An Overview of Unconventional Oil and
Natural Gas: Resources and Federal Actions
Michael Ratner
Specialist in Energy Policy
Mary Tiemann
Specialist in Environmental Policy
July 15, 2013
Congressional Research Service
7-5700
www.crs.gov
R43148

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Summary
The United States has seen a resurgence in petroleum production, mainly driven by technology
improvements—hydraulic fracturing and directional drilling—developed for natural gas
production from shale formations. Application of both of these technologies enabled natural gas
to be economically produced from shale and other unconventional formations, and contributed to
the United States becoming the world’s largest natural gas producer in 2009. Use of these
technologies has also contributed to the rise in U.S. oil production over the last few years. In
2009, annual oil production increased over 2008, the first annual rise since 1991, and has
continued to increase each year since then. Between 2008 and 2012, U.S. annual crude oil
production rose by 1.5 million barrels per day, with about 92% of the increase coming from shale
and related tight oil formations in Texas and North Dakota. Overall petroleum liquids grew by 2.1
million barrels per day, with much of the increase in natural gas liquids coming from shale gas
plays. Other tight oil plays are also being developed, and helped raise the prospect of energy
independence, particularly for North America.
The rapid expansion of oil and gas extraction using hydraulic fracturing—both in rural and more
densely populated areas—has raised concerns about its potential environmental and health
impacts. These concerns have focused primarily on potential impacts to groundwater and surface
water quality, public and private water supplies, and air quality.
States broadly regulate oil and gas exploration and production on non-federal lands. State laws
and regulations governing unconventional oil and natural gas development have been evolving
across the states in response to changes in production practices, largely in response to the use of
high-volume hydraulic fracturing in combination with directional drilling. However, state
regulations vary considerably, leading to calls for more federal regulation of unconventional oil
and natural gas extraction activities.
Although several federal environmental laws can apply to certain activities related to oil and gas
production, proposals to expand federal regulation in this area have been highly controversial.
Some advocates of a larger federal role point to a wide range of differences among state
regulatory regimes, and argue that a national framework is needed to ensure a consistent
minimum level of protection for surface and groundwater resources, and air quality. Others argue
against more federal involvement, and point to the long-established state oil and natural gas
regulatory programs, regional differences in geology and water resources, and concern over
regulatory redundancy.
The federal role in regulating oil and gas extraction activities—and hydraulic fracturing, in
particular—has been the subject of considerable debate and legislative proposals for several
years, but legislation has not been enacted. While congressional debate has continued, the
Administration has pursued a number of regulatory initiatives related to unconventional oil and
gas development under existing statutory authorities.
This report focuses on the growth in U.S. oil and natural gas production driven primarily by tight
oil formations and shale gas formations. It also reviews selected federal environmental regulatory
and research initiatives related to unconventional oil and gas extraction, including the Bureau of
Land Management (BLM) proposed hydraulic fracturing rule.

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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Contents
Introduction: Change Is Afoot ......................................................................................................... 1
Geology Is What Makes a Resource Unconventional ..................................................................... 2
Price Drives Industrial Innovation ................................................................................................... 2
Technologies Stimulate Shale Gas Production First ........................................................................ 4
Natural Gas Liquids: A Production Driver ................................................................................ 4
Increased Tight Oil Production Raises Independence Possibility .................................................... 5
Environmental Concerns and Responses ......................................................................................... 7
State Regulation of Oil and Gas Development ........................................................................ 10
Debate over the Federal Role .................................................................................................. 14
Selected Federal Responses to Unconventional Resource Extraction ..................................... 15
EPA Study on Hydraulic Fracturing and Drinking Water .................................................. 15
Multiagency Collaboration on Unconventional Oil and Gas Research ............................. 16
BLM Proposed Rule on Hydraulic Fracturing .................................................................. 17
Coast Guard Regulation of Barge Shipments of Shale Gas Wastewater ........................... 19
Conclusion: Above- and Below-Ground Issues a Concern ............................................................ 20

Figures
Figure 1. Percentage of U.S. Oil and Natural Gas from Tight Oil and Shale Gas ........................... 1
Figure 2. Daily U.S. Natural Gas Prices .......................................................................................... 3
Figure 3. Monthly U.S. Natural Gas Production ............................................................................. 4
Figure 4. Natural Gas, Oil, and NGL Prices .................................................................................... 5
Figure 5. Monthly U.S. Oil Production ........................................................................................... 6
Figure 6. Unconventional Shale Plays in the Lower 48 States ...................................................... 11
Figure 7. Hydraulic Fracturing Chemical Disclosure by State ...................................................... 13

Tables
Table A-1. Selected Federal Actions Related to Unconventional Oil and Gas Production ............ 21

Appendixes
Appendix. Selected Federal Initiatives Related to Unconventional Oil and Gas Production ........ 21

Contacts
Author Contact Information........................................................................................................... 24
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Introduction: Change Is Afoot
In the past, the oil and natural gas industry considered resources locked in tight, impermeable
formations like shale uneconomical to produce. Advances in directional well drilling and
reservoir stimulation, however, have dramatically changed this perspective. It is production from
these unconventional formations that has changed the U.S. energy posture and global energy
markets.
U.S. oil and natural gas production is on the rise, primarily driven by resources from tight
formations. The techniques developed to produce shale gas—directional drilling and hydraulic
fracturing1—have migrated to the oil sector. The United States is the third-largest oil producer in
the world, but also the fastest-growing producer. The United States surpassed Russia in 2009 as
the world’s largest natural gas producer. Production from tight formations is expected to make up
a significant part of production of each commodity well into the future (see Figure 1).
Figure 1. Percentage of U.S. Oil and Natural Gas from Tight Oil and Shale Gas
2005-2040

Source: U.S. Energy Information Administration, Annual Energy Outlook 2013, http://www.eia.gov/forecasts/aeo/
index.cfm.
Note: Prior to 2007, the Energy Information Administration did not report tight oil and shale gas data.
This report focuses on the growth in U.S. oil and natural gas production driven primarily by tight
oil formations and shale gas formations. It does not address other types of unconventional
production such as coalbed methane or tight gas, as their contributions to overall U.S. production
have not changed as dramatically as shale gas.2 There has been continued congressional interest

1 Hydraulic fracturing is an industry technique that uses water, sand, and chemicals under pressure to enhance the
recovering of natural gas and oil. It has taken on new prominence as it has been applied to tight oil and shale gas
formation as an essential method for producing resources from those types of formations.
2 Coalbed methane and tight gas accounted for 33% of U.S. natural gas production in 2011, but are projected to account
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through the 113th Congress related to unconventional natural gas and oil production. In May
2013, the Senate Energy and Natural Resources Committee held three roundtable discussions on
natural gas supply and use.3 The House Energy and Commerce Committee’s Subcommittee on
Energy and Power held a hearing in June 2013 on U.S. energy abundance.4
Geology Is What Makes a Resource Unconventional
Unconventional formations are fine-grained, organic-rich, sedimentary rocks—usually shales and
similar rocks. The shales and rocks are both the source of and the reservoir for oil and natural gas,
unlike conventional petroleum reservoirs. The Society of Petroleum Engineers describes
“unconventional resources” as petroleum accumulations that are pervasive throughout a large area
and that are not significantly affected by pressure exerted by water (hydrodynamic influences);
they are also called “continuous-type deposits” or “tight formations.” In contrast, conventional oil
and natural gas occur in porous and permeable sandstone and carbonate reservoirs. Under
pressure exerted by water, the hydrocarbons migrated upward from organic sources until an
impermeable cap-rock (such as shale) trapped it in the reservoir rock. Although the
unconventional formations may be as porous as other sedimentary reservoir rocks, their
extremely small pore sizes and lack of permeability make them relatively resistant to hydrocarbon
flow. The lack of permeability means that the oil and gas typically remain in the source rock
unless natural or artificial fractures occur.
Price Drives Industrial Innovation
Historically, natural gas prices in the United States have been volatile. From 1995 to 1999 the
spot price of natural gas averaged $2.23 per million British thermal units (MBtu), but increased to
an average price of $4.68 per MBtu, in nominal dollars, during the 2000-to-2004 period, an
almost 110% rise. Prices hit a peak in December 2005 at $15.38 per MBtu, but remained
relatively high through July 2008, as can be seen in Figure 2. Along with the rise in prices, U.S.
net imports of natural gas also rose, increasing 32% between 1995 and 2000 and 41% between
1995 and 2007.

(...continued)
for only 28% in 2040, according to the Energy Information Administration (EIA).
3 Full Committee Forum: Domestic Supply and Exports, Senate Energy and Natural Resources Committee, May 21,
2013, http://www.energy.senate.gov/public/index.cfm/hearings-and-business-meetings?ID=0380bed7-f9ef-4450-bfa0-
a3af60f7a184.
4 “U.S. Energy Abundance: Regulatory, Market, and Legal Barriers to Export,” House Energy and Commerce
Committee, Subcommittee on Energy and Power, June 18, 2013, http://energycommerce.house.gov/hearing/us-energy-
abundance-regulatory-market-and-legal-barriers-export.
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Figure 2. Daily U.S. Natural Gas Prices
2002-2012

Source: U.S. Energy Information Administration.
Note: Units = nominal dollars per million British thermal units (MBtu).
As U.S. prices and imports continued to trend up, industry undertook two competing solutions to
meet the need for more natural gas—increased liquefied natural gas (LNG) imports and
development of techniques to produce shale gas. The LNG import facilities were much higher-
profile and were cited extensively in industry and popular press. Approximately 50 import
projects were proposed, and eight were eventually constructed during the mid- to late 2000s,
along with the recommissioning of older facilities.
Although horizontal drilling and hydraulic fracturing have been industry techniques for some
time, their application to shale gas formations is relatively new. Advances in directional drilling,
particularly steerable down-hole motors, allowed drilling operators to better keep the well bore in
the hydrocarbon-bearing shale formations. Well stimulation was also required, and improvements
in hydraulic fracturing techniques, particularly multistage hydraulic fracturing and the ability to
better control the fractures, contributed to making shale gas production a profitable venture.
In 2007, the Energy Information Administration (EIA) first recorded shale gas production, when
it accounted for just 7% of U.S. natural gas production. In 2012, shale gas production accounted
for more than 30% of U.S. production, while almost all the LNG import terminals are idle and
many have applied to become export terminals.5

5 For additional information on U.S. natural gas exports, see CRS Report R42074, U.S. Natural Gas Exports: New
Opportunities, Uncertain Outcomes, by Michael Ratner et al.
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Technologies Stimulate Shale Gas Production First
The application of advances in directional drilling and hydraulic fracturing were first applied to
shale gas formations, particularly as natural gas prices increased in the mid-2000s. Methane
molecules and those of natural gas liquids (NGLs) are smaller than crude oil molecules and
therefore tend to be more responsive to hydraulic fracturing. The success of shale gas
development has driven U.S. natural gas production to increase almost every month on a year-on-
year basis (see Figure 3) from 2006 through 2012. The rise in shale gas development has also
resulted in natural gas prices declining, as shown in Figure 2.
Figure 3. Monthly U.S. Natural Gas Production
2007-2012

Source: U.S. Energy Information Administration.
Note: Units = million British thermal units (MBtu).
The decline in prices and production in the latter half of 2008 was mainly the result of the
economic downturn. However, as the economy picked up in 2009, natural gas resumed its upward
production trajectory while prices stayed low. Overall U.S. natural gas production grew, as did the
contribution from shale. The continued increase in production can be attributed, in part, to
industry improvements in extracting more of the natural gas from the shale formations. Continued
progress in hydraulic fracturing and directional drilling techniques has enabled companies to
drive down production costs while increasing output.
Natural Gas Liquids: A Production Driver
Natural gas liquids (NGLs) have taken on a new prominence as shale gas production has
increased and prices have fallen. As natural gas prices have stayed low, company interests have
shifted away from dry natural gas production to more liquids-based production. NGL is a general
term for all liquid products separated from natural gas at a gas processing plant, and includes
ethane, propane, butane, and pentanes. When NGLs are present with methane, which is the
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primary component of natural gas, the natural gas is referred to as either “hot” or “wet” gas. Once
the NGLs are removed from the methane, the natural gas is referred to as “dry” gas, which is
what most consumers use.
Each NGL has its own market and its own value. As the price for dry gas has dropped because of
the increase in supply and other reasons, such as the warm winter of 2011, the natural gas
industry has turned its attention to producing in areas with more wet gas in order to bolster the
value it receives (see Figure 4). Some companies have shifted their production portfolios to tight
oil formations, such as the Bakken in North Dakota and Montana, to capitalize on the experience
they gained in shale gas development. Historically, the individual NGL products have been priced
against oil, except for ethane. As oil prices have remained higher since 2008 relative to natural
gas, they have driven an increase of wet gas production. Because of its low price, dry gas is often
treated as a “by-product” of wet gas and oil production, despite its low price.
Figure 4. Natural Gas, Oil, and NGL Prices
2010-2012

Source: U.S. Energy Information Administration.
Notes: According to EIA, the NGL composite price is derived from daily Bloomberg spot price data for natural
gas liquids at Mont Belvieu, TX, weighted by gas processing plant production volumes of each product as
reported on Form EIA-816, “Monthly Natural Gas Liquids Report.” The mix of NGLs will vary by source, and
the price will vary by the actual market for the product. The natural gas price is at Henry Hub, and the oil price
is West Texas Intermediate (WTI). Units = nominal dollars per million British thermal units (MBtu).
Increased Tight Oil Production Raises
Independence Possibility
The prospect of U.S. energy independence is grounded in the production growth from tight oil
formations such as the Bakken Formation in North Dakota and Montana, and the Eagle Ford
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Formation in Texas.6 Relative to other fuels, the United States is more dependent upon imports
for its oil requirements, still accounting for almost 40% of consumption.7 Canada is the largest
supplier of U.S. oil imports, which is why energy independence is usually mentioned as North
American energy independence.8 The United States added a total of more than 850,000 barrels
per day (b/d) of oil production between 2011 and 2012 (see Figure 5), and production in
February 2013 was up almost 1 million b/d over 2012. U.S. oil production has reached levels not
seen in more than a decade, but is almost 2.5 million b/d short of the highs in the 1970s. Since
2005, when imports reached a peak, they have dropped more than 3 million b/d, or 23%, through
2012.9 Also since 2005, U.S. consumption of crude oil and petroleum products has been trending
downward, contributing to the decrease in imports.
Figure 5. Monthly U.S. Oil Production
2007-2012

Source: U.S. Energy Information Administration.
Note: Units = nominal dollars per million barrels per day (MMb/d).
The continued shift of industry resources toward oil-rich production has prompted forecasts of
continued growth. Domestic crude oil production is projected to rise through the end of the
decade. The tremendous increases are primarily due to dramatic increases in production from the

6 For additional information on the Bakken Formation, see CRS Report R42032, The Bakken Formation: Leading
Unconventional Oil Development, by Michael Ratner et al.
7 For additional information on U.S. oil imports, see CRS Report R42465, U.S. Oil Imports and Exports, by Robert
Pirog.
8 CRS Report R41875, The U.S.-Canada Energy Relationship: Joined at the Well, by Paul W. Parfomak and Michael
Ratner. Mexico is the third-largest source of U.S. oil imports, but is not always included in discussions of North
American energy independence, as its oil sector is not as integrated with the United States as is Canada’s.
9 U.S. Energy Information Administration, U.S. Imports of Crude Oil and Petroleum Products, March 15, 2013,
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MTTIMUS2&f=A.
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previously mentioned Bakken Formation in North Dakota and the Eagle Ford play in Texas, both
tight oil formations.10
Environmental Concerns and Responses
As with other energy sources or fuel production, the development of unconventional oil and gas
resources can pose environmental risks, many of which potentially may be mitigated with
appropriate safeguards and existing technology. The recent large-scale increase in unconventional
oil and gas production may result in both negative and positive environmental impacts,
comparatively speaking. For example, increased unconventional oil and gas production activity
has in some cases placed a strain on water resources, and on wastewater treatment plants that
were not designed to remove chemicals, salts, and other contaminants from hydraulic fracturing
flowback and produced water. On the other hand, natural gas is seen by many as a “bridge” fuel
that provides more energy per unit of greenhouse gas produced than some alternatives (e.g., coal),
and has only recently been produced in sufficient quantity and at low enough prices to provide a
viable alternative fuel that is widely regarded as relatively cleaner-burning.
Nonetheless, the rapid expansion of oil and natural gas extraction using high-volume hydraulic
fracturing—both in rural and more densely populated areas—has generated controversy due to its
potential scale and impacts on land and water resources, air quality, communities, and
landowners.11
Water quality issues have received the most attention, and of these, the potential risks associated
with well stimulation by hydraulic fracturing have been at the forefront. Complaints of
contaminated well water have emerged in various areas where unconventional oil and gas
development is occurring,12 although regulators have not reported a direct connection between
hydraulic fracturing of shale formations and groundwater contamination. In shale formations, the
vertical distance separating the target zone from usable aquifers generally is much greater than
the length of the fractures induced during hydraulic fracturing. Thousands of feet of rock layers
typically overlay the produced portion of shale, and these layers serve as barriers to flow. In these
circumstances, geologists and state regulators generally view as remote the possibility of creating
a fracture that could reach a potable aquifer. If the shallow portions of shale formations were
developed, then the thickness of the overlying rocks would be less and the distance from the shale
to potable aquifers would be shorter, posing more of a risk to groundwater. In contrast to shale,
coalbed methane (CBM) basins often qualify as underground sources of drinking water. Injection
of fracturing fluids directly into or adjacent to such formations would be more likely to present a
risk of contamination, and this is where initial regulatory attention and study was focused.13

10 Adam Sieminski, Outlook for Shale Gas and Tight Oil Development in the U.S., U.S. Energy Information
Administration, Presentation for the American Petroleum Institute, Washington, DC, April 4, 2013, p. 12.
11 For a detailed discussion of environmental issues, see, for example, New York Department of Environmental
Conservation, Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program (September 2011): Well
Permit Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing in the Marcellus Shale and Other Low-
Permeability Gas Reservoirs, September 7, 2011, http://www.dec.ny.gov/energy/75370.html.
12 See, for example, Amy Mall, Incidents Where Hydraulic Fracturing is a Suspected Cause of Drinking Water
Contamination, Natural Resources Defense Council, Switchboard, updated June 17, 2013, http://switchboard.nrdc.org/
blogs/amall/incidents_where_hydraulic_frac.html.
13 U.S. Environmental Protection Agency, Evaluation of Impacts to Underground Sources of Drinking Water by
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State regulators have expressed more concern about the groundwater contamination risks
associated with developing a natural gas or oil well (drilling through an overlying aquifer and
casing, cementing, and completing the well), as opposed to hydraulic fracturing per se. The
challenges of sealing off the groundwater and isolating it from possible contamination are
common to the development of any oil or gas well, and are not unique to hydraulic fracturing.
Identifying the source or cause of groundwater contamination can be difficult for various reasons,
including the complexity of hydrogeologic processes and investigations, a lack of baseline testing
of nearby water wells prior to drilling and fracturing, and the confidential business information
status traditionally provided for fracturing compounds. In cases that have been investigated,
regulators generally have determined that groundwater contamination was caused by failure of
well-bore casing and cementing, well operation problems, or surface activities, rather than the
hydraulic fracturing process.14
The debate over the groundwater contamination risks associated with hydraulic fracturing
operations has been fueled in part by the lack of scientific studies to assess more thoroughly the
current practices and related complaints and uncertainties. To address this issue, Congress has
directed the Environmental Protection Agency (EPA) to conduct a study on the relationship
between hydraulic fracturing and drinking water.15 The “hydraulic fracturing” debate also has
been complicated by terminology. Many who express concern over the potential environmental
impacts associated with hydraulic fracturing do not differentiate the well stimulation process of
“fracing” or “fracking” from the full range of activities associated with unconventional oil and
gas exploration and production.16
The management of the large volumes of wastewater produced during natural gas production
(including flowback from hydraulic fracturing operations and water produced from source
formations) has emerged as a significant water quality issue. In some areas, such as portions of
the Marcellus Shale region,17 capacity is limited for wastewater disposal using underground
injection wells (historically, the most common produced-water disposal practice in oil and natural

(...continued)
Hydraulic Fracturing of Coalbed Methane Reservoirs, Final Report, EPA-816-04-003, Washington, DC, June 2004, p.
4-1. (EPA reviewed 11 major coalbed methane formations to determine whether coal seams lay within underground
sources of drinking water (USDWs). EPA determined that 10 of the 11 producing coal basins “definitely or likely lie
entirely or partially within USDWs.”)
14 See, for example, New York State Department of Environmental Conservation, Fact Sheet: What We Learned from
Pennsylvania, NYS DEC NEWS, http://www.dec.ny.gov/energy/75410.html.
15 Department of the Interior, Environment, and Related Agencies Appropriations Act, 2010, P.L. 111-88, H.Rept. 111-
316. Drilling and fracturing methods and technologies have changed significantly over time as they have been applied
to more challenging formations, greatly increasing the amount of water, fracturing fluids, and well pressures involved
in oil and gas production operations. The EPA study includes five case studies that involve drinking water
contamination incidents in areas where unconventional oil and gas development is occurring.
16 A 2012 Pacific Institute study found that many individuals interviewed for the study defined “hydraulic fracturing”
much more broadly than the industry meaning of the term (i.e., injection of fluids into a production well). These
individuals used the term broadly to include well construction, completion, and other associated activities. Noting the
differences, the authors concluded that “additional work is needed to clarify terms and definitions associated with
hydraulic fracturing to support more fruitful and informed dialog and to develop appropriate energy, water, and
environmental policy.” See Hydraulic Fracturing and Water Resources: Separating the Frack from the Fiction, p. 29,
http://www.pacinst.org/reports/fracking/.
17 The Marcellus Shale formation potentially represents one of the largest unconventional natural gas resources in the
United States, underlying much of West Virginia and Pennsylvania, southern New York, eastern Ohio, western
Maryland, and western Virginia.
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gas fields), and surface discharge of wastewater is an increasingly restricted option. Additionally,
the injection of large volumes of wastewater into disposal wells has been associated with some
instances of induced seismicity.18
Other water quality concerns—associated with both conventional and unconventional oil and
natural gas extraction—include the risks of contaminating ground and surface water from surface
spills, migration of methane gas and contaminants into residential water wells from faulty well
construction, and siltation of streams from drilling and pad construction activities.19 Because of
the large volumes of water needed to extract shale gas and tight oil, water consumption issues
have emerged as well. Water use issues include the impacts that large water withdrawals might
have on groundwater resources, streams and aquatic life, and other competing uses (e.g.,
municipal or agricultural uses).
Air pollution associated with unconventional oil and natural gas production has also raised public
health concerns and has drawn regulatory scrutiny. Air pollutants can be released during various
stages of oil and natural gas production, not just hydraulic fracturing. Emission sources include
pad, road, and pipeline construction; well drilling and completion, and flowback activities; and
natural gas processing, storage, and transmission equipment. Key pollutants include methane (the
main component of natural gas and a potent greenhouse gas), volatile organic compounds
(VOCs), nitrogen oxides, sulfur dioxide, particulate matter, and various hazardous air pollutants.20
According to EPA, the oil and gas industry is a significant source of VOCs, which react with
nitrogen oxides to form ozone (smog). EPA has identified hydraulically fractured gas wells during
flowback as an additional source of VOC emissions in the natural gas industry.21
In addition to hydraulically fractured gas wells, releases of methane and other pollutants can
occur where natural gas is produced in association with oil, and natural gas gathering pipelines
and other infrastructure are lacking. In such cases, the natural gas generally must be flared or
vented. Flaring reduces VOC emissions compared to venting, but like venting, it contributes to
greenhouse gas emissions without producing an economic value or displacing other fuel
consumption.22 Natural gas flaring has become an issue with the rapid and intense development of
tight oil from the Bakken Formation in North Dakota, which has significant amounts of
associated gas.23 Other areas that have experienced large increases in tight oil production also
have had increases in the amount of natural gas being flared.

18 Katie M. Keranen, Heather M. Savage, and Geoffrey A. Abers et al., “Potentially Induced Earthquakes in Oklahoma,
USA: Links between Wastewater Injection and the 2011 Mw 5.7 Earthquake Sequence,” Geology, vol. 41, no. 3 (March
26, 2013).
19 Such impacts may be regional or localized, and can vary seasonally or with longer-term variations in precipitation.
For a discussion of water quality and supply issues associated with shale gas development, see CRS Report R42333,
Marcellus Shale Gas: Development Potential and Water Management Issues and Laws, by Mary Tiemann et al.
20 For a detailed discussion of air pollution issues associated with oil and gas exploration and development and recent
EPA regulations, see CRS Report R42833, Air Quality Issues in Natural Gas Systems, by Richard K. Lattanzio.
21 U.S. Environmental Protection Agency, Overview of Final Amendments to Air Regulations for the Oil and Natural
Gas Industry: Fact Sheet, EPA, October 2012, http://www.epa.gov/airquality/oilandgas/pdfs/20120417fs.pdf.
22 When vented, natural gas (largely methane) is released to the air without being burned. In contrast, when natural gas
is flared (burned), the main by-product is carbon dioxide. Flaring is preferred to venting, as the latter is a major
environmental concern because methane is several times more potent than carbon dioxide as a greenhouse gas,
although more short-lived in the atmosphere. During drilling, natural gas is flared for safety reasons.
23 See CRS Report R42032, The Bakken Formation: Leading Unconventional Oil Development, by Michael Ratner et
al.
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State Regulation of Oil and Gas Development
Oil and natural gas development is occurring in at least 32 states.24 Shale gas, tight oil, or other
unconventional resources are found in many of these states; primarily on non-federal lands (see
Figure 6). States are the principal regulators of oil and gas exploration and production activities
on state and private lands.25 Additionally, some states require operators on federal public lands
within state boundaries to comply with the state’s oil and gas rules.26


24 U.S. Energy Information Administration, Rankings: Natural Gas Marketed Production, 2011, 2012,
http://www.eia.gov/state/rankings/. EIA reports gas production in 32 states and oil production in 31 states. Five states
(Texas, Alaska, California, North Dakota, and Oklahoma) accounted for 56% of crude oil production in 2011, and the
biggest gains were in North Dakota and Texas, due in large part to increased horizontal drilling and hydraulic
fracturing activity. EIA, Petroleum & Other Liquids, http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_m.htm.
25 The federal government, through the Bureau of Land Management (BLM), within the Department of the Interior, has
responsibility for overseeing oil and gas development on federally managed lands. For a discussion of federal
responsibilities for oil and gas production, see CRS Report R40806, Energy Projects on Federal Lands: Leasing and
Authorization, by Adam Vann.
26 States often enter into memoranda of understanding with BLM to coordinate administration and enforcement various
regulatory requirements on public lands within the state.
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Figure 6. Unconventional Shale Plays in the Lower 48 States
(with federal lands shown)

Source: CRS, compiled from U.S. Energy Information Administration sources.
Notes: No information reported on active shale plays in Alaska at the time of this report. Hawaii’s volcanic origin does not
support the geologic process leading to the deposition of shale.
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Hydraulic fracturing has been used for decades to stimulate increased production from existing
oil or gas wells. This technique, along with other well stimulation techniques, has been regulated
to varying degrees through state oil and gas codes. The detail and scope of applicable regulations
vary across the states, and some states have regulated “well stimulation” broadly without
addressing hydraulic “fracturing” explicitly.27 State regulators note that hydraulic fracturing
operations are regulated through provisions that address a variety of production activities,
including requirements regarding well construction (e.g., casing and cementing), well stimulation
(e.g., hydraulic fracturing), and well operation (e.g., pressure testing and blowout prevention).28
Nonetheless, state groundwater protection officials also have reported that development of shale
gas and tight oil using high-volume hydraulic fracturing, in combination with directional drilling,
has posed new challenges for the management and protection of water resources.29 Consequently,
many of the major producing states have revised or are reviewing and considering revising their
oil and gas laws and regulations to respond to these advances in oil and natural gas production
technologies and related changes in the industry.
When revising measures, states have added provisions that address hydraulic fracturing
specifically, such as requirements for disclosure of chemicals used in hydraulic fracturing.30 Other
common revisions include stricter requirements for well construction and operation (e.g.,
cementing, casing, and pressure testing) and wastewater storage and disposal.31 New York State
has imposed a de facto moratorium on high-volume hydraulic fracturing pending completion of
environmental and public health reviews and development of new rules. Similarly, Maryland
regulators, pursuant to executive order, are studying the risks associated with deep drilling and
hydraulic fracturing to identify new safeguards that may be needed in permits. North Carolina has
enacted legislation to permit hydraulic fracturing and horizontal drilling once rules are in place.32
The National Conference of State Legislatures (NCSL) reports that “state legislatures are actively
working to address public health and environmental concerns, while also taking advantage of the
economic potential offered by shale gas development.”33 During the 2011-2012 legislative

27 For state-specific information, see the Interstate Oil and Gas Compact Commission, Summary of State Statutes and
Regulations, available at http://www.iogcc.state.ok.us/state-statutes.
28 The state of California notes, for example, that requirements for protecting underground resources and well
construction standards “provide a first line of protection from potential damage caused by hydraulic fracturing.”
However, the state notes that “There is a gap between the requirements placed on oil and gas operators to safely
construct and maintain their wells, and the information they provide to the Division about hydraulic fracturing
operations and steps taken to protect resources and the environment. The Department’s pending regulatory process is
intended to close that gap.” California Department of Conservation, Hydraulic Fracturing in California,
http://www.conservation.ca.gov/dog/general_information/Pages/HydraulicFracturing.aspx.
29 See, for example, Ground Water Protection Council, U.S. Department of Energy, Office of Fossil Energy, National
Energy Technology Laboratory, State Oil and Natural Gas Regulations Designed to Protect Water Resources, 2009, p.
24, http://www.gwpc.org/sites/default/files/state_oil_and_gas_regulations_designed_to_protect_water_resources_0.pdf.
30 Alabama, Arkansas, Colorado, Montana, North Dakota, New Mexico, Ohio, Pennsylvania, Texas, Utah, West
Virginia, and Wyoming are among the states that have revised oil and gas rules in recent years.
31 For a comparison of state requirements for specific activities (e.g., wastewater disposal, chemical disclosure, and
cementing) see Resources for the Future, A Review of Shale Gas Regulations by State, Center for Energy Economics
and Policy, July 2012, http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx.
32 Vermont banned hydraulic fracturing; currently, EIA does not list Vermont as an oil or gas producing state. The New
Jersey legislature passed a ban on shale gas drilling; however, the governor vetoed the bill and imposed a one-year ban,
which has expired.
33 Jacquelyn Pless, Natural Gas Development and Hydraulic Fracturing: a Policymaker’s Guide, National Conference
(continued...)
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session, more than 170 bills were introduced in 29 states, and 14 of the states enacted legislation
related to natural gas development.34 The proposals covered a broad range of issues, and included
measures on (1) water resources protection (including casing, well spacing, setbacks, water
withdrawal, flowback, waste management requirements); (2) disclosure of hydraulic fracturing
fluids; (3) severance taxes; (4) hydraulic fracturing suspensions, moratoria, or studies to
investigate impacts; and (5) resolutions addressing hydraulic fracturing.35 Regarding disclosure of
chemicals used in hydraulic fracturing fluids, at least 35 bills were introduced in 14 states, and
legislation was enacted in three states (Indiana, Louisiana, and Pennsylvania). Through 2012, 16
states had adopted chemical disclosure requirements (see Figure 7).36
Figure 7. Hydraulic Fracturing Chemical Disclosure by State

Source: Ground Water Protection Council, Groundwater Communique, p. 2, January 2013.
Notes: FracFocus was established in 2011 by the Ground Water Protection Council and the
Interstate Oil and Gas Compact Commission (IOGCC). FracFocus is a public registry where oil and
gas companies may voluntarily identify chemicals used in hydraulic fracturing operations at specific
wells. Various states allow or require operators to meet state disclosure requirements by posting
information on the FracFocus website (http://www.fracfocus.org).

(...continued)
of State Legislatures, June 2012, p. 5.
34 Jacquelyn Pless, States Take the Lead on Regulating Hydraulic Fracturing: Overview of 2012 State Legislation,
National Conference of State Legislatures, March 2013, p. 1.
35 Ibid., pp. 2-3. North Dakota adopted a resolution urging Congress to limit EPA regulation of hydraulic fracturing.
South Dakota and Utah resolutions urge Congress to clearly delegate hydraulic fracturing responsibility to the states.
36 State requirements regarding disclosure of chemicals used in hydraulic fracturing are discussed in CRS Report
R42461, Hydraulic Fracturing: Chemical Disclosure Requirements, by Brandon J. Murrill and Adam Vann.
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Debate over the Federal Role
While states continue to adopt and implement varying frameworks and degrees of oversight and
regulation of unconventional gas and oil development, citizen and environmental groups, and
some Members of Congress, have pressed for greater environmental oversight of this industry
sector at the federal level. Some advocates of a larger federal role point to a wide range of
differences in substance, scope, and enforcement among state regulatory regimes, and assert that
a national framework is needed to ensure a consistent baseline level of environmental and human
health protection and transparency.37 Such advocates further argue that greater regulatory
uniformity would reduce risks and uncertainties to both the industry and the public.38 Others
argue against greater federal involvement, and point to established state oil and gas programs and
regulatory structures (which include a range of structures involving commissions, boards, or
divisions within natural resource agencies working to varying degrees with, or within, state
environmental agencies). In this view, experience lies with the states, and in addition to the
relative nimbleness of states to review and revise laws and rules, the states are better able to
consider regional differences in geology, topography, climate, and water resources.
In the 113th Congress, as in recent Congresses, the federal role in regulating oil and gas
production generally, and hydraulic fracturing specifically, has been the subject of hearings and
legislation.39 Some bills have proposed to broaden the federal role, while others have proposed to
further limit federal involvement in regulating oil and gas development.40 Such proposals have
been contentious, and Congress has not enacted such legislation since amending the Safe
Drinking Water Act (SDWA) in the Energy Policy Act (EPAct) of 2005 (P.L. 109-58) to explicitly
exclude from the SDWA definition of underground injection the injection of fluids (other than
diesel fuels) related to hydraulic fracturing operations.

37 See, for example, Matthew McFeeley, State Hydraulic Fracturing Disclosure Rules and Enforcement: A
Comparison, Natural Resources Defense Council, NRDC Issue Brief IB: 12-06-A, July 2012.
38 For further discussion, see Jeffrey Logan, Garvin Heath, and Elizabeth Paranhos et al., Natural Gas and the
Transformation of the U.S. Energy Sector: Electricity, Joint Institute for Strategic Energy Analysis, NREL/TP-6A50-
57702, Golden, CO, January 2013, http://www.nrel.gov/docs/fy13osti/55538.pdf.
39 The 113th Congress has explored the role of states and the federal government in oil and gas production, specifically,
and in environmental protection broadly. In February 2013, the House Committee on Energy and Commerce,
Subcommittee on Environment and the Economy, held a hearing, The Role of the States in Protecting the Environment
Under Current Law. The Senate Committee on Energy and Natural Resources has held a series of Natural Gas
Roundtables, including a May 2013 forum on Shale Development: Best Practices and Environmental Concerns.
40 Several relevant bills were offered in the 112th Congress, but none was enacted. H.R. 1084/S. 587 proposed repealing
the hydraulic fracturing exemption established in the Energy Policy Act (EPAct) of 2005, and amending the term
“underground injection” to include the injection of fluids used in hydraulic fracturing operations, thus authorizing EPA
to regulate this process under the SDWA. The bills also would have required disclosure of the chemicals used in the
fracturing process. In response to rules proposed by BLM in 2012, S. 2248/H.R. 4322 proposed that a state would have
sole authority to regulate hydraulic fracturing on federal lands within state boundaries; H.R. 3973 would have
prohibited the rule from having any effect on Indian lands; and H.R. 6235 would have barred a final rule for 10 years,
pending an impact study.
In the 113th Congress, hydraulic fracturing legislation has been introduced again. H.R. 1921, S. 1135, and Section 301
of S. 332 would (1) require disclosure of the chemicals used in the fracturing process, and (2) repeal the hydraulic
fracturing exemption established in EPAct 2005, and amend the term “underground injection” to include the injection
of fluids used in hydraulic fracturing operations, thus authorizing EPA to regulate this process under the SDWA. H.R.
2513/S. 1234 would grant states sole authority to regulate hydraulic fracturing on federal lands within the state, and
specify that hydraulic fracturing on federal land shall be subject to the law of the state in which the land is located. For
further discussion, see CRS Report R41760, Hydraulic Fracturing and Safe Drinking Water Act Regulatory Issues, by
Mary Tiemann and Adam Vann.
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Selected Federal Responses to Unconventional Resource Extraction
Provisions of several federal environmental laws and related regulations currently apply to certain
activities associated with oil and natural gas production. The Clean Water Act (CWA), for
example, prohibits the discharge of pollutants from point sources into surface waters without a
permit,41 and the Safe Drinking Water Act (SDWA) requires an Underground Injection Control
(UIC) permit for wastewater disposal through deep well injection.42 Additionally, a SDWA UIC
permit is required for the underground injection of fluids or propping agents pursuant to hydraulic
fracturing if the injected fracturing fluids contain diesel fuels.43 In 2012, EPA promulgated
regulations under the authority of the Clean Air Act that require reductions in emissions related to
oil and natural gas production, including emissions of volatile organic compounds (VOCs) from
hydraulically fractured natural gas wells.44
While congressional debate has continued over possible legislation, the Administration has been
pursuing additional initiatives to regulate or otherwise manage activities related to
unconventional oil and natural gas production, and hydraulic fracturing specifically. EPA has
been most active, and is considering actions under several pollution control statutes. Among these
efforts, EPA is working to (1) establish technology-based limits to control discharges of
wastewater from shale gas and coalbed methane extraction; (2) revise water quality criteria to
protect aquatic life from discharges of brine produced during oil and gas extraction; (3) subject
hydraulic fracturing chemicals to toxic substance reporting requirements, and (4) finalize
permitting guidance for the use of diesel in hydraulic fracturing operations. The Appendix of this
report provides a brief overview of selected federal environmental research and regulatory
activities related to the production of tight oil and gas resources. Several of these initiatives are
reviewed below.
EPA Study on Hydraulic Fracturing and Drinking Water
The 111th Congress, in 2009, urged EPA to conduct a study on the relationship between hydraulic
fracturing and drinking water to gain a better understanding of potential contamination risks.45 In

41 CWA Section 301 prohibits the discharge of pollutants into the nation’s waters except in compliance with the
provisions of the law, which include obtaining a discharge permit. 33 U.S.C. §1311. For information on applicable
CWA requirements, see Environmental Protection Agency, “Natural Gas Drilling in the Marcellus Shale, NPDES
Program Frequently Asked Questions,” March 16, 2011, http://www.epa.gov/npdes/pubs/hydrofracturing_faq.pdf.
42 The Safe Drinking Water Act of 1974 (P.L. 93-523) authorized the Underground Injection Control (UIC) program at
EPA. UIC provisions, as amended, are contained in SDWA Part C, §§1421-1426; 42 U.S.C. §§300h-300h-5.
43 EPAct 2005 (P.L. 109-58, §322), amended SDWA to exempt from the definition of underground injection the
injection of fluids or propping agents (other than diesel fuel) for hydraulic fracturing purposes.
44 The rules regulate VOC emissions from hydraulically fractured natural gas wells, compressors, pneumatic
controllers, storage vessels, and leaking components at onshore natural gas processing plants, as well as sulfur dioxide
emissions from onshore natural gas processing plants. The new standards require producers to capture about 90% of the
natural gas that escapes into the atmosphere as a result of production using hydraulic fracturing. For further discussion,
see CRS Report R42986, Air Quality Issues in Natural Gas Systems: In Brief, by Richard K. Lattanzio.
45 The Department of the Interior, Environment, and Related Agencies Appropriations Act, 2010 (P.L. 111-88, H.Rept.
111-316):
Hydraulic Fracturing Study.—The conferees urge the Agency to carry out a study on the
relationship between hydraulic fracturing and drinking water, using a credible approach that relies
on the best available science, as well as independent sources of information. The conferees expect
the study to be conducted through a transparent, peer-reviewed process that will ensure the validity
and accuracy of the data. The Agency shall consult with other Federal agencies as well as
(continued...)
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2011, EPA published a final study plan that identified research projects that would address the full
life cycle of water in hydraulic fracturing, from water acquisition to chemical mixing and
injection through wastewater treatment and/or disposal. The study is intended to (1) examine
conditions that may be associated with potential contamination of drinking water sources, and (2)
identify factors that may lead to human exposure and risks.46 As part of the study, EPA is
investigating five reported incidents of drinking water contamination in areas where hydraulic
fracturing has occurred. The purpose of the retrospective case studies is to determine the potential
relationship between reported impacts and hydraulic fracturing activities.47
In December 2012, EPA released a status report presenting the agency’s efforts through FY2012
on 18 research projects being conducted for the study.48 No data or findings were included. EPA
plans to issue individual reports and papers during 2013 and 2014, and to synthesize the results
from the research projects in a draft “report of results” by the end of 2014. EPA has designated
the report of results as a “highly influential scientific assessment” (HISA),49 which will undergo
peer review by EPA’s Science Advisory Board.50 In June 2013, the agency announced that the
final report will not be completed before 2016.
Multiagency Collaboration on Unconventional Oil and Gas Research
In March 2011, the White House issued a broad Blueprint for a Secure Energy Future, which
identifies the need to “expand safe and responsible domestic oil and gas development and
production.” Additionally, the President directed the Secretary of the Department of Energy
(DOE) to identify steps that could be taken to improve the safety and environmental performance
of shale gas production, and to develop consensus recommendations on practices to ensure the
protection of public health and the environment. 51
In response, the Secretary of Energy’s Advisory Board (SEAB) convened the Shale Gas
Production Subcommittee to evaluate hydraulic fracturing issues and make recommendations to
mitigate possible impacts of shale gas development. The final report included recommendations

(...continued)
appropriate State and interstate regulatory agencies in carrying out the study, which should be
prepared in accordance with the Agency’s quality assurance principles.
46 U.S. Environmental Protection Agency, Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking
Water Sources, Office of Research and Development, EPA/600/R-11/122, November 2011.
47 EPA is conducting retrospective case studies at five sites to develop information about the potential impacts of
hydraulic fracturing on drinking water resources under different circumstances. The case studies include (1) the Bakken
Shale in Dunn County, ND; (2) the Barnett Shale in Wise County, TX; (3) the Marcellus Shale in Bradford County,
PA; (4) the Marcellus Shale in Washington County, PA; and (5) coalbed methane in the Raton Basin, CO.
48 U.S. Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water
Resources: Progress Report, Office of Research and Development, EPA 601/R-12/011, December 2012,
http://www2.epa.gov/hfstudy/study.
49 Ibid., p. 6.
50 Because EPA has designated the “report of results” as a “highly influential scientific assessment,” the agency is to
follow the peer review planning requirements described in the Office of Management and Budget’s Information
Quality Bulletin for Peer Review, 2004. The Bulletin states that important scientific information must be peer reviewed
by qualified specialists before being disseminated by the federal government. The EPA Science Advisory Board is an
external federal advisory committee that conducts peer reviews of significant EPA research products and activities.
51 The White House, “Blueprint for a Secure Energy Future,” March 30, 2011, p. 13, http://www.whitehouse.gov/sites/
default/files/blueprint_secure_energy_future.pdf.
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for the states, federal government, and industry. The subcommittee recommended, among other
actions, that companies and regulators—to the extent that such actions had not been undertaken—
adopt further measures to protect water quality and to manage water use and wastewater disposal,
publicly report the composition of water and flow throughout the fracturing and cleanup process,
disclose fracturing fluid composition, and adopt best practices for well development and
construction (especially casing, cementing, and pressure management).52
In 2012, the President issued Executive Order (E.O.) 13605, Supporting Safe and Responsible
Development of Unconventional Domestic Natural Gas Resources, to coordinate the efforts of
federal agencies overseeing the development of unconventional domestic natural gas resources
and associated infrastructure. The order states that “Because efforts to promote safe, responsible,
and efficient development of unconventional domestic natural gas resources are underway at a
number of executive departments and agencies, close interagency coordination is important for
effective implementation of these programs and activities.”53
E.O. 13605 established an interagency working group to coordinate agency activities and to
engage in long-term planning and ensure coordination on research, resource assessment, and
infrastructure development. In April 2012, the lead agencies—DOE, EPA, and the Department of
the Interior (DOI/U.S. Geological Survey)—signed a Memorandum of Agreement to develop a
multiagency research plan “to address the highest priority research questions associated with
safely and prudently developing unconventional shale gas and tight oil reserves.”54
BLM Proposed Rule on Hydraulic Fracturing
While states have predominant regulatory authority for oil and gas development on state and
private lands, the federal government is responsible for managing oil and gas resources on federal
lands. However, some states require oil and gas operators on federal lands within their state to
comply with state rules, and consequently, the debate over the federal role in regulating
unconventional oil and gas production has extended to activities on federal lands.
The Bureau of Land Management (BLM), within the Department of the Interior, is the federal
agency responsible for overseeing oil, natural gas, and coal leasing and production on federal and
Indian lands, including split estate where the federal government owns the subsurface mineral
estate.55 BLM is tasked with leasing subsurface mineral rights not only on BLM-administered
land, but also for lands managed by other federal agencies, including the U.S. Forest Service.56
BLM oversees roughly 700 million subsurface acres of federal mineral estate and 56 million
subsurface acres of Indian mineral estate nationwide. BLM estimates that approximately 3,400

52 U.S. Department of Energy, the Secretary of Energy Advisory Board, Shale Gas Production Subcommittee, Second
Ninety Day Report, November 18, 2011, http://www.shalegas.energy.gov/.
53 Executive Order 13605, “Supporting Safe and Responsible Development of Unconventional Domestic Natural Gas
Resources,” (Washington: GPO, 2012), http://www.gpo.gov/fdsys/pkg/DCPD-201200269/pdf/DCPD-201200269.pdf.
54 The Memorandum of Agreement is available at the Administration website, Multi-Agency Collaboration on
Unconventional Oil and Gas Research, http://unconventional.energy.gov/.
55 Mineral Leasing Act of 1920, 30 U.S.C. §181.
56 For a discussion of federal lands leasing authorities and activities, see CRS Report R40806, Energy Projects on
Federal Lands: Leasing and Authorization, by Adam Vann.
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wells have been drilled annually in recent years on federal and Indian lands, and that hydraulic
fracturing is used to stimulate roughly 90% of these wells.57
In May 2012, BLM proposed revisions to its oil and natural gas development rules in response to
the increased use of hydraulic fracturing on federal and Indian lands.58 The proposed rule broadly
addressed “well stimulation, including hydraulic fracturing,” and would revise BLM oil and gas
production regulations that were promulgated in 1982 and last revised in 1988.59 In the 2012
Federal Register notice, BLM noted that the rule would modernize its management of well
stimulation activities, and stated that the “rule is necessary to provide useful information to the
public and to assure that hydraulic fracturing is conducted in a way that adequately protects the
environment.” 60 The preamble further noted that the proposed changes were partly in response to
recommendations made by the aforementioned SEAB Shale Gas Subcommittee.
BLM received more than 177,000 comments on the proposed rule, and in May 2013, BLM
published a Supplemental Notice of Proposed Rulemaking (SNPR) and Request for Comment.
BLM has requested comments on the multiple changes in the proposed rule, and provided 30 days
for public comment. (The comment period was extended for 60 days.)61
Despite changes, the 2012 proposed rule and the 2013 SNPR share overarching features that
reflect recommendations of the SEAB subcommittee report. Both proposals would (1) add
reporting and management requirements for water and other fluids used and produced in
hydraulic fracturing operations, with emphasis on managing fluids that flow back to the surface,
(2) require public disclosure of hydraulic fracturing chemicals, and (3) tighten well construction
and operation requirements to help ensure that wellbore integrity is maintained throughout the
hydraulic fracturing process. Among the changes to the 2012 proposed rule, the BLM 2013
Supplemental Notice would
• narrow the scope of the rule to apply only to hydraulic fracturing and refracturing
(the 2012 proposed rule would have applied to “well stimulation” activities
broadly);62
• provide opportunities for individual states or tribes to work with BLM to craft
variances for specific regulatory provisions that would allow compliance with
state or tribal requirements to be accepted as compliance with the BLM rule (if
the variance would meet or exceed the effectiveness of the rule provision it
would replace);63

57 77 Federal Register 27691-27693.
58 Department of the Interior, Bureau of Land Management, “Oil and Gas; Well Stimulation, Including Hydraulic
Fracturing, on Federal and Indian Lands,” 77 Federal Register 27691, May 11, 2012.
59 The proposed rule would amend existing BLM regulations at 43 C.F.R. Section 316.3-2.
60 77 Federal Register 27692-27693.
61 Department of the Interior, Bureau of Land Management, “Oil and Gas; Hydraulic Fracturing on Federal and Indian
Lands: Supplemental Notice of Proposed Rulemaking,” 78 Federal Register 31636, May 24, 2013.
62 SNPR, §3162.3-3(a) and §3160.0-5. This revision excludes acidizing, enhanced secondary and tertiary recovery so
that the rule would apply only to hydraulic fracturing and not to other “well stimulation” activities.
63 SNPR, §3162.3-3(k). In 2012, BLM proposed to implement on public lands “whichever rules, state or Federal, are
most protective of Federal lands and resources and the environment, consistent with longstanding practice and relevant
statutory authorities.” 77 Federal Register 72694.
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• allow operators to report hydraulic fracturing chemical information to BLM
either directly or through the FracFocus website or other specified database,64
and provide more detailed guidance on procedures for handling trade secret
claims;65
• clarify that mechanical integrity testing would be required for all fracturing and
refracturing operations;66
• require that all fracturing operations must isolate all usable water formations to
protect them from contamination, and allow operators to use an expanded set of
cement evaluation tools to help ensure that usable water zones have been isolated
and protected;67
• allow an advanced Notice of Intent Sundry to be submitted for a single well, or
group of wells with the same geological characteristics within a field where
hydraulic fracturing operations are likely to be successful using the same
design;68 and
• request comment on whether to require hydraulic fracturing wastewater to be
stored in tanks only, rather than in lined pits or tanks as proposed in 2012.
Coast Guard Regulation of Barge Shipments of Shale Gas Wastewater
The disposal of the large volumes of wastewater produced during shale gas extraction has posed
challenges for companies, state regulators, and communities—particularly in the Marcellus Shale
region. On-site disposal options are limited, and trucking wastewater to distant injection wells is a
costly endeavor. In 2012, the Coast Guard received two requests for approval for the bulk
shipment of wastewater resulting from shale gas extraction in the Marcellus Shale.
The Coast Guard regulates the shipment of hazardous materials on the nation’s rivers, and
classifies cargoes for bulk shipment.69 For a cargo that has not been classified in the regulations
or under prior policy, the ship owner must request Coast Guard approval prior to shipping the
cargo.70 The Coast Guard has identified concerns with shipment of shale gas wastewater in
barges. A key concern with the wastewater is “its potential for contamination with radioactive
isotopes such as radium-226 and -228. Radium is of particular concern because it is chemically
similar to calcium and so will easily form surface residues and may lead to radioactive surface
contamination of the barges.”71 Because of this concern, the Coast Guard currently does not allow

64 SNPR, §3162.3-3(i). Operators submitting information through FracFocus would be required to certify that the
information is correct and certify that the operator complied with applicable laws governing notice and permits.
65 SNPR, §3162.3-3(j)1-4. Modeled on Colorado rules, BLM would instruct operators not to disclose trade secret
information to BLM or on FracFocus. Operators would submit an affidavit stating that withheld information is entitled
to withholding. BLM would retain authority to require operators to submit claimed trade secret information.
66 SNPR, §3162.3-3(f).
67 SNPR, §3162.3-3(b) and §3162.3-3(d).
68 SNPR, §3162.3-3(d).
69 This action is based on authority in 46 U.S.C. Chapter 37—“Carriage of Liquid Bulk Dangerous Cargoes.”
Implementing regulations are published in 46 C.F.R. Subchapter O—“Certain Bulk Dangerous Cargoes.”
70 See 46 C.F.R. 153.900(c)-(d) or 46 C.F.R. 151.01-15.
71 U.S. Coast Guard, Marine Safety Engineering, Shale Gas Extraction Waste Water, Commercial Regulations and
Standards Directorate, Fall 2012, p. 5, http://www.uscg.mil/hq/cg5/cg52/docs/2012fall.pdf.
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barge shipment of shale gas extraction wastewater (SGEWW), and is developing a draft policy to
allow SGEWW to be transported for disposal. In March, the Coast Guard submitted to the Office
of Management and Budget for review a draft document, “Carriage of Conditionally Permitted
Shale Gas Extraction Waste Water in Bulk.”
Conclusion: Above- and Below-Ground Issues
a Concern
The prospect that by the end of the decade the United States could become a significant exporter
of natural gas and the world’s leading oil producer is a phenomenal change of circumstances from
just a few years ago. The technological advances that drove the changes in the United States have
also reversed the global perspective of dwindling oil and natural gas resources, and increased the
concern among many about greenhouse gas emissions. Other countries seek to emulate the U.S.
success, but have yet to do so. The U.S. oil and gas situation continues to be extremely dynamic,
and many questions remain about how the United States will develop its resources.
Many observers, including U.S. government officials, have only recently recognized the
tremendous resource size and the benefits that will accrue from developing the resources, as well
as the potential risks that may be associated with this development. Even though shale gas
development is still considered very new and tight oil production is even newer, the industry has
continued to improve its efficiency in extracting the resources, particularly of natural gas. As
more industry resources are shifted to tight oil plays, the natural gas sector has had to produce
more with less. Some in industry point out that at the beginning of shale gas development about
5% of the resource was able to be extracted; now it is closer to 20%. By comparison, the
extraction rate from conventional gas is between 30% and 60% of the resource.
Most concerns surrounding shale gas and tight oil development have involved environmental and
human health issues, and particularly concerns over the potential risks to groundwater and surface
water resources, and emissions of air pollutants. These concerns have led to calls for greater
federal oversight of oil and gas development. Although primary regulatory authority over oil and
natural gas exploration and production on state and private lands generally rests with the states,
provisions of several federal environmental laws currently apply to certain activities associated
with oil and natural gas exploration and production. Moreover, EPA is reviewing other statutory
authorities and pursuing new regulatory initiatives, and BLM has proposed revisions to its oil and
gas rules to specifically address hydraulic fracturing on federal and Indian lands. A broader
concern, particularly from environmental groups, is that the low price of natural gas is having
negative consequences for the development and growth in renewable energy sources and nuclear
power, potentially resulting in another generation of greenhouse-gas-producing energy sources.
The 113th Congress has held hearings, roundtables, and other discussions on issues associated
with unconventional oil and gas development broadly, and on the role of the states specifically.
Bills have been introduced to expand and also to constrain federal involvement in oil and gas
development involving hydraulic fracturing. In the meantime, the Administration is pursuing
actions to broaden federal oversight of this industry sector through administrative means.
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Appendix. Selected Federal Initiatives Related to
Unconventional Oil and Gas Production
Table A-1. Selected Federal Actions
Related to Unconventional Oil and Gas Production
(with emphasis on hydraulic fracturing)
Agency: Statute,
as Amended
Regulatory
Research
Status
EPA: Clean Air
Air emissions. In 2012, EPA issued regulations that
Rules
were
Act (CAA)
revised existing rules and promulgated new ones to
promulgated in August
regulate emissions of volatile organic compounds (VOCs),
2012 (77 Federal
sulfur dioxide, and hazardous air pol utants (HAPs) from
Register 49489);
many production and processing activities in the oil and
requirements phase in
gas sector that had not been subject previously to federal
through 2015.
regulation.

Particularly pertinent to shale gas production are the New

EPA has agreed to
Source Performance Standards (NSPS), which require
revisit elements of the
reductions in emissions of VOCs from hydraulically
NSPS, and on April 12,
fractured natural gas wells. The rules require operators to
2013, proposed
use reduced emissions completions (green completions)
revisions to the NSPS
for all hydraulically fractured natural gas wells beginning no
for storage tanks (78
later than January 2015.
Federal Register 22125).
Applying broadly across the sector, the NSPS require
reductions of VOCs from compressors, pneumatic
control ers, storage vessels, and other emission sources,
and also revise existing standards for sulfur dioxide
emissions from onshore natural gas processing plants, and
HAPs from dehydrators and storage tanks.a
EPA: Clean
Wastewater discharge. Produced water and flowback
Draft
criteria
Water Act
from hydraulic fracturing have high levels of total dissolved
document expected in
(CWA)
solids (TDS), largely chlorides, which can harm aquatic life
summer 2014.
and affect receiving water uses (such as fishing or
irrigation). EPA is updating its chloride water quality
criteria for protection of aquatic life.
CWA Section 304(a)(1) requires EPA to develop criteria
for water quality that reflect the latest scientific
understanding of the effects of pol utants on aquatic life
and human health. States use EPA-recommended criteria
to establish state water quality standards, which in turn
are used to develop enforceable discharge permits.
If reflected in state water quality standards, the revised
chloride water quality criteria could affect discharges of
produced water from extraction of conventional and
unconventional oil and gas.b
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Agency: Statute,
as Amended
Regulatory
Research
Status
EPA: CWA
Wastewater discharge. In 2011, EPA indicated that it

Notice of the final
was initiating two separate rulemakings to revise the
Effluent Guidelines
Effluent Limitations Guidelines and Standards (ELGs) for
Program Pan was
the Oil and Gas Extraction Point Source Category to
published in October
control discharges of wastewater from coalbed methane
2011 (76 Federal
(CBM) and shale gas extraction. Under CWA Section
Register 66286).
304(m), EPA sets technology-based effluent limitations for
industrial wastewater discharges. States incorporate these
Initially, EPA planned
limits into discharge permits. Shale and CBM wastewaters
to propose the CBM
often contain high levels of total dissolved solids (TDS—
rule in 2013, and the
i.e., salts), and shale gas wastewater may contain chemical
shale gas rule in 2014.
contaminants, naturally occurring radioactive materials
EPA has combined the
(NORM), and metals. Currently, shale gas wastewater may
rulemakings, and plans
not be discharged directly to surface waters, but CBM
to issue a proposed
wastewater is not subject to national discharge standards.
rule in April 2014 and
(CBM wastewater discharge permits are based on best
a final rule in
professional judgments of state or EPA permit writers.)
December 2015.
EPA is developing regulatory options to control direct
discharges of CBM wastewaters. Also, current ELGs lack
pretreatment standards for discharges of shale gas or
CBM wastewaters to publicly owned wastewater
treatment works (POTWs), which typically are not
designed to treat this wastewater. EPA is developing
national pretreatment standards that shale gas and CBM
wastewaters must meet before discharge to a POTW to
ensure that the facility can treat the wastewater
effectively.c
EPA:
Chemical disclosure. EPA is considering an October
Response
to
Emergency
2012 petition by nongovernmental organizations to subject
petitioners is expected
Planning and
the oil and natural gas extraction industry to Toxics
in spring 2014.
Community
Release Inventory (TRI) reporting under EPCRA. Section
Right-to-Know
313 of EPCRA requires owners or operators of certain
Act (EPCRA)
industrial facilities to report on releases of toxic
substances to the state and EPA. EPA and states are
required to make nonproprietary data publicly available
through the TRI website.
EPA: Safe
Diesel fuels. EPA issued draft UIC Program Guidance for

Draft guidance issued
Drinking Water
Permitting Hydraulic Fracturing with Diesel Fuels in response
in May 2012; final
Act (SDWA)
to the revised SDWA definition of “underground
guidance is expected
injection” in the Energy Policy Act (EPAct) of 2005 to
in 2013.
explicitly exclude the underground injection of fluids
(other than diesel fuels) used in hydraulic fracturing. The
draft guidance provides recommendations for EPA permit
writers to use in writing permits for hydraulic fracturing
operations using diesel fuels. The guidance will apply in
states where EPA implements the UIC program for oil and
natural gas related (Class II) injection wells. States are not
required to adopt the guidance, but may do so.d
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Agency: Statute,
as Amended
Regulatory
Research
Status
EPA: SDWA

Study. EPA is studying
Progress report issued
the relationship between
in December 2012.
hydraulic fracturing and
drinking water. Congress
During 2013 and 2014,
requested the study in
EPA plans to issue
EPA’s FY2010
individual reports and
appropriations act. EPA
papers.
designated the pending
A final report of
“report of results” as a
results is expected in
“highly influential
2016 (extended from
scientific assessment”
2014).
(HISA), which requires
peer review by qualified
specialists.
EPA: Toxic
Chemical reporting. EPA is developing an Advance

Initiated in January
Substances
Notice of Proposed Rulemaking (ANPRM) to get input on
2012.
Control Act
the design and scope of possible reporting requirements
(TSCA)
for hydraulic fracturing chemicals; EPA is considering
Publish ANPRM in
requiring information reporting under TSCA Section 8(a),
Federal Register:
and health and safety data reporting under Section 8(d).
expected February
2014.
EPA: Resource
Storage/disposal pits and ponds. EPA is considering

No schedule.
Conservation
developing guidance to address the design, operation,
and Recovery
maintenance, and closure of pits used to store hydraulic
Act (RCRA)
fracturing fluids for reuse or pending final disposal. These
(Also known as
wastes are exempt from regulation as a hazardous waste
the Solid Waste
under RCRA.
Disposal Act)
EPA: National
Oil and gas extraction. Every three years, EPA selects

This initiative runs
Enforcement
specific industries or pol ution sources to focus
through 2013.
Initiative
enforcement efforts on “serious pol ution problems” that
EPA believes can best be addressed by a national
enforcement team. The 2011-2013 initiatives include
Assuring Energy Extraction Activities Comply with
Environmental Laws focused on natural gas extraction and
production activities.
Department of
Hydraulic fracturing on public lands. BLM has

Proposed in May 2012;
the Interior,
proposed revisions to rules governing oil and natural gas
following extensive
Bureau of Land
production on federal and Indian lands. BLM proposes to
public comment, BLM
Management:
(1) require public disclosure of chemicals used in hydraulic
issued a Supplemental
Mineral Leasing
fracturing, (2) tighten regulations related to well-bore
Notice of Proposed
Act, Indian
integrity, and (3) add new reporting and
Rulemaking in May
Mineral Leasing
management/storage/disposal requirements for water used
2013.
Act
in hydraulic fracturing.
U.S. Coast
Wastewater shipment. The Coast Guard regulates the

In March, the Coast
Guard:
shipment of hazardous materials on the nation’s rivers.
Guard submitted to
46 U.S.C. Ch. 37 Because of the potential for shale gas wastewater in the
the Office of
Marcellus Shale region to contain radioactive materials
Management and
(especially radium, which can form surface residues and
Budget for review a
may lead to radioactive surface contamination of the
draft document,
barges), the Coast Guard currently does not allow barge
“Carriage of
shipment of shale gas extraction wastewater. The Coast
Conditional y
Guard’s Hazardous Materials Division is developing a
Permitted Shale Gas
policy to allow shale gas extraction wastewater to be
Extraction Waste
transported for disposal.
Water in Bulk.”
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An Overview of Unconventional Oil and Natural Gas: Resources and Federal Actions

Agency: Statute,
as Amended
Regulatory
Research
Status
DOE/EPA/DOI-

Federal research
Research plan
USGS:
coordination. In 2012,
expected to be
E.O. 13605
the agencies agreed,
available mid-2013.
through an MOU, to
develop a multiagency
research plan “to address
the highest priority
research questions
associated with safely and
prudently developing
unconventional shale gas
and tight oil resources.”
Source: Prepared by the Congressional Research Service.
Notes: This table presents selected Administration activities related to unconventional oil and natural gas
extraction. It excludes, for example, regional or site-specific research studies conducted by federal agencies.
More information on EPA initiatives to regulate oil and gas production and hydraulic fracturing is available at
EPA’s website, Natural Gas Extraction—Hydraulic Fracturing, http://www2.epa.gov/hydraulicfracturing.
a. These CAA rules, issued under court order, establish new air emissions standards for the “Crude Oil and
Natural Gas Production” and “Natural Gas Transmission and Storage” source categories. For details, see
CRS Report R42986, Air Quality Issues in Natural Gas Systems: In Brief, by Richard K. Lattanzio.
b. For more information, see the EPA Water Quality Criteria web page, http://water.epa.gov/scitech/
swguidance/standards/criteria/.
c. EPA explains that “[f]or direct dischargers of unconventional oil and gas wastewaters from onshore oil and
gas facilities—with the exception of coalbed methane—technology-based limitations are based on the
Effluent Limitations Guidelines (ELGs) for the Oil and Gas Extraction Category (40 CFR Part 435). Permits
for onshore oil and gas facilities must include the requirements in Part 435, including a ban on the discharge
of pollutants, except for wastewater that is of good enough quality for use in agricultural and wildlife
propagation for those onshore facilities located in the continental United States and west of the 98th
meridian. . Part 435 does not currently include categorical pretreatment standards for indirect discharges
to publicly owned treatment works (POTWs) for wells located onshore.” Source: U.S. Environmental
Protection Agency, Unconventional Extraction in the Oil and Gas Industry, http://water.epa.gov/scitech/
wastetech/guide/oilandgas/unconv.cfm.
d. EPA regulates the underground injection of fluids through SDWA §§1421-1426; 42 U.S.C. §§300h-300h-5. In
May 2012, EPA issued draft UIC Program Guidance for Permitting Hydraulic Fracturing with Diesel Fuels, which
generally follows EPA Class II underground injection well requirements (i.e., well construction standards;
mechanical integrity testing; operating, monitoring, and reporting requirements; and public notification and
financial responsibility requirements). The draft guidance provides recommendations for EPA permit writers
for tailoring requirements for hydraulic fracturing using diesel fuels. The guidance will apply in states where
EPA implements the UIC program for Class II wells (including Pennsylvania, New York, Michigan, Kentucky,
Tennessee, and Virginia).

Author Contact Information

Michael Ratner
Mary Tiemann
Specialist in Energy Policy
Specialist in Environmental Policy
mratner@crs.loc.gov, 7-9529
mtiemann@crs.loc.gov, 7-5937


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