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Hydraulic fracturing is a technique developed initially to
stimulate oil production from wells in declining oil reservoirs.
More recently, it has been used to initiate oil and gas production
in unconventional (i.e., low-permeability) reservoirs where these
resources were previously inaccessible. This process now is used in
more than 90% of new oil and gas production wells. Hydraulic
fracturing is done after a well is drilled and involves injecting
large volumes of water, sand (or other propping agent), and
specialized chemicals under enough pressure to fracture the
formations holding the oil or gas. The sand or other proppant holds
the fractures open to allow the oil or gas to flow freely out of
the formation and into a production well. Its application, along
with horizontal drilling, for production of natural gas (methane)
from coal beds, tight gas sands, and, more recently, from
unconventional shale formations, has resulted in the marked
expansion of estimated U.S. natural gas reserves in recent years.
Similarly, hydraulic fracturing is enabling the development of
unconventional domestic oil resources, such as the Bakken Formation
in North Dakota and Montana. However, the rapidly increasing and
geographically expanding use of fracturing, along with a growing
number of citizen complaints and state investigations of well water
contamination attributed to this practice, has led to calls for
greater state and/or federal environmental regulation and oversight
of this activity. Historically, the Environmental Protection Agency
(EPA) had not regulated the underground injection of fluids for
hydraulic fracturing of oil or gas production wells. In 1997, the
U.S. Court of Appeals for the 11th Circuit ruled that fracturing
for coalbed methane (CBM) production in Alabama constituted
underground injection and must be regulated under the Safe Drinking
Water Act (SDWA). This ruling led EPA to study the risk that
hydraulic fracturing for CBM production might pose to drinking
water sources. In 2004, EPA reported that the risk was small,
except where diesel was used, and that regulation was not needed.
However, to address regulatory uncertainty the ruling created, the
Energy Policy Act of 2005 (EPAct 2005) revised the SDWA term
"underground injection" to explicitly exclude the injection of
fluids and propping agents (except diesel fuel) used for hydraulic
fracturing purposes. Consequently, EPA currently lacks authority
under the SDWA to regulate hydraulic fracturing, except where
diesel fuel is used. However, as the use of this process has grown,
some in Congress would like to revisit this statutory exclusion.
Several relevant bills are pending. H.R. 1084 and S. 587 would
repeal the exemption for hydraulic fracturing operations
established in EPAct 2005, and amend the term "underground
injection" to include explicitly the injection of fluids used in
hydraulic fracturing operations, thus authorizing EPA to regulate
this process under the SDWA. EPA's FY2010 appropriations act urged
the agency to study the relationship between hydraulic fracturing
and drinking water quality. The interim report, expected in 2012,
may help inform Congress on whether federal action is needed.
Meanwhile, numerous states are reviewing or have revised their oil
and gas rules to address the increased use of hydraulic fracturing.
This report reviews past and proposed treatment of hydraulic
fracturing under the SDWA, the principal federal statute for
regulating the underground injection of fluids to protect
groundwater sources of drinking water. It reviews current SDWA
provisions for regulating underground injection activities, and
discusses some possible implications of, and issues associated
with, enactment of legislation authorizing EPA to regulate
hydraulic fracturing under this statute.
Congress is examining numerous energy sources to determine their
contribution to the nation's energy portfolio and the federal role
in supporting these sources. Hydropower, the use of flowing water
to produce electricity, is one such source. Conventional hydropower
accounted for approximately 6% of total U.S. net electricity
generation in 2010. Hydropower has advantages and disadvantages as
an energy source. Its advantages include its status as a
continuous, or baseload, power source that releases minimal air
pollutants during power generation relative to fossil fuels. Some
of its disadvantages, depending on the type of hydropower plant,
include high initial capital costs, ecosystem disruption, and
reduced generation during low water years and seasons. Hydropower
project ownership can be categorized as federal or nonfederal. The
bulk of federal projects are owned and managed by the Bureau of
Reclamation and the U.S. Army Corps of Engineers. Nonfederal
projects are licensed and overseen by the Federal Energy Regulatory
Commission (FERC). Considered by many to be an established energy
source, hydropower is not always discussed alongside clean or
renewable energy sources in the ongoing energy debate. However,
hydropower proponents argue that hydropower is cleaner than some
conventional energy sources, and point to recent findings that
additional hydropower capacity could help the United States reach
proposed energy, economic, and environmental goals. Others argue
that the expansion of hydropower in the form of numerous small
hydropower projects could have environmental impacts and regulatory
concerns similar to those of existing large projects. Congress
faces several issues as it determines how hydropower fits into a
changing energy and economic landscape. For example, existing large
hydropower infrastructure is aging; many of the nation's hydropower
generators and dams are over 30 years old. Proposed options to
address this concern include increasing federal funding, utilizing
alternative funding, privatizing federally owned dams, and
encouraging additional small-capacity generators, among other
options. Additionally, whether to significantly expand or encourage
expansion of hydropower is likely to require congressional input
due to the uncertainty surrounding the clean and renewable energy
portfolio within power markets. Potential expansion of hydropower
projects could take place by improving efficiency at existing
projects or by building new projects, or both. Congressional
support for this approach is evident in the House passage of the
Bureau of Reclamation Small Conduit Hydropower Development and
Rural Jobs Act of 2012 (H.R. 2842). Senate activity on this matter
includes the Hydropower Improvement Act of 2011 (S. 629), which
proposes to establish a grants program for increased hydropower
production, and to amend the Federal Power Act (FPA) to authorize
FERC to exempt electric power generation facilities on federal
lands from the act's requirements, among other things. Another
issue is the rate at which FERC issues licenses for nonfederal
projects, which is slower than some find ideal. The licensing
process can be delayed significantly as stakeholders and the
approximately dozen federal and state agencies involved give their
input. FERC responded by developing a more streamlined licensing
process in 2003. Still, some object to "mandatory conditions" that
federal agencies can place on new or renewed hydropower facilities.
The 112th Congress has introduced roughly 25 bills regarding
hydropower, a quarter of which are state- or site-specific
legislation.
The development of offshore oil, gas, and other mineral resources
in the United States is impacted by a number of interrelated legal
regimes, including international, federal, and state laws.
International law provides a framework for establishing national
ownership or control of offshore areas, and domestic federal law
mirrors and supplements these standards.
Hydraulic fracturing is a technique used to free oil and natural
gas trapped underground in low-permeability rock formations by
injecting a fluid under high pressure in order to crack the
formations. The composition of a fracturing fluid varies with the
nature of the formation, but typically contains mostly water; a
proppant to keep the fractures open, such as sand; and a small
percentage of chemical additives. Some of these additives may be
hazardous to health and the environment. The Shale Gas Production
Subcommittee of the Secretary of Energy Advisory Board (SEAB) has
recommended public disclosure, on a well-by-well basis, of all of
the chemical ingredients added to fracturing fluids, with some
protection for trade secrets. Currently, no such law or regulation
exists at the federal level. In his 2012 State of the Union
Address, President Barack Obama said he would obligate "all
companies that drill for gas on public lands to disclose the
chemicals they use," citing health and safety concerns. In May
2012, the Bureau of Land Management (BLM) published a proposed rule
that would require companies employing hydraulic fracturing on
lands managed by BLM to disclose the content of the fracturing
fluid. In addition, there have been legislative efforts in the
112th Congress. H.R. 1084 and S. 587, the Fracturing Responsibility
and Awareness of Chemicals Act (FRAC Act), would create more
broadly applicable disclosure requirements for parties engaged in
hydraulic fracturing. Chemical disclosure laws at the state level
vary widely. Of the 15 laws examined in this report, fewer than
half require direct public disclosure of chemical information by
mandating that parties post the information on the FracFocus
chemical disclosure website. The level of detail required to be
disclosed often depends on how states protect trade secrets, as
these protections may allow submitting parties to withhold
information from disclosure at their discretion or to submit fewer
details about proprietary chemicals, except, perhaps, in
emergencies. Even if a disclosure law does not protect information
from public disclosure, other state laws, such as an exemption in
an open records law, may do so. States also have varying laws
regarding the timing of these disclosure requirements. This report
provides an overview of current and proposed laws and regulations
at the state and federal levels that require the disclosure of the
chemicals added to the fluid used in hydraulic fracturing. Appendix
A provides a glossary of many of the terms used in this report.
Appendix B contains a table summarizing the fracturing chemical
disclosure requirements described in this report. For an overview
of the relationship between hydraulic fracturing and the Safe
Drinking Water Act (SDWA), see CRS Report R41760, CRS Report
R41760, Hydraulic Fracturing and Safe Drinking Water Act Issues, by
Mary Tiemann and Adam Vann.
In 2008, Canadian pipeline company TransCanada filed an application
with the U.S. Department of State to build the Keystone XL
pipeline, which would transport crude oil from the oil sands region
of Alberta, Canada, to refineries on the U.S. Gulf Coast. Keystone
XL would ultimately have the capacity to transport 830,000 barrels
per day, delivering crude oil to the market hub at Cushing, OK, and
further to points in Texas. TransCanada plans to build a pipeline
spur so that oil from the Bakken formation in Montana and North
Dakota can also be carried on Keystone XL. As a facility connecting
the United States with a foreign country, the pipeline requires a
Presidential Permit from the State Department. In evaluating such a
permit application, the department must determine whether it is in
the "national interest," considering the project's potential
effects on the environment, economy, energy security, foreign
policy, and other factors. Environmental impacts are considered
pursuant to the National Environmental Policy Act, and documented
by the State Department in an Environmental Impact Statement (EIS).
The final EIS was released for the Keystone XL pipeline permit
application in August 2011, after which a 90-day public review
period began to make the national interest determination. During
that time the State Department determined that more information was
needed to consider an alternative pipeline route avoiding the
environmentally sensitive Sand Hills region of Nebraska, an
extensive sand dune formation with highly porous soil and a shallow
depth to groundwater recharging the Ogallala aquifer. The Temporary
Payroll Tax Cut Continuation Act of 2011 (P.L. 112-78) required the
Secretary of State to approve or deny the project within 60 days.
On January 18, 2012, the State Department, with the President's
consent, denied the Keystone XL permit, citing insufficient time
under this deadline to properly assess the reconfigured project.
Subsequently, TransCanada announced that it would proceed with
development of the pipeline segment connecting Cushing, OK, to the
Gulf Coast as a stand-alone project not requiring a Presidential
Permit-a decision supported by the Obama administration. In April
2012, TransCanada submitted to Nebraska proposed pipeline routes
avoiding the Sand Hills. Subsequently, on May 4, 2012, TransCanada
submitted a new application for a Presidential Permit that includes
proposed new routes through Nebraska. With the new permit
application, the NEPA compliance process begins anew, although it
may draw from relevant existing analysis and documentation prepared
for the August 2011 final EIS. In the wake of the State
Department's denial of the Presidential Permit, Congress has
debated legislative options addressing the Keystone XL pipeline.
The Surface Transportation Extension Act of 2012, Part II (H.R.
4348) and the North American Energy Access Act (H.R. 3548) would
transfer the permitting authority for the Keystone XL pipeline
project to the Federal Energy Regulatory Commission, requiring FERC
to issue a permit within 30 days of enactment. The Keystone For a
Secure Tomorrow Act (H.R. 3811), the Grow America Act of 2012 (S.
2199), S. 2041 (a bill to approve the Keystone XL pipeline), the
EXPAND Act (H.R. 4301), and the Energizing America through
Employment Act (H.R. 4000) would immediately approve the original
permit application filed by TransCanada.
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