities. It concludes with a brief discussion of a number of issues under
debate, including
 defining the roles of industry and local, state, and federal governments;
 establishing comprehensive emissions data;
 determining the proper control of pollutants and sources;
 understanding the human health and environmental impacts of emissions; and
 estimating the costs of pollution abatement.

Congressional Research Service

Methane and Other Air Pollution Issues in Natural Gas Systems

Background
Congressional interest in U.S. energy policy has often focused on ways through which the United
States could secure more economical, reliable, and cleaner fossil fuel resources both domestical y
and international y. Recent expansion in natural gas production, primarily as a result of new or
improved technologies (e.g., hydraulic fracturing)1 used on unconventional resources (e.g., shale,
tight sands, and coalbed methane),2 has made natural gas an increasingly significant component
in the U.S. energy supply. While the practice of hydraulic fracturing is not new, relatively recent
innovations have incorporated processes such as directional dril ing, high-volume slick-water
injection, and multistage fractures to get to previously unrecoverable resources. As a result, the
United States has again become the largest producer of natural gas in the world.3 The U.S. Energy
Information Administration (EIA) projects natural gas to account for nearly 40% of total U.S.
energy resource production by 2050, with shale gas and tight oil plays projected to grow.4 In
addition, some analysts believe that by significantly expanding the domestic gas supply, the
exploitation of new unconventional resources has the potential to reshape energy policy at
national and international levels—altering geopolitics and energy security, recasting the
economics of energy technology investment decisions, and shifting trends in greenhouse gas
(GHG) emissions.5
Many in both the public and private sectors have advocated for the increased production and use
of natural gas because the resource is domestical y available, economical y recoverable, and
considered a potential “bridge” fuel to a less polluting and lower GHG-intensive economy.
Natural gas is cleaner burning than other fossil fuels, emitting, on average, about half as much
carbon dioxide (CO2) as coal and one-quarter less than oil when consumed in a typical electric
utility plant.6 Further, natural gas combustion emits no mercury—a persistent, bioaccumulative
neurotoxin—virtual y no particulate matter or sulfur dioxide (SO2), and less nitrogen oxides, per
unit of combustion, than either coal or oil. For these reasons, pollution control measures in natural

1 Hydraulic fracturing (hydrofracking, fracking, or fracing) is commonly defined as an oil or gas well completion
process that directs pressurized fluids typically containing any combination of water, proppant, and any added
chemicals to penetrate tight rock formations, such as shale or coal formations, in order to stimulate the oil or gas
residing in the formation and that subsequently requires high-rate, extended flowback to expel fracture fluids and
solids. T he National Petroleum Council estimates that hydraulic fracturing will account for nearly 70% of natural gas
development within the next decade. See National Petroleum Council, “ Prudent Development: Realizing the Potential
of North America’s Abundant Natural Gas and Oil Resources,” Sept ember 15, 2011, http://www.npc.org/NARD-
ExecSummVol.pdf.
2 T hese unconventional resources are commonly defined as follows: T ight sands gas is natural gas trapped in low
permeability and nonporous sandstones. Shale gas is natural gas trapped in shale deposits, a very fine-grained
sedimentary rock that is easily breakable into thin, parallel layers. Coalbed methane is natural gas trapped in coal
seams. T hese resources are referred to as “ unconventional” because, in the broadest sense, they are more difficult
and/or less economical to extract than “conventional” natural gas, usually because the t echnology to reach them has not
been developed fully or has been too expensive. For a more detailed discussion of these definitions, see the Natural Gas
Supply Association’s website, http://naturalgas.org/overview/resources/.
3 T he United States surpassed Russia as the world’s leading producer of dry natural gas beginning in 2009. See U.S.
Energy Information Administration (EIA), “ International Overview,” https://www.eia.gov/beta/international/.
4 EIA, Annual Energy Outlook, 2019, https://www.eia.gov/outlooks/aeo/. Based on EIA reference case scenario.
5 For more discussion on natural gas resources, see CRS Report R43636, U.S. Shale Gas Development: Production,
Infrastructure, and Market Issues, by Michael Ratner.
6 T hese values are averages based on CO2 emitted per unit of energy generated. See EIA, Emissions of Greenhouse
Gases in the United States 1997, T able B1, p. 106. Other pollutants derived from U.S. Environmental Protection
Agency, Com pilation of Air Pollutant Em ission Factors, Vol. 1, Stationary Point and Area Sources, 1998,
https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emission-factors.
Congressional Research Service

1

Methane and Other Air Pollution Issues in Natural Gas Systems

gas systems have traditional y received less attention relative to those in other hydrocarbon
industries. However, the recent increase in natural gas production, specifical y from
unconventional resources, has raised a new set of questions regarding environmental impacts.
These questions centered initial y on water quality issues, including the potential contamination
of groundwater and surface water from hydraulic fracturing and related production activities.
They have since incorporated other issues, such as water management practices (both
consumption and discharge), land use changes, induced seismicity, and air pollution. These
questions about hydraulic fracturing in unconventional reservoirs have led, in part, to the rise of
various grassroots movements, some political opposition, and cal s for additional regulatory
actions, moratoria, and/or bans on the practice at the local, state, and federal levels.
Currently, the development of natural gas in the United States is regulated under a complex set of
local, state, and federal laws that addresses many aspects of exploration, production, and
distribution. State and local authorities are responsible for virtual y al of the day-to-day
regulation and oversight of natural gas systems. The organization of this oversight within each
gas-producing jurisdiction varies considerably. In general, each state has one or more regulatory
agencies that may permit wel s—including their design, location, spacing, operation, and
abandonment—and may regulate for environmental compliance. With respect to pollution
controls, state laws may address many aspects of water management and disposal, air emissions,
underground injection, wildlife impacts, surface disturbance, and worker health and safety.
Furthermore, several federal statutes address pollution control measures in natural gas systems,
and, where applicable, these controls are largely implemented by state and local authorities.7 For
example, the Clean Water Act regulates surface discharges of water associated with natural gas
dril ing and production as wel as contaminated storm water runoff from production sites. The
Safe Drinking Water Act regulates the underground injection of wastewater from crude oil and
natural gas production and the underground injection of fluids used in hydraulic fracturing if the
fluids contain diesel fuel. The Clean Air Act (CAA) limits emissions from associated engines and
gas processing equipment as wel as some natural gas extraction, production, and processing
activities.
Natural Gas Systems and Air Pollution
The Industry
Natural gas is a nonrenewable fossil fuel that is used both as an energy source (for heating,
transportation, and electricity generation) and as a chemical feedstock (for such varied products
as plastic, fertilizer, antifreeze, and fabrics). The natural gas that the nation uses—to heat homes
and to fuel electric utilities—is the product of a long process beginning with the exploration and
extraction of the resource and leading to its treatment in processing facilities, transportation to
distributors, and eventual delivery through a long network of pipelines to consumers. Raw natural
gas is commonly recovered from geologic formations in the ground through dril ing and
extraction activities by the oil and gas industry.8 This industry includes operations in the
production of crude oil and natural gas as wel as the processing, transmission, and distribution of

7 For more discussion, see CRS Report R43148, An Overview of Unconventional Oil and Natural Gas: Resources and
Federal Actions, by Michael Ratner and Mary T iemann.
8 Natural gas can also be recovered as a byproduct from various other sources including mining, industrial, or
agricultural processes. T hese secondary sources are not discussed in this report.
Congressional Research Service

2

Methane and Other Air Pollution Issues in Natural Gas Systems

natural gas. For both operational and regulatory reasons, the industry is commonly separated into
four major sectors: (1) crude oil and natural gas production, (2) natural gas processing,9 (3)
natural gas transmission and storage, and (4) natural gas distribution. This report uses these basic
categories to track the various activities in natural gas systems, including the operations,
emissions, and regulations discussed below. While the focus of this report is on the production
sector, it also highlights air quality issues in other sectors, where appropriate.
The Resource
Raw natural gas is primarily a mixture of low molecular-weight hydrocarbon compounds that are
gaseous in form at normal conditions. While the principal component of natural gas is methane
(CH4), it may contain smal er amounts of other hydrocarbons, such as ethane, propane, and
butane, as wel as heavier hydrocarbons. These nonmethane hydrocarbons include types of VOCs,
classified as ground-level ozone (i.e., smog) precursors, as wel as, in some cases, hazardous (i.e.,
toxic) air pollutants (HAPs). Nonhydrocarbon gases—such as CO2, helium, hydrogen sulfide
(H2S), nitrogen, and water vapor—may also be present in any proportion to the total hydrocarbon
content. The chemical composition of raw natural gas varies greatly across resource reservoirs,
and the gas may or may not be “associated” with crude oil resources. When natural gas is found
to be primarily methane, it is referred to as “dry” or “pipeline quality” gas. When natural gas is
found bearing higher percentages of heavier hydrocarbons, nonhydrocarbon gases, and/or water
vapor, it is commonly referred to as “wet,” “rich,” or “hot” gas. Similarly, quantities of VOCs,
HAPs, and H2S can vary significantly depending upon the resource reservoir. VOC and HAP
compositions typical y account for only a smal percentage of natural gas mixtures; however, this
ratio increases the “wetter” the gas. Natural gas mixtures with a higher percentage of H2S are
general y referred to as “sour” or “acid” gas. These varying characteristics may cause both
industry operations and regulatory oversight to differ across resource reservoirs.
Types of Emissions
Natural gas systems release air emissions in several different ways. This report categorizes these
emissions into three types: fugitive, combusted, and associated.
1. Fugitive refers to the natural gas vapors that are released to the atmosphere
during industry operations. Fugitive emissions can be either intentional (i.e.,
vented) or unintentional (i.e., leaked). Intentional emissions are releases that are
designed specifical y into the system: for example, emissions from vents or blow-
downs used to guard against overpressuring or gas-driven equipment used to
regulate pressure or store or transport the resource. Conversely, unintentional
emissions are releases that result from uncontrolled leaks in the system: for
example, emissions from routine wear, tear, and corrosion; improper instal ation
or maintenance of equipment; or the overpressure of gases or liquids in the
system. Fugitive emissions can contain several different kinds of air pollutants,
including methane, VOCs, and HAPs.
2. Combusted refers to the byproducts that are formed from the burning of natural
gas during industry operations. Combusted emissions are commonly released
through either the flaring of natural gas for safety and health precautions10 or the

9 Petroleum refining (i.e., crude oil processing after the production phase) is classified as another industry sector for
regulatory purposes and is not discussed in this report.
10 Flaring is a means to eliminate natural gas that may be impracticable to use, capture, or transport. As with venting,
Congressional Research Service

3

Methane and Other Air Pollution Issues in Natural Gas Systems

combustion of natural gas for process heat, power, and electricity in the system
(e.g., for compressors and other machinery). The chemical process of combusting
natural gas releases several different kinds of air pollutants, including CO2,
carbon monoxide (CO), nitrogen oxides (NOx), and trace amounts of sulfur
dioxide (SO2) and particulate matter (PM).
3. Associated refers to secondary sources of emissions that arise from associated
operations in natural gas systems. Associated emissions may result from the
combustion of other fossil fuels (i.e., other than the natural gas stream) to power
equipment, machinery, and transportation as wel as the associated release of dust
and PM from construction, operations, and road use. Associated emissions have
the potential to contribute significantly to air pollution.11
The focus of this report is on fugitive and combusted natural gas emissions. Notwithstanding the
additional emissions from associated sources, the primary focus of this report is on air quality
issues related to the resource itself (i.e., the fugitive release of natural gas and its combustion
during operations). It is this release of natural gas—and the pollutants contained within it—that
makes air quality considerations in the crude oil and natural gas sector unique from other
manufacturing-, construction-, and transportation-intensive sectors.
Sources of Emissions
Natural gas systems include many activities and pieces of equipment that have the potential to
emit air pollutants.
 Production sector (upstream). Production operations include the wel s and al
related processes used in the extraction, production, recovery, lifting,
stabilization, separation, and treating of oil and/or natural gas. Production
operations span the initial wel dril ing, hydraulic fracturing, and wel completion
activities and include not only the “pads” where the wel s are located but also the
sites where oil, condensate, produced water, and gas from several wel s may be
separated, stored, and treated as wel as the gathering pipelines, compressors, and
related components that collect and transport the oil, gas, and other materials
from the wel s to the refineries or natural gas processing plants. Emissions of
fugitive gas can be released both intentional y and unintentional y from many of
these activities and pieces of equipment.

Since production operations occur upstream from gas processing, any fugitive
release of gas may include quantities of VOCs, H2S, HAPs, and other pollutants
at concentrations found within the reservoirs. Further, as some of these
operations involve the initial removal of wastes and byproducts from the natural

the primary purpose of flaring is to act as a safety device to minimize explosive conditions. Gas may be flared at many
points in the system; however, it is most common during the drilling and well completion phases, specifically at oil
wells with associated gas. Compared to vented emissions, combustion is generally considered a better pollution control
mechanism because the process serves to incinerate many of the VOCs and HAPs that would otherwise be released
directly into the atmosphere.
11 Air standards for various mobile and stationary source engines are covered in several parts of the Code of Federal
Regulations, including 40 C.F.R. Part 60, Subpart JJJJ—Standards of Performance for Stationary Spark Ignition (SI)
Internal Combustion Engines (ICE) and 40 C.F.R. Part 60, Subpart IIII —Standards of Performance for Stationary
Compression Ignition (CI) ICEs as well as 40 C.F.R. Part 80, et seq.—Regulations of Fuels and Fuel Additives. For
more information about standards for particulate matter, see CRS Report R40096, 2006 National Am bient Air Quality
Standards (NAAQS) for Fine Particulate Matter (PM2.5): Designating Nonattainm ent Areas, by Robert Esworthy.
Congressional Research Service

4

Methane and Other Air Pollution Issues in Natural Gas Systems

gas stream, the types and quantities of emissions may be dependent upon how the
wastes are managed (e.g., venting, flaring, separation, and storage). Historical y,
the greatest concern over air emissions from the production sector has focused on
leaks from equipment and pipelines as wel as combustion exhaust from
compressor stations. Recently, however, concern has incorporated other activities
such as dril ing, hydraulic fracturing, wel completions, and workovers.
 Processing sector (midstream). Processing operations are used to separate out
the byproducts and wastes from raw natural gas in order to produce “pipeline
quality” or “dry” natural gas for consumption. Due to the many and varied
activities involved in these operations, natural gas processing plants have the
potential to release significant quantities of air pollutants. These emissions result
from the combustion of natural gas and other fossil fuels in compression engines
as wel as from the fugitive release of VOCs, SO2, and HAPs from separators,
dehydrators, and sweetening units used to extract byproducts and wastes from the
natural gas stream.
 Transmission, storage, and distribution sectors (downstream). After
processing, dry natural gas enters pipelines in the transmission, storage, and
distribution sectors for delivery to utilities and consumers. Nationwide, natural
gas systems consist of thousands of miles of pipe, including both mains and
customer service lines, as wel as compressors, storage facilities, and metering
stations, which al ow companies to both move and monitor the natural gas in the
system. Due to the extensive network of pipelines, valves, pumps, and other
components within the transmission, storage, and distribution sectors, fugitive
releases of gas collectively can be a significant source of emissions. However,
because these activities general y occur after processing, VOC, H2S, and HAP
content can be minimal, with methane remaining the primary component.
Pollutants
Air pollutants associated with natural gas systems include, most prominently, methane and
VOCs—of which the crude oil and natural gas sector is one of the highest-emitting industrial
sectors in the United States—as wel as NOx, SO2, and various forms of HAPs.
 Methane. Methane—the principal component of natural gas—is both a precursor
to ground-level ozone formation (i.e., “smog”)12 and a potent GHG,13 albeit with
a shorter climate-affecting time horizon than CO2. Every process in natural gas
systems has the potential to emit methane. EPA’s Inventory of U.S. Greenhouse

12 While methane is a precursor to ground-level ozone formation, it is less reactive than other hydrocarbons. T hus, EPA
has officially excluded it from the definition of VOCs. See EPA, Conversion Factors for Hydrocarbon Em ission
Com ponents, July 2010, p. 2, https://19january2017snapshot.epa.gov/www3/otaq/models/nonrdmdl/nonrdmdl2005/
420r05015.pdf.
13 As a GHG, methane emitted into the atmosphere absorbs terrestrial infrared radiation, which contributes to increased
global warming and continuing climate change. According to the Intergovernmental Panel on Climate Change (IPCC)
Fifth Assessm ent Report 2013, http://www.ipcc.ch/report/ar5/wg1/, in 2011, methane concentrations in the atmosphere
exceeded preindustrial levels by 150%. Further, they contributed about 16% to global warming due to anthropogenic
GHG sources, making methane the second-leading climate forcer after CO2 globally. While the perturbation lifetime
for methane is 12 years, CO2’s is considerably longer and does not undergo a simple decline over a single predictable
timescale. For further discussion on climate change and its potential impacts, see CRS Report R45086, Evolving
Assessm ents of Hum an and Natural Contributions to Clim ate Change, by Jane A. Leggett.
Congressional Research Service

5

Methane and Other Air Pollution Issues in Natural Gas Systems

Gas Emissions and Sinks: 1990-2017 (released April 11, 2019) estimates 2017
methane emissions from “Natural Gas Systems” (i.e., the natural gas supply
chain) to be 6,624 gigagrams (Gg) (equivalent to 343.9 bil ion standard cubic feet
[bscf], or 1.2% of the industry’s marketed production that year).14 In 2017,
natural gas systems represented nearly 25% of the total methane emissions from
al domestic sources and accounted for approximately 2.5% of al GHG
emissions in the United States.15 Natural gas systems are currently the second-
largest contributor to U.S. anthropogenic (i.e., man-made) methane emissions.16
Because of methane’s effects on climate, EPA has found that it, along with five
other wel -mixed GHGs, endangers public health and welfare within the meaning
of the CAA.17
 VOCs—a ground-level ozone precursor. The crude oil and natural gas sector is
currently one of the largest sources of VOC emissions in the United States,
accounting for approximately 20% of man-made VOC emissions nationwide (and
representing almost 40% of VOC emissions released by stationary source
categories).18 VOCs—in the form of various hydrocarbons—are emitted
throughout a wide range of natural gas operations and equipment. The interaction
among VOCs, NOx, and sunlight in the atmosphere contributes to the formation
of ozone (i.e., smog). Ozone exposure is linked to several respiratory ailments.
 NOx—a ground-level precursor. Significant amounts of NOx are emitted at
natural gas sites through the combustion of natural gas and other fossil fuels (e.g.,
diesel). This combustion occurs during several activities, including (1) the flaring
of natural gas during dril ing and wel completions, (2) the combustion of natural
gas to drive the compressors that move the product through the system, and (3)
the combustion of fuels in engines, dril s, heaters, boilers, and other production,

14 EPA reported 2017 methane emissions from natural gas systems to be 6,624 Gg, equivalent to 165.6 million metric
tons of CO2 equivalent (MMtCO2e). EPA reported 2017 methane emissions from all sources to be 656.3 MMtCO2e and
2017 GHG emissions from all sources to be 6,456.7 MMtCO2e. EPA, Inventory of U.S. Greenhouse Gas Em issions and
Sinks: 1990-2017, EPA 430-R-19-001, April 11, 2019, https://www.epa.gov/ghgemissions/inventory-us-greenhouse-
gas-emissions-and-sinks. Here, as elsewhere in the report, GHGs are quantified using a unit measurement called CO 2
equivalent (CO2e), wherein gases are indexed and aggregated against one unit of CO2. T his index is commonly referred
to as the Global Warming Potential (GWP). T he data in this report are based on EPA’s 2019 inventory and the IPCC
Fourth Assessm ent Report 2007 wherein GWP values for methane are 25 and 72 over a 100 -year and a 20-year time
horizon, respectively. EIA reports 2017 U.S. natural gas marketed production to be 29,203.55 bscf. See
https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_VGM_mmcf_a.htm . CRS uses a conversion of 1 Gg = 0.051921
bscf. For more discussion of methane, see CRS In Focus IF10752, Methane Em issions: A Prim er, by Richard K.
Lattanzio.
15 T he end use combustion of natural gas (e.g., in the commercial, residential, transportation, or electric power
generating sectors) emits GHGs, primarily in the form of CO2, which is accounted for separately in EPA’s inventory.
16 Enteric fermentation is the largest contributor. Methane is produced as part of normal digestive processes in animals,
particularly ruminant livestock (e.g., cattle). Microbes that reside in the animal’s digestive system ferment food
consumed by the animal and produce methane as a byproduct, which can be eructated (i.e., belching or flatulence) by
the animal.
17 EPA, “Endangerment and Cause or Contribute Findings for Greenhouse Gases,” 74 Federal Register 66496-66516,
December 15, 2009.
18 EPA’s 2014 National Emissions Inventory estimated VOC emissions from “oil and gas” stationary sources to be 3.23
million tons, from all stationary sources to be 8.26 million tons, and from all anthropogenic sources to be 16.48 million
tons. Data for VOCs, as well as the other criteria pollutants and HAP s, are derived from EPA’s National Emissions
Inventory, https://www.epa.gov/sites/production/files/2017-04/documents/2014neiv1_profile_final_april182017.pdf.
Congressional Research Service

6

Methane and Other Air Pollution Issues in Natural Gas Systems

construction, and transportation equipment.19 In addition to its contribution to
ozone formation, NOx exposure is linked to several other respiratory ailments.
 SO2 is emitted from crude oil and natural gas production and processing
operations that handle and treat sulfur-rich, or “sour,” gas. SO2 exposure is linked
to several respiratory ailments.
 Hazardous Air Pollutants (HAPs). HAPs, also known as air toxics, are those
pollutants that are known or suspected to cause cancer or other serious health
effects, such as reproductive diseases, or birth defects. Of the HAPs emitted from
natural gas systems, VOCs are the largest group and typical y evaporate easily
into the air. The most common HAPs in natural gas systems are n-hexane and the
BTEX compounds (benzene, toluene, ethylbenzene, and xylenes). Further, some
natural gas reservoirs may contain high levels of H2S.20 HAPs are found
primarily in natural gas itself and are emitted from equipment leaks and from
various processing, compressing, transmission, distribution, or storage
operations. They are also a byproduct of incomplete fuel combustion and may be
components in various chemical additives.
The Federal Role
Several federal agencies have authorities to set standards on the natural gas industry that could
have the effect of controlling air emissions. This report summarizes some of the more significant
actions taken by EPA, the U.S. Department of the Interior’s Bureau of Land Management (BLM),
and the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety
Administration (PHMSA).
EPA and the Clean Air Act
The CAA21 seeks to protect human health and the environment from emissions that pollute
ambient, or outdoor, air.22 It requires EPA to establish minimum national standards for air
emissions from various source categories (e.g., EPA has listed “Crude Oil and Natural Gas
Production” and “Natural Gas Transmission and Storage” as source categories) and assigns
primary responsibility to the states to assure compliance with the standards. EPA has largely
delegated day-to-day responsibility for CAA implementation to the states, including permitting,
monitoring, inspections, and enforcement. In many cases, states have further delegated program
implementation to local governments. Sections of the CAA that are most relevant to air quality
issues in natural gas systems are outlined in the following sections.

19 NOx emissions from engines and turbines are covered by 40 C.F.R. Section 60, Subparts JJJJ and KKKK,
respectively.
20 Hydrogen sulfide was on the original list of hazardous air pollutants in the CAA, Section 112(b), but was
subsequently removed by Congress. Currently, hydrogen sulfide is regulated under the CAA’s Accidental Release
Program, Section 112(r)(3). According to EPA, there are 14 major areas found in 20 different states where hydrogen
sulfide is commonly found in natural gas deposits. As a result of drilling in these areas, “the potential for routine
[hydrogen sulfide] emissions is significant.” See EPA, Report to Congress on Hydrogen Sulfide Air Emissions
Associated with the Extraction of Oil and Natural Gas, EPA-453/R-93-045, October 1993, at ii, III-35; see also ii, II-5
to II-11.
21 42 U.S.C. 7401 et seq. For a summary of the CAA and EPA’s air and radiation activities and its authorities, see
EPA’s website at http://www.epa.gov/air/basic.html; and CRS Report RL30853, Clean Air Act: A Summary of the Act
and Its Major Requirem ents, by James E. McCarthy.
22 Outdoor is defined as that to which the public has access (see 40 C.F.R. §50.1(e)).
Congressional Research Service

7

Methane and Other Air Pollution Issues in Natural Gas Systems

National Ambient Air Quality Standards
Section 109 of the CAA requires EPA to establish National Ambient Air Quality Standards
(NAAQS) for air pollutants that may reasonably be anticipated to endanger public health or
welfare and whose presence in ambient air results from numerous or diverse sources. Using this
authority, EPA has promulgated NAAQS for SO2, particulate matter (PM2.5 and PM10), nitrogen
dioxide (NO2), CO, ozone, and lead. States are required to implement specified air pollution
control plans to monitor these pollutants and ensure that the NAAQS are met or “attained.”
Additional measures are required in areas not meeting the standards, referred to as
“nonattainment areas.” “Nonattainment” findings for ozone, NO2, and SO2 in areas with crude oil
and natural gas operations have resulted in states establishing specific pollution control
mechanisms that affect the industry.
New Source Performance Standards
Section 111 of the CAA requires EPA to promulgate regulations establishing emission standards
that are applicable to new, modified, and reconstructed sources—if such sources cause or
contribute significantly to air pollution that may reasonably be anticipated to endanger public
health or welfare. A New Source Performance Standard (NSPS) reflects the degree of emission
limitation achievable through the application of the “best system of emission reduction,” which
EPA determines has been adequately demonstrated. EPA has had minimum standards for VOCs
and SO2 at processing facilities in the oil and gas industry for over a decade.23
Under the Obama Administration, on August 16, 2012, EPA promulgated new standards for
several sources in the “Crude Oil and Natural Gas Production” source category never before
regulated at the federal level. The 2012 standards aim to control VOC emissions from new or
modified onshore natural gas wel s, centrifugal compressors, reciprocating compressors,
pneumatic controllers, storage vessels, and leaking components at onshore natural gas processing
plants as wel as SO2 emissions from new or modified onshore natural gas processing plants.24
The 2012 standards include, most prominently, a requirement for producers to reduce VOC
emissions by 95% from an estimated 11,000 new hydraulical y fractured gas wel s each year
through the use of “reduced emissions completions” (RECs) or “green completions.” RECs are
defined by EPA as “wel completion[s] following fracturing or refracturing where gas flowback
that is otherwise vented is captured, cleaned, and routed to the flow line or collection system, re-
injected into the wel or another wel , used as an on-site fuel source, or used for other useful
purpose that a purchased fuel or raw material would serve, with no direct release to the
atmosphere.” The rule also requires certain pneumatics, storage vessels, and compressors to
achieve at least a 95% reduction of VOC emissions.
On December 31, 2014, EPA made several amendments to the 2012 standards, including (1)
establishing the definition of flowback period for the purposes of compliance, (2) making several

23 In 1979, the EPA published a list of source categories, including “crude oil and natural gas production,” for which
the EPA would promulgate standards of performance under Section 111(b) of the CAA. EPA, “ Priority List and
Additions to the List of Categories of Stationary Sources,” 44 Federal Register 49222, August 21, 1979.
24 EPA, “Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for
Hazardous Air Pollutants Reviews, Final Rule,” 77 Federal Register 49489, August 16, 2012. T hese standards, in part,
revised existing standards promulgated by EPA, including NSPS for Equipment Leaks of VOCs from Onshore Natural
Gas Processing Plants (40 C.F.R. Part 60, Subpart KKK) and NSPS for SO2 Emissions for Onshore Natural Gas
Processing (40 C.F.R. Part 60, Subpart LLL). T he new NSPS are codified as 40 C.F.R. Part 60, Subpart OOOO.
Congressional Research Service

8

Methane and Other Air Pollution Issues in Natural Gas Systems

changes to storage vessel provisions, and (3) removing an affirmative defense provision that
shielded facility operators from civil penalties for violations resulting from malfunction.25
On June 3, 2016, EPA promulgated updates to the 2012 standards “for methane and VOC
emissions from new and modified oil and gas production sources, and natural gas processing and
transmission sources.”26 The 2016 rule sets first-ever controls for methane emissions and extends
controls for VOC emissions beyond the previously existing requirements to include new or
modified hydraulical y fractured oil wel s, pneumatic pumps, compressor stations, and leak
detection and repair at wel sites, gathering and boosting stations, and processing plants. The final
rule also includes the issuance for public comment of an Information Collection Request (ICR)
that would require companies to provide extensive information instrumental for developing
comprehensive regulations to reduce methane emissions from existing oil and gas sources. In a
similar action, EPA finalized Control Techniques Guidelines (CTG) for the oil and natural gas
sector, providing recommendations for reducing VOC emissions from existing oil and natural gas
industry emission sources in ozone nonattainment areas classified as moderate or higher and in
states within the Ozone Transport Region.27
In a direct response to the Obama-era standards, and in line with his campaign promises,
President Trump signed Executive Order 13783 on March 28, 2017. The order—entitled
“Promoting Energy Independence and Economic Growth”—requires agencies to review existing
regulations and “appropriately suspend, revise, or rescind those that unduly burden” domestic
energy production and use.28 Section 7 of the executive order specifical y directs the EPA
Administrator to review several regulations related to U.S. oil and gas development, including the
agency’s methane standards.
Effective March 2, 2017, EPA withdrew the ICR to assess the need for this information and to
reduce the burden to businesses during this assessment.29 The ICR withdrawal was issued shortly
after nine state attorneys general and two governors submitted a letter to EPA asking that the ICR
be suspended and withdrawn.30
On June 5, 2017, EPA published a rule to delay by 90 days the fugitive emissions, pneumatic
pump, and professional engineer certification requirements of the 2016 NSPS w hile the agency
reconsiders these provisions.31 Under the proposal, “sources will not need to comply with these
requirements while the stay is in effect.”32 On July 3, 2017, the U.S. Court of Appeals for the
District of Columbia Circuit vacated EPA’s administrative 90-day stay, agreeing with arguments

25 EPA, “Oil and Natural Gas Sector: Reconsideration of Additional Provisions of New Source Performance
Standards,” 79 Federal Register 79018, December 31, 2014.
26 EPA, “ Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources: Final Rule,”
81 Federal Register 35823, June 3, 2016.
27 EPA, “ Release of Final Control T echniques Guidelines for the Oil and Natural Gas Industry,” 81 Federal Register
74798, October 27, 2016.
28 Executive Order 13783, “Promoting Energy Independence and Economic Growth,” 82 Federal Register 16093,
March 28, 2017.
29 EPA, “Notice Regarding Withdrawal of Obligation to Submit Information,” 82 Federal Register 12817, March 7,
2017.
30 Letter from Ken Paxton, Attorney General, T exas, to E. Scott Pruitt, Administrator, EPA, March 1, 2017,
https://www.epa.gov/sites/production/files/2017-03/documents/letter_from_attorneys_general_and_governors.pdf.
31 EPA, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources; Grant of
Reconsideration and Part ial Stay,” 82 Federal Register 25730, June 5, 2017.
32 Letter from E. Scott Pruitt, Administrator, EPA, to petitioner, April 18, 2017, https://www.epa.gov/sites/production/
files/2017-04/documents/oil_and_gas_fugitive_emissions_monitoring_reconsideration_4_18_2017.pdf .
Congressional Research Service

9

Methane and Other Air Pollution Issues in Natural Gas Systems

that the agency improperly used its authority under CAA Section 307(d)(7)(B) to pause
provisions of the rule.33 On June 16, 2017, EPA proposed rulemaking for a two-year extension to
the stay34 and issued a notice of data availability related to the agency’s proposed stay on
November 8, 2017.35 In the notice, EPA provided additional information on several topics raised
by stakeholders and solicited comment on the information presented.
On March 12, 2018, EPA published a final rule to make two “narrow” revisions to the 2016
NSPS. The rule removes the requirement that leaking components be repaired during unplanned
or emergency shutdowns and provides separate monitoring requirements for wel sites located on
the Alaskan North Slope.36 In addition, EPA published a notice of proposed withdrawal,
requesting comment, on the 2016 CTG for the oil and natural gas sector.37
On October 15, 2018, EPA proposed a larger set of amendments to the 2016 NSPS.38 The
proposal includes changes to the fugitive emissions, pneumatic pump, and professional engineer
certification requirements that were the focus of the earlier rule delay. The proposed changes
would decrease the frequency for monitoring fugitive emissions at wel sites and compressor
stations; decrease the schedule for making repairs; expand the technical infeasibility provision for
pneumatic pumps to al wel sites; and amend the professional engineer certification requirements
to al ow for in-house engineers. Upon the proposal’s release, the agency stated that it “continues
to consider broad policy issues in the 2016 rule, including the regulation of greenhouse gases in
the oil and natural gas sector,” and that “these issues wil be addressed in a separate proposal at a
later date.”39 The October 2018 proposal has not been finalized.
On September 24, 2019, EPA proposed more substantive amendments to the 2012 and 2016
NSPSs that would remove al sources in the transmission and storage segment of the oil and
natural gas industry from regulation under the NSPS for both ozone-forming VOCs and GHGs.40
The amendments would also rescind the methane requirements in the 2016 NSPS that apply to
sources in the production and processing segments of the industry. The proposed amendments
would remove the agency’s obligation to develop emission guidelines to address methane
emissions from existing sources under Section 111(d) of the Clean Air Act. The proposal also
seeks comment on alternative interpretations of the agency’s legal authority to regulate pollutants
(specifical y methane) under Section 111 of the Clean Air Act.41

33 Clean Air Council, et al. v. EPA, No. 17-1145 (D.C. Cir. July 3, 2017).
34 EPA, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources: Stay of
Certain Requirements,” 82 Federal Register 27645, June 16, 2017.
35 EPA, “ Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources: Stay of
Certain Requirements,” 82 Federal Register 51788, November 8, 2017.
36 EPA, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources;
Amendments: Final Rule,” 83 Federal Register 52056, October 15, 2018.
37 EPA, “Notice of Proposed Withdrawal of the Control T echniques Guidelines for the Oil and Natural Gas Industry ,”
83 Federal Register 10478, March 12, 2018.
38 EPA, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources
Reconsideration; Proposed Rule,” 83 Federal Register 10628, March 12, 2018.
39 EPA, “ EPA Proposes Amendments to the 2016 New Source Performance Standards for the Oil and Natural Gas
Industry: Fact Sheet ,” https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/proposed-
improvements-2016-new-source.
40 EPA, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review,” 84
Federal Register 50244, September 24, 2019.
41 In the 2016 NSPS, EPA took the position that the law did not require that the agency, as a prerequisite to regulating
methane as part of the NSPS, first make a separate, pollutant -specific determination that GHG emissions (primarily
methane) from the oil and natural gas industry cause or significantly contribute to air pollution that may endanger
Congressional Research Service

10

Methane and Other Air Pollution Issues in Natural Gas Systems

EPA finalized the October 2018 proposal on September 15, 202042 and the September 2019
proposal on September 14, 2020, 2020.43
National Emission Standards for Hazardous Air Pollutants
Section 112 of the CAA requires EPA to promulgate National Emissions Standards for Hazardous
Air Pollutants (NESHAPs). NESHAPs are applicable to both new and existing sources of HAPs,
and there are NESHAPs for both “major” sources and “area” sources of HAPs.44 The aim is to
develop technology-based standards that require emission levels met by the best existing facilities
(commonly referred to as maximum achievable control technology, or MACT, standards). The
pollutants of concern in natural gas systems are, most prominently, the BTEX compounds,
carbonyl sulfide, and n-hexane. EPA promulgated NESHAPs for both the “Crude Oil and Natural
Gas Production” and the “Natural Gas Transmission and Storage” sectors in 1999. These
standards contain provisions for both major sources and area sources of HAPs and include storage
vessels with flash emissions45 (major sources only), equipment leaks (major sources only), and
dehydrators (major and area sources).46
The air standards promulgated on August 16, 2012, revise the existing NESHAPs to establish
MACT standards for “smal ” dehydrators (which were unregulated under the initial NESHAPs),
strengthen the leak detection and repair requirements, and retain the existing NESHAPs for
storage vessels.
Air Permits
The CAA Amendments of 1990 added Title V, which requires major sources of air pollution to
obtain operating permits, and amended the CAA requirements for Prevention of Significant
Deterioration (PSD) and Nonattainment New Source Review (NSR) preconstruction permits.47

public health or welfare. T he 2019 proposal seeks comment on whether the agency should revise this position.
42 EPA, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources
Reconsideration, Final Rule,” 85 Federal Register 57398, September 15, 2020.
43 EPA, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review, Final
Rule,” 85 Federal Register 57018, September 14, 2020. In the final policy amendments, the agency states: “ EPA is
finalizing a determination that the source category includes only the production and processing segments of the
industry and is rescinding the standards applicable to the transmission and storage segment of the industry. T his
determination is based on the EPA’s review of the original source category listing and its 2012 and 2016 Rules’
interpretations of, and its 2016 Rule’s revision to, the scope of the source category, which, as revised, covered sources
in the transmission and storage segment. Having reexamined its prior rulemakings regarding the scope of this source
category and the transmission and storage segment, the EPA has determined that the revision in the 2016 Rule of the
original source category was not appropriate. Because the EPA is determining that the original source category did not
cover the transmission and storage segment, and that this segment constitutes a separate source category from the
production and processing segments, the EPA was authorized to list it for regulation under CAA section 11 1(b) only by
making a cause-or-contribute-significantly and endangerment finding as required by the statute, which the EPA never
did.”
44 A major source of HAPs is one with the potential to emit in excess of 10 tons per year (T py) of any single HAP or 25
T py of two or more HAPs combined. Area sources are those sources that are not “ major.”
45 Flash emissions occur when produced liquid (crude oil or condensate) is exposed to temperature increases or
pressure decreases during the transfer from the production separators (or similar sources) into atmospheric storage
tanks.
46 See NESHAPs from Oil and Natural Gas Production Facilities (40 C.F.R. Part 63, Subpart HH) and NESHAPs from
Natural Gas T ransmission and Storage Facilities (40 C.F.R. Part 63, Subpart HHH).
47 42 U.S.C. §§7661-7661f. For background, see CRS Report RL33632, Clean Air Permitting: Implementation and
Issues, by Claudia Copeland.
Congressional Research Service

11

link to page 23 Methane and Other Air Pollution Issues in Natural Gas Systems

EPA has delegated primary responsibility for Title V, PSD, and NSR permitting to state and local
authorities. Sources subject to the permit requirements general y include new or modified sources
that emit or have the potential to emit 10 tons to 250 tons per year, depending upon the pollutant
and the area’s attainment status. While natural gas processing facilities typical y fal under major
source determination, most crude oil and natural gas production activities upstream from the
processing plant have not been classified as major sources.48
On June 3, 2016, EPA promulgated rules to clarify the definitions for “major source” categories in
the oil and natural gas sector and the conditions under which certain pieces of equipment can be
aggregated.49
Greenhouse Gas Reporting
In the FY2008 Consolidated Appropriations Act (H.R. 2764; P.L. 110-161), Congress directed
EPA to establish a mandatory GHG reporting program (GHGRP) that applies to emissions that
are “above appropriate thresholds in al sectors of the economy.” EPA issued the Mandatory
Reporting of Greenhouse Gases Rule,50 which became effective on December 29, 2009. It
includes annual reporting requirements for many facilities in the crude oil and natural gas sector.51
EPA collects these data to inform the agency’s annual Inventory of U.S. Greenhouse Gas
Emissions and Sinks.
BLM Waste Prevention Standards
In addition to EPA’s CAA authorities, Congress authorized BLM to set standards to conserve
federal mineral resources under the Mineral Leasing Act of 1920 (MLA), as amended (30 U.S.C.
§181 et seq.). Section 225 of the act requires BLM to ensure that lessees “use al reasonable
precautions to prevent waste of oil or gas developed in the land” and, under Section 187, that
leases include “a provision that such rules ... for the prevention of undue waste as may be
prescribed by [the] Secretary shal be observed.”
Under the Obama Administration, on November 18, 2016, BLM promulgated a “Waste
Prevention, Production Subject to Royalties, and Resource Conservation” rule,52 which targets
natural gas emissions as a potential waste of public resources and loss of royalty revenue. BLM’s
rule requires operators of crude oil and natural gas facilities on federal and Indian lands to take
various actions to reduce the waste of gas, establishes clear criteria for when flared gas will

48 EPA’s guidance for “major source” determinations includes consideration of proximity, ownership, and industrial
grouping. For a more detailed discussion on major source determination for facilities in the crude oil and natural gas
sector, see the “ Major Source Aggregation” section of this report.
49 EPA, “ Source Determination for Certain Emission Units in the Oil and Natural Gas Sector: Final Rule,” 81 Federal
Register 35622, June 3, 2016.
50 EPA, “Mandatory Reporting of Greenhouse Gases,” 74 Federal Register 56260, October 30, 2009.
51 EPA, “Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems,” 75 Federal Register
74458, November 30, 2010; see final rule revision to Subpart W —Petroleum and Natural Gas Systems—amending 40
C.F.R. Section 98 (i.e., the regulatory requirements for the program). Several amendments to the reporting
methodology have been proposed and promulgated since 2010. See EPA’s GHGRP data at https://www.epa.gov/
ghgreporting.
52 BLM, “Waste Prevention, Production Subject to Royalties, and Resource Conservation, Final Rule,” 81 Federal
Register 83008, November 18, 2016.
Congressional Research Service

12

Methane and Other Air Pollution Issues in Natural Gas Systems

qualify as waste and therefore be subject to royalties, and clarifies which on-site uses of gas are
exempt from royalties.53
The BLM rule was eligible for consideration under the Congressional Review Act at the start of
the 115th Congress.54 On February 3, 2017, the House passed a joint resolution of disapproval
(H.J.Res. 36) to repeal it. The Senate rejected the motion to proceed on May 10, 2017.
Under the Trump Administration, BLM announced on June 15, 2017, that it would delay the
compliance dates of several requirements of the rule that are slated to take effect in January
2018.55 These include “requirements that operators capture a certain percentage of the gas they
produce, measure flared volumes, upgrade or replace pneumatic equipment, capture or combust
storage tank vapors, and implement leak detection and repair ... programs.” The Postponement
Notice invoked Section 705 of the Administrative Procedure Act (APA) and concluded that
“justice requires [BLM] to postpone the future compliance dates for [certain] sections of the
Rule” in light of “the substantial cost that complying with these requirements poses to operators
... and the uncertain future these requirements face in light of the pending litigation and
administrative review of the Rule.”
On July 5, 2017, California and New Mexico filed a lawsuit in the U.S. District Court for the
Northern District of California chal enging the legality of the postponement notice.56 The two
states were joined on July 10, 2017, by more than a dozen environmental and tribal groups.57 On
October 4, 2017, the U.S. District Court for the Northern District of California granted both
motions and ruled against BLM’s initial postponement.58
On December 8, 2017, BLM finalized rulemaking to suspend or delay certain requirements
contained in the 2016 final rule until January 17, 2019.59 The bureau stated that it reviewed the
2016 final rule and determined that the costs the rule is expected to impose would exceed the
benefits it is expected to generate. On February 22, 2018, the U.S. District Court for the Northern
District of California issued an order enjoining the rule.60 Thus, the rule, as original y
promulgated, remains in effect.
On February 12, 2018, BLM proposed a new rule “to revise the 2016 final rule in a manner that
reduces unnecessary compliance burdens, is consistent with the BLM’s existing statutory
authorities, and reestablishes long-standing requirements that the 2016 final rule replaced.”61

53 For more detail on BLM’s rule and a comparison of its requirements to EPA’s standards, see CRS Insight IN10645,
EPA’s and BLM’s Methane Rules, by Richard K. Lattanzio (available to congressional clients from the author by
request).
54 See CRS In Focus IF10023, The Congressional Review Act (CRA), by Maeve P. Carey and Christopher M. Davis.
55 BLM, “ Waste Prevention, Production Subject to Royalties, and Resource Conservation; Postponement of Certain
Compliance Dates,” 82 Federal Register 27430, June 15, 2017. For more information, see CRS Legal Sidebar
WSLG1806, UPDATE: BLM Venting and Flaring Rule Survives (For Now), by Linda T sang.
56 Complaint for Declaratory Relief, California v. BLM, No. 3:17 -cv-03804-EDL (N.D. Cal. July 5, 2017).
57 Complaint for Declaratory and Injunctive Relief, Sierra Club et al., v. BLM, No. 3:17 -cv-03885 (N.D. Cal. July 10,
2017).
58 State of California, et al., v. BLM; Sierra Club, et al., v. Ryan Zinke, Nos. 17-cv-03804-EDL, 17-cv-3885-EDL,
(N.D. Cal. October 4, 2017).
59 BLM, “ Waste Prevention, Production Subject to Royalties, and Resource Conservation; Delay and Suspension of
Certain Requirements, Final Rule,” 82 Federal Register 58050, December 8, 2017.
60 State of California, et al., v. BLM; Sierra Club, et al., v. Ryan Zinke, Nos. 17-cv-07186-WHO, 17-cv-07187-WHO
(N.D. Cal. February 22, 2018).
61 BLM, “ Waste Prevention, Production Subject to Royalties, and Resource Conservation; Rescission or Revision of
Certain Requirements, Proposed Rule,” 83 Federal Register 7924, February 22, 2018.
Congressional Research Service

13

Methane and Other Air Pollution Issues in Natural Gas Systems

BLM finalized the rule on September 28, 2018.62 The rule rescinds the novel requirements
pertaining to waste-minimization plans, gas-capture percentages, wel dril ing, wel completion
and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and
leak detection and repair (LDAR), returning these requirements to the preexisting royalty
provisions promulgated in DOI’s 1980 Notice to Lessees, NTL-4A.63 It revises other provisions
related to venting and flaring (by placing volume and/or time limits on royalty-free venting and
flaring during production testing, emergencies, and downhole wel maintenance and liquids
unloading) and adds provisions regarding deference to appropriate state or tribal regulation in
determining when flaring of associated gas from oil wel s wil be royalty-free. The final rule was
effective on November 27, 2018.
In July 2020, a California federal district court vacated the 2018 BLM rule.64 The district court
held that BLM misinterpreted the MLA by limiting the definition of waste of oil or gas to apply
only when the compliance costs are not greater than the monetary value of the oil or gas.65 The
court also ruled that BLM failed to provide a reasoned explanation for its “abrupt reversal” of its
findings in the 2016 rule and violated the National Environmental Policy Act and the APA.66
BLM has appealed the district court decision to the U.S. Court of Appeals for the Ninth Circuit. 67
The California federal district court stayed its vacatur until October 13, 2020, to al ow the parties
time to restart the litigation chal enging the 2016 rule in the federal district court in Wyoming,
which had been paused during BLM’s reconsideration of that rule.68 The Wyoming federal district
court granted the state petitioners’ request to resume its chal enge to the reinstated 2016 rule.69
In its brief of August 18, 2020, BLM declined to defend the 2016 rule and asked the Wyoming
district court to vacate it, “confess[ing] error” and acknowledging that it violated the APA by
failing to adequately explain and support key provisions of the 2016 rule.70 BLM also admitted
that the 2016 rule exceeded its authority under the MLA by “imposing uneconomical
conservation obligations” on federal oil and gas lease operators.71 Various environmental groups
and two states (California and New Mexico), which intervened in support of 2016 rule, remain in
the case to defend the rule.72

62 BLM, “ Waste Prevention, Production Subject to Royalties, and Resource Conservation; Rescission or Revision of
Certain Requirements, Final Rule,” 83 Federal Register 49184, September 28, 2018.
63 DOI, Geological Survey Conservation Division, “Not ice to Lessees and Operators of Onshore Federal and Indian Oil
and Gas Leases,” January 1, 1980.
64 California v. Bernhardt, No. 4:18-cv-05712-YGR, 2020 U.S. Dist. LEXIS 128961 (N.D. Cal. July 15, 2020).
65 Id. at *7-8.
66 Id. at *7-8, *126.
67 Defendant’s Notice of Appeal, California v. Bernhardt, No. 4:18-cv-05712-YGR, 2020 U.S. Dist. LEXIS 128961
(N.D. Cal. Sept. 14, 2020).
68 Id. at *126.
69 T he state petitioners requesting to resume the litigation are North Dakota, T exas, Wyoming and Montana. Order
Granting Motion to Lift Stay at 2, Wyoming v. U.S. Dep’t of the Interior, No. 2:16-cv-00285-SWS (D. Wyo. July 21,
2020).
70 Federal Respondents’ Supplemental Merits Response Brief, Wyoming v. U.S. Dep’t of the Interior, No. 2:16-cv-
00285-SWS (D. Wyo. Aug. 18, 2020).
71 Id.
72 Citizen Groups and State Respondents’ Supplemental Response Brief, Wyoming v. U.S. Dep’t of the Interior, No.
2:16-cv-00285-SWS (D. Wyo. Aug. 25, 2020). For further information regarding this litigation, contact Linda T sang,
CRS Legislative Attorney (ltsang@crs.loc.gov).
Congressional Research Service

14

Methane and Other Air Pollution Issues in Natural Gas Systems

PHMSA Pipeline Safety Standards
The U.S. Department of Transportation (DOT) is given primary authority to regulate the safety of
pipelines and underground natural gas storage facilities, including design, construction, operation,
maintenance, and leak/spil response planning. These activities can affect air quality issues in the
downstream sectors of the natural gas supply chain. The authorities stem from several statutes,
including the Natural Gas Pipeline Safety Act of 1968 (P.L. 90-481) and the Hazardous Liquid
Pipeline Act of 1979 (P.L. 96-129), among others. The Pipeline and Hazardous Materials Safety
Administration (PHMSA), within DOT, administers the federal pipeline safety program by
establishing safety standards; conducting programmatic inspections of management systems,
procedures, and processes; physical y inspecting facilities and construction projects; investigating
safety incidents; enforcing federal safety requirements; and maintaining a dialogue with pipeline
operators.
On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011 (P.L. 112-90). The act contains a broad range of provisions addressing
pipeline safety. Among the most significant are provisions to increase the number of federal
pipeline safety inspectors, require automatic shutoff valves for transmission pipelines, mandate
verification of maximum al owable operating pressure for gas transmission pipelines, and
increase civil penalties for pipeline safety violations. Altogether, the act imposed 42 mandates on
PHMSA regarding studies, rules, maps, and other elements of the federal pipeline safety program.
Further, on June 22, 2016, President Obama signed the Protecting our Infrastructure of Pipelines
and Enhancing Safety Act of 2016 (P.L. 114-183). The act reauthorizes provisions for PHMSA
operational expenses, user fees for underground natural gas storage facility safety, one-cal
notification programs, community pipeline safety information grants, and the pipeline integrity
program. PHMSA has fulfil ed many of the requirements under P.L. 112-90 and P.L. 114-183, and
others are near completion.73
Issues for Congress
The expansion of both industry production and government regulation of natural gas systems has
sparked discussion on a number of outstanding issues. Some of the more significant debates
involving air quality concerns are outlined in the following sections.
The Regulatory Role of Federal, State, and Local Governments
Federal regulation of air emissions in the oil and gas industry remains controversial. According to
EPA, the 2012 and 2016 federal air standards are designed to provide minimum requirements for
emissions of air pollutants from the crude oil and natural gas sector that can both protect human
health and the environment and al ow for continued growth in production. However, some believe
that state and local authorities are better positioned to develop these emission standards. They
argue that a distant federal bureaucracy unfamiliar with local conditions is rarely the best entity to
ensure that environmental needs are balanced with economic growth and job creation. They claim
that states can more readily address the regional and state-specific character of many crude oil
and natural gas activities, including differences in geology, hydrology, climate, topography,
industry characteristics, development history, state legal structures, population density, and local
economics and the effects these components have on air quality. They argue that federal rules add

73 For more information on PHMSA authorities, activities, and status of the agency mandates, see CRS Report R44201,
DOT’s Federal Pipeline Safety Program: Background and Key Issues for Congress, by Paul W. Parfomak.
Congressional Research Service

15

link to page 21 Methane and Other Air Pollution Issues in Natural Gas Systems

unnecessary and often repetitive requirements on the industry, which may increase project costs
and delays with little added benefit. They point to states such as Colorado and Wyoming—both
with more stringent air quality controls on the oil and gas industry than the federal government—
as examples of where states have succeeded in crafting regulations to balance continued industry
growth and environmental protection.
Others disagree, attesting to the inefficiencies caused by a “patchwork” of state and local
requirements. They support the need for the federal government to institute minimum standards
for emissions that are consistent and predictable and reach across state lines. They claim that a
federal standard could extend regulatory certainties to the industry and avoid a “race to the
bottom” among localities competing to attract development. Moreover, they argue that the same
federalist system used in virtual y al other environmental programs should be applied, whereby
the federal government sets a minimum national floor and states are given flexibilities in their
approach to implementation. They observe that, in other federal-state collaborative regulatory
programs, states have benefitted from sharing “lessons learned” about the availability and cost-
effectiveness of chosen technologies and practices.
Measurement of Emissions
The 2012 and 2016 federal air standards are based on EPA’s emissions estimates for the crude oil
and natural gas sector. While emissions from some activities and equipment may lend themselves
to credible estimates, others—specifical y fugitive emissions from production activities such as
hydraulical y fractured wel completions, flowback, and produced water ponds—are more
difficult to evaluate, have fewer data available, and remain under considerable debate. Currently,
the primary source of information on emissions from the sector is a methane study published in
1996 by EPA and the Gas Research Institute.74 EPA uses this methodology to calculate the
industry’s GHG emissions and publishes these data annual y in the agency’s Inventory of U.S.
Greenhouse Gas Emissions and Sinks.
EPA’s GHG inventory is a “bottom-up” approach, employing commonly accepted emission
factors and activity levels to calculate aggregate estimates for al source categories. While some
of this methodology has been representative over the period of 1996 to the present, much of it has
been revised and recalculated based on new information received through the inventory
preparation process, formal public notice periods, GHGRP data, and academic studies.
Differences in modeling, reported data, analytic assumptions, and levels of uncertainty have
resulted in significant fluctuations in methane emissions estimates. (For example, EPA’s
estimates for natural gas systems have fluctuated between 96.4 mil ion metric tons of carbon
dioxide equivalent [MMTCO2e] and 221.2 MMTCO2e over the past several years due primarily
to changes in reporting methodology.)75 This uncertainty is il ustrated in Figure 1, which presents
the historical methane emissions estimates for each GHG inventory from 2007 to 2018 based
upon each inventory’s methodology.

74 Gas Research Institute and EPA, Methane Emissions from the Natural Gas Industry, Volumes 1 -15, GRI-94/0257
and EPA 600/R-96-080, June 1996, https://www.epa.gov/sites/production/files/2016-08/documents/
1_executiveummary.pdf. T he study was an outgrowth of the analysis taken by EPA pursuant to U.S. commitments
under the United Nations Framework Convention on Climate Change and the Intergovernmental Panel on Climate
Change’s “Guidelines for National Greenhouse Gas Inventories.”
75 For more discussion of current emission estimates and historical trends, see CRS In Focus IF10752, Methane
Em issions: A Prim er, by Richard K. Lattanzio.
Congressional Research Service

16

Methane and Other Air Pollution Issues in Natural Gas Systems

EPA’s GHG inventory has been criticized by industry groups and other sources, many of which
have put forth competing—and sometimes conflicting—estimates.76 Efforts are ongoing at
producing a current, comprehensive, and consistent emissions data set for the sector.77
Figure 1. EPA’s GHG Inventories of Methane Emissions from Natural Gas Systems,
2007-2018

Source: CRS, with data from EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks, multiple years.
Notes: EPA updates its modeling assumptions for the sector and recalculates the historical emissions every year
for the publication of its inventory. The figure shows estimates for each reported year back to 1990 under the
methodologies used for each inventory year from 2007 to 2018 (e.g., the line for “Inventory Year 2018” shows
the emissions estimates for the sector for “Reported Years 1990-2016” based upon the modeling assumptions
used in 2018).
Complicating the uncertainty of measuring methane emissions from crude oil and natural gas
systems is EPA’s additional and unassociated inventory for VOC emissions: EPA’s National
Emissions Inventory (NEI).78 The NEI is an estimate of criteria pollutants, criteria precursors, and

76 See, for example, Scott Miller, “Anthropogenic Emissions of Methane in the United States,” Proceedings of the
National Academ y of Sciences of the United States of Am erica , vol. 110, no. 50 (December 10, 2013),
http://www.pnas.org/content/110/50/20018.abstract, which provides methane emission estimates for the industry
roughly 50% greater than that reported by EPA; and Karin Ritter et al., Understanding GHG Em issions from
Unconventional Natural Gas Production, 2012, http://www.epa.gov/ttnchie1/conference/ei20/session3/kritter.pdf,
which provides methane emission estimates roughly half of that reported by EPA for several source categories.
77 Efforts include (1) EPA’s efforts to update its Inventory, as outlined in its annual reporting, https://www.epa.gov/
ghgemissions/natural-gas-and-petroleum-systems; (2) the Environmental Defense Fund’s Methane Leakage Study,
http://www.edf.org/methaneleakage; and (3) several data harmonization studies of existing inventories (e.g., U.S.
Department of Energy, National Renewable Energy Laboratory, “ Life Cycle Assessment Harmonization,”
https://www.nrel.gov/analysis/life-cycle-assessment.html). Further, on June 21, 2017, EPA’s inspector general
launched a planned investigation of how the agency estimates methane emissions from the oil and gas sector, as
described in OIG’s annual plan for FY2017, released December 2016 (see James Hatfield, Director, Air Evaluations,
Office of Program Evaluation, letter to Sarah Dunham, Acting Assistant Administrator Office of Air and Radiation ,
“Project Notification: Evaluation of EPA’s Estimation of Methane Emissions from the Oil and Natural Gas Production
Sector,” June 21, 2017, https://www.epa.gov/office-inspector-general/notification-evaluation-epas-estimation-methane-
emissions-oil-and-natural).
78 EPA, 2014 National Emissions Inventory, volume 1, https://www.epa.gov/air-emissions-inventories.
Congressional Research Service

17

link to page 22

Methane and Other Air Pollution Issues in Natural Gas Systems

HAPs from air emissions sources across the United States. It is released every three years and is
based primarily upon data provided by state, local, and tribal air agencies for sources in their
jurisdictions and supplemented by data developed by EPA. As with the GHG inventory,
differences in modeling, reported data, analytic assumptions, and levels of uncertainty have
resulted in significant fluctuations in VOC emissions estimates. Figure 2 presents the 2014 NEI
emissions trends estimates for VOCs from the “Petroleum and Related Industries” source sector.
While emissions of VOCs from crude oil and natural gas systems are generally analogous with
emissions of methane, the NEI presents distinctly different data from the GHG inventory. The
disparity may be due to differences in structure, aim, definitions, and methodologies between the
two inventories as wel as underlying analytic uncertainties.
Figure 2. EPA’s Inventory of Volatile Organic Compound Emissions from Petroleum
and Related Industries, 2014

Source: CRS, with data from EPA, 2014 National Emissions Inventory, Average Annual Emissions of Criteria
Pol utants, National Tier 1, 1970-2016.
Covered Sources and Pollutants
The 2012 federal air standards focus primarily on the upstream sectors of the oil and gas industry
and cover only some of the pollutants and potential sources of emissions. The standards regulate
emissions of VOCs from some of the equipment and activities at new or modified onshore natural
gas wel sites, gathering and boosting stations, and processing plants. Similarly, the standards
regulate emissions of SO2 from new or modified sweetening units at some natural gas processing
plants as wel as HAPs from some dehydration units and storage facilities in the sector. The scope
of the 2012 federal standards is the result of several factors, including (1) statutory limitations
placed upon the agency by provisions in the CAA, (2) EPA-conducted cost-benefit and risk
analyses, and (3) stakeholder comments provided to the agency during rulemaking.79
In response to stakeholder comments and legal proceedings, EPA revisited the 2012 NSPS to
cover additional sources and pollutants. Most notably, the 2016 NSPS introduces first-ever
controls on methane emissions from new or modified equipment and activities in the oil and gas

79 In the CAA, as amended, Congress sets statutory limitations on EPA’s authority to regulate emissions from natural
gas systems in several instances. T hese include specific limitations, such as major and area source determinations for
HAPs in Section 112(n), as well as more general limitations, such as the classification of some pollutants prevalent in
the industry (e.g., hydrogen sulfide).
Congressional Research Service

18

Methane and Other Air Pollution Issues in Natural Gas Systems

sector, as wel as requirements for new or modified hydraulical y fractured oil wel s, new or
modified onshore pneumatic pumps, new or modified onshore transmission and storage sector
compressors and pneumatics, and leak detection and repair requirements for sectors beyond the
processing plant.
The 2019 NSPS proposal would rescind controls for several of these sources and pollutants,
removing al sources in the transmission and storage segment of the oil and natural gas industry
from regulation under the NSPS for both ozone-forming VOCs and GHGs and removing the
methane requirements that apply to sources in the production and processing segments of the
industry.
Notwithstanding these requirements, other pollutants from natural gas systems remain
unaddressed by any federal law or regulation, and critics point specifical y to H2S as the most
significant omission.80 Further, federal standards do not cover emissions from offshore sources,
coalbed methane production facilities, field engines, dril ing rig engines, turbines, wel -head
compressors, well-head activities such as liquids unloading, heater-treaters, storage cel ars,
sumps, and produced water ponds. Also, due to statutory limitations in the CAA, federal emission
standards do not cover VOC or SO2 emissions from existing sources unless the emissions are
classified as HAPs. Final y, EPA’s standards do not cover methane emissions from existing
sources.81
Major Source Aggregation
Determinations for which activities and pieces of equipment are considered “major sources” of
pollution with respect to CAA Title V operating permits and Prevention of Significant
Deterioration (PSD) and Nonattainment New Source Review (NSR) preconstruction permits have
been controversial.82 The 2012 federal air standards exempt wel completions, pneumatic
controllers, compressors, and storage vessels from the classification of “major source” (i.e., one
that emits typical y 10 tons to 250 tons per year, depending upon the pollutant and the area’s
attainment status).
Viewed at the component level, discrete “emissions units” at natural gas facilities may not
generate enough pollution individual y to be classified as “major sources.” However, it may be
possible that a combination of discrete “emissions units” at a natural gas operation (e.g., a wel
site, field, or station) could be grouped together, or “aggregated,” as a “major source.” For
example, under the PSD permitting program, to determine whether emitting facilities should be
aggregated for permitting purposes, EPA has defined major stationary source to include “any
[emitting] building, structure, facility, or instal ation” that is (1) in the same industrial grouping
per Standard Industrial Classification (“SIC”) codes; (2) located on “contiguous or adjacent”
properties; and (3) under common control of the same person or persons.83 The Title V major

80 H2S is covered under the Accidental Release Program, Section 112(r)(3) of the CAA; however, it is not listed as a
HAP under Section 112(b)(1). H2S emissions are typically addressed by state and local requirements (e.g., permits and
nuisance abatement authorities).
81 T he possibility remains open for EPA to propose performance standards on methane emissions for existing sources
in the fut ure. T hat is, for certain pollutants, promulgation of NSPS under Section 111(b) triggers a mandatory EPA duty
under CAA Section 111(d) to address existing sources in the same source category. At present, however, there is a
looming legal question as to precisely what those “ certain pollutants” are. T his question is likely to be debated in the
litigation over EPA’s Clean Power Plan.
82 See, for example, Summit Petroleum Corp. v. EPA, 6th Cir., Nos. 09-4348, 10-4572, 8/7/12.
83 40 C.F.R. 52.21(b)(5)-(6); 40 C.F.R. 51.165(a)(1)(i)-(ii); 40 C.F.R. 51.166(b)(5)-(6).
Congressional Research Service

19

Methane and Other Air Pollution Issues in Natural Gas Systems

source definition is consistent with the language and application of the PSD major source
definition.84 These factors are determined on a case-by-case basis for each permitting decision.
Defining what emitting facilities are “contiguous or adjacent” for purposes of major source
determinations has been interpreted differently by the states, EPA, the courts, and regulated
entities. Most recently, EPA finalized rules to clarify the meaning of the term adjacent that is used
to determine the scope of a “stationary source” in the oil and natural gas sector (published on
June 3, 2016, in conjunction with the 2016 NSPS).85 The effectiveness of these new guidelines
has yet to be determined.
In contrast to the permitting requirements for PSD, NSR, and Title V pollutants (e.g., VOCs and
SO2 for the oil and gas sector), “major” and “area” source determinations for NESHAPs in the
sector are clearly outlined in the CAA. In Section 112(n)(4), Congress specifical y exempts
upstream crude oil and natural gas operations from aggregation to determine both major and area
source categories for HAPs, excepting some activities near metropolitan areas with populations in
excess of 1 mil ion.
Impacts of Emissions
The 2012 and 2016 federal air standards are based on EPA’s expectations that the avoided
emissions under the rules would result in improvements in air quality and reductions in health
effects associated with exposure to HAPs, ozone, and methane. However, the relationship
between air pollution from natural gas systems and its impacts on human health and the
environment has yet to be ful y quantified and assessed. EPA acknowledges this shortcoming in
the 2012 rule’s proposal, stating that a full quantification of health benefits for the standards
could not be accomplished due to the “unavailability of data and the lack of published
epidemiological studies correlating crude oil and natural gas production to respective health
outcomes.”86 Nevertheless, it should be noted that comprehensive epidemiological studies are
general y difficult, rare, and expensive to conduct, requiring data that are typical y absent or
inadequate for assessment (e.g., precise and accurate estimates of emissions, fate and transport,
and exposure levels as wel as impact data on relatively large populations of exposed individuals
over extended durations of time).
Various stakeholders assert that the lack of published and peer-reviewed literature makes it
chal enging to scientifical y assess the impacts of natural gas operations. Some contend that this
uncertainty argues against additional pollution controls at this time. Others maintain that the
relevant question for determining whether pollution controls are necessary is whether natural gas
systems impact an area’s ability to attain air quality standards (NAAQS) or the country’s ability
to achieve its GHG reduction targets.
From a selection of recent studies, some of the impacts of emissions from natural gas systems
have been reported as follows:

84 61 Federal Register 34202, 34210, July 21, 1996.
85 EPA, “ Source Determination for Certain Emission Units in the Oil and Natural Gas Sector: Final Rule,” 81 Federal
Register 35622, June 3, 2016. T he rule defines adjacency to mean equipment and activities in the oil and gas sector that
are under common control and are located near each other—specifically, on the same site or on sites that share
equipment and are within one-quarter of a mile of each other.
86 EPA, Regulatory Impact Analysis: Proposed New Source Performance Standards and Amendments to the National
Em issions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry , July 2011, p. 4-1.
Congressional Research Service

20

Methane and Other Air Pollution Issues in Natural Gas Systems

 Some reports have shown significant increases in VOC and/or ozone levels in
several areas of the country with heavy concentrations of dril ing, including the
Marcel us Basin in Pennsylvania and West Virginia,87 the Piceance and Denver-
Julesburg Basins in Colorado,88 the Green River Basin in Wyoming,89 and the
Uinta Basin in Utah.90 Research (from academia and state-level environmental
agencies) attributes the rise in industry-related VOC emissions primarily to
increased traffic, combustion exhaust, and local emissions from oil and gas
development activities. However, others note that the presence of VOCs in the
atmosphere is only one of the many factors that contribute to ground-level ozone
formation. Several other surveys of air quality in these regions have shown
increases in ozone values due to effects such as stratospheric ozone intrusions91
as wel as drops in ozone values due to mitigating circumstances such as
reductions in NOx concentrations and changes in weather patterns (e.g., the Fort
Worth92 and Uinta93 Basins).
 Several local, state, and national health agencies have expressed concerns about
the health impacts of HAPs and other emissions from natural gas facilities,
including the National Institute of Environmental Health Sciences,94 the Agency
for Toxic Substances and Disease Registry (ATSDR),95 the New York State
Department of Health,96 and the Colorado School of Public Health,97 among
others. These investigations were spurred by community health complaints in

87 T imothy Vinciguerra et al., “Regional Air Quality Impacts of Hydraulic Fracturing and Shale Natural Gas Activity:
Evidence from Ambient VOC Observations,” Atm ospheric Environm ent, vol. 110 (June 2015), pp. 144-150.
88 Colorado Department of Public Health and Environment, Air Pollution Cont rol Division, Oil and Gas Emission
Sources Presentation for the Air Quality Control Com m ission Retreat, May 15, 2008, pp. 3-4.
89 Wyoming Department of Environmental Quality, Technical Support Document I for Recommended 8-Hour Ozone
Designation of the Upper Green River Basin, March 26, 2009.
90 Randal Martin et al., Final Report: Uinta Basin Winter Ozone and Air Quality Study, December 2010 -March 2011,
Energy Dynamics Laboratory, Utah State University, for Uintah Impact Mitigation Special Service District, June 14,
2011, https://binghamresearch.usu.edu/files/edl_2010-11_report_ozone_final.pdf.
91 T echnical Services Program, Air Pollution Control Division, Colorado Departm ent of Public Health and
Environment, “Technical Support Document for the May 24, 2010, Stratospheric Ozone Intrusion Exceptional Event, ”
October 7, 2011, https://www.colorado.gov/airquality/tech_doc_repository.aspx?action=open&file=
T SD_O3_Intrusion_Event_052410.pdf.
92 T exas Commission on Environmental Quality, “A Commitment to Air Quality in the Barnett Shale,” Natural
Outlook Newsletter, Fall 2010, https://www.tceq.texas.gov/assets/public/comm_exec/pubs/pd/020/10-04/Outlook-Fall-
2010.pdf.
93 Utah Department of Environmental Quality, Ozone in the Uintah Basin.
94 National Institute of Environmental Health Sciences, “Hydraulic Fracturing and Health,” https://www.niehs.nih.gov/
health/topics/agents/fracking/index.cfm.
95 AT SDR, Health Consultation: Public Health Implications of Ambient Air Exposure to Volatile Organic Compounds
as Measured in Rural, Urban, and Oil & Gas Development Areas Garfield County, Colorado , March 13, 2008,
https://www.atsdr.cdc.gov/hac/pha/Garfield_County_HC_3-13-08/Garfield_County_HC_3-13-08.pdf.
96 New York State Department of Health, “A Public Health Review of High Volume Hydraulic Fracturing for Shale
Gas Development ,” December 2014, https://www.health.ny.gov/press/reports/docs/
high_volume_hydraulic_fracturing.pdf.
97 Roxana Witter et al., Health Impact Assessment for Battlement Mesa, Garfield County, Colorado , Colorado School
of Public Health, 2010, https://www.garfield-county.com/public-health/documents/
1%20%20%20Complete%20HIA%20without%20Appendix%20D.pdf ; Lisa McKenzie et al., “ Human Health Risk
Assessment of Air Emissions from Development of Unconventional Natural Gas Resources,” Sci Total Environ., May
1, 2012, 424:79-87, http://www.sciencedirect.com/science/article/pii/S0048969712001933.
Congressional Research Service

21

Methane and Other Air Pollution Issues in Natural Gas Systems

regard to natural gas operations such as strong odors, dizziness, nausea,
respiratory problems, and eye and skin irritation, and more severe concerns
including cancer. Some of the reports identified, on average, slightly elevated
cancer risks at some sites. Most recommended further investigation into HAP
emissions and risks at al sites.
 Final y, a variety of studies have examined the impacts—both positive and
negative—of GHG emissions from natural gas systems. Many observe that the
combustion of natural gas is less carbon-intensive than other fossil fuels (i.e., on
a per-unit-of-energy basis) and claim that fuel switches to natural gas would
benefit the climate by reducing overal CO2 emissions. Other studies, however,
focus on the potential impacts of fugitive methane releases. They argue that
fugitive methane may contribute significantly to GHG emissions from the sector
and may counteract some of the environmental benefits that the U.S. economy
has to gain by switching from coal or oil to natural gas.98
Cost-Benefit Analysis of Federal Standards
Natural gas is a product of—and thus a source of revenue for—the oil and gas industry. It is also a
source of pollution from the industry when it is emitted into the atmosphere. Due to this unique
linkage, pollution abatement has the potential to translate into economic benefits for the industry,
as producers may be able to offset some compliance costs with the value of natural gas products
recovered and sold. To capitalize on these incentives, many recovery technologies have been
incorporated into industry practices.99 Whether product recovery is profitable for producers may
depend upon a number of factors, including the nature and extent of the release, the technology
available for capture, and the market price for the recovered products. Because these factors vary
significantly over time and place, incentives to control for emissions based solely on market
forces have been inconsistent.
Both EPA and BLM considered the costs and the benefits of their respective rulemakings on the
crude oil and natural gas sector. These considerations were conducted as required by statute (e.g.,
CAA,100 MLA)101 and by executive orders and guidance (e.g., Executive Order 12866,

98 For more discussion of methane’s GHG emissions impacts in the power sector, see CRS Report R44090, Life-Cycle
Greenhouse Gas Assessm ent of Coal and Natural Gas in the Power Sector, by Richard K. Lattanzio.
99 For examples of available technologies and operating practices and the marginal costs associated with their
employment, see, for example, ICF International, “ Economic Analysis of Methane Emission Reduction Opportunities
in the U.S. Onshore Oil and Natural Gas Industries,” prepared for the Environmental Defense Fund, March 2014,
http://www.edf.org/sites/default/files/methane_cost_curve_report.pdf.
100 T he CAA defines standard of perform ance as “a standard for emissions of air pollutants which reflects the degree of
emission limitation achievable through the application of the best system of emission reduction which (taking into
account the cost of achieving such reduction and any non -air quality health and environmental impact and energy
requirement) the Administrator determines has been adequately demonstrated” (42 U.S.C. 7411(a)(1)). T he CAA does
not provide specific direction regarding what metric or metrics to use in considering costs for a standard of
performance, affording EPA considerable discretion in choosing a means of cost consideration.
101 T he MLA requires BLM to set royalty rates and determine the quantity of produced oil and gas that is subject to
royalties under the terms and conditions of a federal lease. T he MLA also requires BLM to ensure that lessees “ use all
reasonable precautions to prevent waste of oil or gas developed in the land” (30 U.S.C. 225). BLM has long read the
MLA to exempt from royalty payments production that is “unavoidably lost ” in the course of production. (See 44
Federal Register 76600.) In determining when production is unavoidably versus avoidably lost, BLM has generally
considered the technical and economic feasibility of preventing the loss of gas. (See BLM, “ Notice to Lessees and
Operators of Onshore Federal and Indian Oil and Gas Leases (NT L -4A): Royalty or Compensation for Oil and Gas
Loss,” January 1, 1980, https://www.ntc.blm.gov/krc/uploads/172/NT L-
Congressional Research Service

22

Methane and Other Air Pollution Issues in Natural Gas Systems

“Regulatory Planning and Review”; Executive Order 13563, “Improving Regulation and
Regulatory Review”; and Circular A-4 from the Office of Management and Budget [OMB]).102
Neither the CAA nor the MLA requires that the regulatory agency set the level of control based
on a cost-benefit analysis (CBA). However, executive orders require developing and considering
CBA, as wel as producing a RIA and other administrative addenda.103 Specifical y, the executive
orders encourage agencies to “propose or adopt a regulation only upon a reasoned determination
that the benefits of the intended regulation justify its costs.” As such, to the extent al owed by
law,104 the agencies have general y sought options that yield only net benefits (i.e., that are worth
more to society than they cost).
In their respective analyses, the agencies calculated regulatory compliance costs for the affected
industry to include initial capital costs and annualized engineering costs. These calculations
incorporated estimates for new technology investment, increased monitoring and reporting
requirements, and the adoption of additional management or workplace practices. Costs were then
adjusted for the estimated revenues generated from the recovered natural gas and other products
that would otherwise have been vented or flared.
The agencies calculated regulatory benefits in both monetized and nonmonetized terms.
Monetized benefits included those from reductions in methane emissions, which were valued
using the social cost of methane (SC-CH4).105 Nonmonetized benefits included estimates for
improvements in ambient air quality and reductions in negative health effects associated with
exposure to hazardous air pollutants, ozone, and particulate matter, which the agencies
determined could not be adequately monetized with the data currently available. In addition to
these health improvements, nonmonetized benefits included improvements in visibility,
ecosystem effects, and additional natural gas recovery.

4A%20Royalty%20or%20Compensation%20for%20Oil%20and%20Gas%20Lost.pdf.)
102 Under Executive Orders 12866 and 13563, each economically significant regulatory action taken by covered
agencies (under any statutory authority) must include estimates of the cost and benefits of the action in Regulatory
Impact Analyses (RIAs) before it is proposed and again before it is promulgated. T hese RIAs can play a major role in
the interagency review process overseen by the OMB, which precedes the publication of most agencies’ significant
proposed and final rules in the Federal Register. See Executive Order 12866, “ Regulatory Planning and Review,” 58
Federal Register 51735, October 4, 1993; and Executive Order 13563, “ Improving Regulations and Regulatory
Review,” 76 Federal Register 3821, January 21, 2011. For more on this OMB review process, see CRS Report
RL32397, Federal Rulem aking: The Role of the Office of Inform ation and Regulatory Affairs, coordinated by Maeve P.
Carey.
103 See CRS Report R41974, Cost-Benefit and Other Analysis Requirements in the Rulemaking Process, coordinated by
Maeve P. Carey.
104 Some statutory provisions require other criteria for setting the stringency of a regulation, for examp le, to protect the
most vulnerable populations.
105 EPA and other federal agencies have used metrics recommended by an interagency working group and publicly peer
reviewed for the social cost of carbon (SC-CO2) to estimate the climate benefits of rulemakings. EPA and BLM have
used, in a few cases, the SC-CH4, which employs similar methods but for methane (published citation below) . T he SC-
CO2 and SC-CH4 are estimates of the economic damages associated with a small increase in CO2 and methane
emissions, conventionally analyzed as one metric ton, in a given year. T he stream of projected future avoided damages
due to those emissions, translated into monetary values, are discounted back to a single “ net present value” for the year
of emissions. T he avoided damages noted, in their analytical documentation, are not comprehensive of all likely
climate change damages, though they include changes in net agricultural and forest productivity, human health,
protection against sea level rise, and changes in energy system costs, such as reduced costs for heating and increased
costs for air conditioning. T hey also include damages outside of the United States, a major point of contention raised by
critics. See CRS In Focus IF10625, Social Costs of Carbon/Greenhouse Gases: Issues for Congress, by Jane A.
Leggett .
Congressional Research Service

23

Methane and Other Air Pollution Issues in Natural Gas Systems

The 2012 NSPS require natural gas producers to use recovery technologies to capture
approximately 95% of the methane and VOCs that escape into the air as a result of hydraulic
fracturing operations. At the time, EPA reported the potential environmental benefits of the 2012
standards as follows: VOC reductions of 190,000 tons annual y, air toxics reductions of 12,000
tons annual y, and methane reductions of 1.0 mil ion tons annual y. The agency estimated that the
equipment and the activities required to comply with the 2012 standards would cost producers
about $170 mil ion per year but that incorporating the sale of recovered products into the cost
would result in an estimated net gain of about $11 mil ion to $19 mil ion per year. The industry
disagreed with these estimates and countered with compliance costs at more than $2.5 bil ion
annual y.106 Third parties, such as Bloomberg Government, projected a net cost between $316
mil ion and $511 mil ion.107
For the 2016 NSPS, EPA reported the potential environmental benefits by 2025 as follows: VOC
reductions of 210,000 tons, air toxics reductions of 3,900 tons, and methane reductions of
510,000 tons.108 The agency estimated that the total annualized engineering costs of the 2016
NSPS would be $530 mil ion in 2025 (2012 dollars), but it calculated that incorporating the sale
of recovered products into the cost would recover approximately $30 mil ion of this total. Using
SC-CH4 metrics, the rule was estimated to yield climate benefits of $690 mil ion in 2025.
Industry sources contend that EPA exaggerated the benefits of the 2016 rule, stating that rather
than net benefits of more than $100 mil ion, net costs could be $150 mil ion in 2020 and $290
mil ion to $400 mil ion in 2025.109 Third parties, such as researchers at Stanford University,
estimated that the 2016 standards would cost about a third less than what the agency reports but
may not lead to the expected emissions reductions.110
BLM estimated that the 2016 waste prevention rule would avoid 175,000-180,000 tons of
methane emissions per year and yield total benefits from $209 mil ion to $403 mil ion per year,
outweighing the costs of $110 mil ion to $275 mil ion per year. BLM estimated annual royalties
to the federal government, tribal governments, states, and private landowners to increase by $3
mil ion to $10 mil ion per year. Industry countered with a net benefit assessment of -$143 mil ion
to -$278 mil ion for the proposed rule, arguing against the agency’s use of the SC-CH4 metric and
other assumptions.111
Al cost estimates are based on assumptions regarding the quantity of captured emissions, the cost
and availability of capital equipment, and the market price for natural gas.112

106 See, for example, Advanced Resources International, Estimate of Impacts of EPA Proposals to Reduce Air
Em issions from Hydraulic Fracturing Operations, prepared for the American Petroleum Institute, February 2012 .
107 Rich Heidorn Jr., Fracking Emission Rules: EPA, Industry Miss Mark on Costs, Consequences, Bloomberg
Government, 2012.
108 EPA, “Regulatory Impact Analysis of the Final Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources,” EPA-452/R-16-002, May 2016.
109 NERA Economic Consulting, “ T echnical Comments on the Social Cost of Methane as Used in the Regulatory
Impact Analysis for the Proposed Emissions Standards for New and Modified Sources in the Oil and Natural Gas
Sector,” prepared for American Council for Capital Formation, December 3, 2015, http://www.nera.com/publications/
archive/2015/technical-comments-on-the-social-cost-of-methane-as-used-in-the-.html.
110 Arvind Ravikumar and Adam Brandt, “Designing Better Methane Mitigation Policies: T he Challenge of Distributed
Small Sources in the Natural Gas Sector,” Environm ental Research Letters, vol. 12, no. 4 (April 19, 2017),
http://iopscience.iop.org/article/10.1088/1748-9326/aa6791.
111 American Petroleum Institute, “Comments on BLM’s Proposed Waste Prevention and Resource Conservation Rule:
Attachment A,” April 22, 2016, https://www.regulations.gov/document?D=BLM-2016-0001-9073.
112 For more on the cost-benefit analysis of air quality standards and its use during federal agency rulemaking, see CRS
Report R44840, Cost and Benefit Considerations in Clean Air Act Regu lations, by James E. McCarthy and Richard K.
Congressional Research Service

24

Methane and Other Air Pollution Issues in Natural Gas Systems

Under the Trump Administration, analysis of the costs and benefits of environmental
regulations—specifical y estimates regarding the social cost of carbon and methane—are under
reconsideration.113 These reconsiderations affect the cost-benefit analysis of the Obama-era
methane standards in significant ways.114 For the 2019 proposed NSPS, the agency estimated that
the oil and natural gas industry would save a total of $97 mil ion to $123 mil ion from 2019
through 2025, or $17 mil ion to $19 mil ion a year. The total cost savings reflected both the cost
savings associated with proposed changes to requirements in the rule and the forgone value of
natural gas that would not be recovered as a result of those changes. Further, EPA’s analysis
estimated that certain emissions reductions would not occur from 2019 through 2025 as a result
of the proposed amendments, including 370,000 short tons of methane (8.4 MMTCO2e), 10,000
short tons of VOCs, and 300 short tons of HAPs. The analysis reported the total present value of
climate benefits within the United States that would not occur at $13 mil ion (under a 7%
discount rate) or $52 mil ion (under a 3% discount rate), which translated to $2.3 or $8.1 mil ion
per year, respectively.115
Conclusion
U.S. natural gas production has grown markedly in recent years. This growth is due in large part
to increased activities in unconventional resources brought on by technological advance. Many
have advocated for the increased production and use of natural gas in the United States for
economic, national security, and environmental reasons. They argue that natural gas is the
cleanest-burning fossil fuel, with fewer emissions of CO2, NOx, SO2, PM, and mercury than other
fossil fuels (e.g., coal and oil) on a per-unit-of-energy basis. For these reasons, many have looked
to natural gas as a “bridge” fuel to a less polluting and lower GHG-intensive economy. However,
the recent expansion in natural gas production in the United States has given rise to a new set of
concerns regarding human health and environmental impacts, including impacts on air quality.
To address air quality and other environmental issues, the oil and gas industry in the United States
has been regulated under a complex set of local, state, and federal laws. Currently, state and local
authorities are responsible for virtual y al of the day-to-day regulation and oversight of natural
gas systems, and many states have passed laws and/or promulgated rules to address air quality
issues based on local needs. Further to this, organizations such as the State Review of Oil and
Natural Gas Environment Regulations (STRONGER) are available to help states assess the
overal framework of environmental regulations supporting oil and gas operations in their
regions.116
At the federal level, EPA promulgated minimum national standards for emissions of methane,
VOCs, SO2, and HAPs for some source categories in the crude oil and natural gas sector.
Additional y, BLM promulgated rules to reduce potential waste of public resources and loss of
royalty revenue. The federal standards focus primarily on the production and processing sectors

Lattanzio.
113 EPA, “Increasing Consistency and T ransparency in Considering Costs and Benefits in the Rulemaking Process:
Advance Notice of Proposed Rulemaking,” 83 Federal Register 27524, June 13, 2018.
114 For more discussion on this issue, see CRS In Focus IF10625, Social Costs of Carbon/Greenhouse Gases: Issues for
Congress, by Jane A. Leggett .
115 EPA, “Regulatory Impact Analysis for the Proposed Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Review,” August 2019.
116 ST RONGER is a nonprofit, multi-stakeholder organization that specializes in assessing the overall framework of
environmental regulations supporting oil and gas operations. Its collaborative review teams encompass industry,
regulators, and environmental/public interest stakeholders. For more information, see http://www.strongerinc.org/.
Congressional Research Service

25

Methane and Other Air Pollution Issues in Natural Gas Systems

of the industry and were drawn, in part, from existing requirements found in the codes of states
such as Colorado and Wyoming. These federal standards have been revised. BLM rescinded
many of the novel requirements of its rule on September 28, 2018. EPA rescinded its
requirements for methane on September 14, 2020.
Further, many producers in the crude oil and natural gas sector have set forth a series of
recommended practices. These practices are sustained by the economic incentives provided by
capturing the fugitive releases of natural gas and its byproducts to be sold at market. Several
voluntary partnerships sponsored by various federal and international agencies also serve to
facilitate recommended practices for emissions reductions in the oil and gas industry. EPA’s
Natural Gas STAR Program, the Global Methane Initiative (formerly the Methane to Markets
Partnership), and the World Bank Global Gas Flaring Reduction Partnership are three such
programs.117
Debate continues over the regulation of methane, VOC, SO2, and HAP emissions from the crude
oil and natural gas sector. Information and technology are rapidly evolving. Conflicts between
federal and state governments remain, and the argument that environmental regulations hinder
economic growth continues to be made. Complicating this debate is the fact that a comprehensive
national inventory of fugitive emissions from natural gas systems does not exist due to many
factors, including costs and technical uncertainties. For these reasons, the choice of policy that
returns the most efficient, flexible, cost-effective, and environmental y sound emissions controls
on the sector has remained an open question.

Author Information

Richard K. Lattanzio

Specialist in Environmental Policy

Disclaimer
This document was prepared by the Congressional Research Service (CRS). CRS serves as nonpartisan
shared staff to congressional committees and Members of Congress. It operates solely at the behest of and
under the direction of Congress. Information in a CRS Report should n ot be relied upon for purposes other
than public understanding of information that has been provided by CRS to Members of Congress in
connection with CRS’s institutional role. CRS Reports, as a work of the United States Government, are not
subject to copyright protection in the United States. Any CRS Report may be reproduced and distributed in
its entirety without permission from CRS. However, as a CRS Report may include copyrighted images or
material from a third party, you may need to obtain the permission of the copyright holder if you wish to
copy or otherwise use copyrighted material.

117 For more information about EPA’s Natural Gas ST AR Program, see http://www.epa.gov/gasstar/. For the Global
Methane Init iative, see EPA’s website, https://www.epa.gov/gmi. For the Global Gas Flaring Reduction Partnership,
see the World Bank’s website, http://go.worldbank.org/KCXIVXS550.
Congressional Research Service
R42986 · VERSION 29 · UPDATED
26