Key Environmental Issues in the Energy Policy Act of 2005 (P.L. 109-58, H.R. 6)
CRS Report for Congress
Key Environmental Issues in the Energy Policy
Act of 2005 (P.L. 109-58, H.R. 6)
Updated September 15, 2005
Brent D. Yacobucci, Coordinator
Resources, Science, and Industry Division
Claudia Copeland, M. Lynne Corn, Linda Luther,
James E. McCarthy, Kyna Powers, Fred Sissine,
and Mary Tiemann
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
Key Environmental Issues in the Energy Policy Act of
Debate over a national energy policy has been ongoing since the 107th Congress.
Both the 107th and 108th Congresses were unable to complete action on an omnibus
energy bill. The 109th Congress debated and passed H.R. 6, the Energy Policy Act
of 2005, which was signed by President Bush August 8, 2005 (P.L. 109-58).
The enacted law contains various provisions involving environmental protection
and regulation. This report briefly summarizes and discusses the background and
implications of key environmental provisions.
Title XV of P.L. 109-58 eliminates the reformulated gasoline (RFG) oxygen
standard, and in its place establishes a renewable fuel mandate for gasoline. Because
of related concerns over MTBE (a gasoline additive that competes with ethanol)
contamination, the enacted law modifies existing authority for cleanup of leaking
underground storage tanks, and authorizes funding for MTBE cleanup.
Title XVI establishes a program to promote the development and deployment
of low-carbon technologies both domestically and in developing countries.
Section 322 amends the Safe Drinking Water Act to exempt certain hydraulic
fracturing techniques from EPA regulation. Hydraulic fracturing involves the
underground injection of fluids into coal beds to enhance recovery of oil gas.
Section 323 gives permanent exemption from Clean Water Act stormwater
runoff rules for the construction of exploration and production facilities by oil and
gas companies and roads that service those sites.
Various sections in Titles VII, VIII, and XIII authorize R&D funding for
hydrogen, fuel cells, and alternative fuel vehicles or establish tax incentives for their
Section 241 gives applicants for hydroelectric licenses increased flexibility in
complying with conditions imposed by federal agencies. These conditions can
include water release controls to limit erosion, and protection of habitat.
Section 966 requires EPA to work with state and local officials in western
Michigan to determine ozone pollution and transport, and assess alternatives to
achieve compliance with air quality standards.
A variety of provisions are intended to expedite the process for completing or
complying with environmental requirements.
Not included in the enacted law are provisions on oil exploration in the Arctic
National Wildlife Refuge (ANWR) and a renewable portfolio standard.
This report will not be updated.
In troduction ......................................................1
MTBE and Ethanol: Fuels...........................................1
MTBE and Leaking Underground Storage Tanks.........................3
Oil and Gas Exploration and Production: Clean Water.....................5
Hydraulic Fracturing: Drinking Water Regulation........................7
Alternative Fuels and Vehicles: R&D and Incentives.....................10
Hydroelectric Power: Relicensing....................................11
Small Hydroelectric Power: Alaska...................................11
Air Quality: Ozone Nonattainment Area Deadlines......................12
Streamlining Environmental Requirements.............................12
Key Environmental Provisions not Included in P.L. 109-58................15
Oil Exploration in the Arctic National Wildlife Refuge (ANWR).......15
Renewable Portfolio Standard...................................15
Key Environmental Issues in the Energy
Policy Act of 2005 (P.L. 109-58, H.R. 6)
Over the past several Congresses, there have been ongoing efforts to developthth
comprehensive energy legislation. Energy bills were debated in the 107 and 108
Congresses, but final agreement was not reached in either Congress. The debate overth
omnibus energy legislation (H.R. 6) continued in the 109 Congress. On August 8,
The final version of H.R. 6 was enacted with some significant differences from
the House- and Senate-passed bills. In many cases, the enacted law and the House
and Senate versions treat environmental issues in a similar manner. However, there
are several environmental provisions that were addressed by an earlier version of the
bill but not the enacted law, or that were treated differently by different versions of
the bill. The H.R. 6 environmental provisions addressed in this report are the
following: limits on the use of MTBE; a renewable fuel mandate for gasoline;
stricter regulation of underground storage tanks; climate change; Clean Water Act
and Safe Drinking Water Act exemptions for oil and gas exploration and production
(related to stormwater runoff and hydraulic fracturing); incentives and R&D funding
for alternative fuels and vehicles; hydroelectric relicensing; ozone compliance
deadlines; streamlining of environmental regulations; and a renewable portfolio
A short discussion of each of the above provisions is included in this report. It
should be noted that not all environment-related provisions of H.R. 6 are discussed
in this report; it focuses on the major environmental issues in the debate.
MTBE and Ethanol: Fuels
Title XV of the enacted law contains several provisions addressing the gasoline
additives methyl tertiary butyl ether (MTBE) and ethanol.
Under the Clean Air Act Amendments of 1990, reformulated gasoline (RFG)
sold in many areas of the country with poor air quality was required to contain an
oxygenate (MTBE, ethanol, or other substances containing oxygen) to improve
combustion and reduce emissions of ozone-forming compounds and carbon
monoxide. A little more than 30% of the gasoline sold in the United States is RFG,
and a majority of RFG has contained MTBE. MTBE has been implicated in
numerous incidents of groundwater contamination, however, and 25 states have taken
steps to ban or regulate its use. The most significant of these bans (in California,
New York, and Connecticut) took effect at the end of 2003.1
The law repeals the Clean Air Act requirement to use oxygenates in RFG,
eliminating a key incentive for refiners to use MTBE.2 The repeal will take effect on
May 5, 2006 (270 days after enactment) — except in California, where it took effect
immediately upon enactment, August 8, 2005. Both the House and Senate versions
of H.R. 6 would also have banned the use of MTBE in motor vehicle fuel nationwide,
with some exceptions, in 2014 or 2009 respectively. The enacted version does not
contain a ban, however, effectively leaving the matter to the states to decide
In place of the oxygen requirement, P.L. 109-58 establishes a new requirement
that an increasing amount of gasoline contain renewable fuels such as ethanol. The
law requires that motor fuels contain at least 4.0 billion gallons of renewables in
2006, and requires an increase of 700 million gallons each year through 2011, before
reaching a level of 7.5 billion gallons in 2012. (In 2004, about 3.4 billion gallons of
ethanol were used in motor fuels.) The law also authorizes funds to clean up MTBE
contamination in groundwater, as discussed further in the next section below.
The enacted law also contains “anti-backsliding” provisions, to preserve the
reductions in emissions of toxic substances achieved by the RFG program. The
baseline emissions are set as the quantity emitted in 2001 and 2002.
The most controversial of the MTBE provisions was dropped in conference: a
“safe harbor” that the House bill would have provided for fuels containing MTBE.
The safe harbor from liability would have meant that such fuels could not be deemed
defective in design or manufacture by virtue of the fact that they contained MTBE.
The effect of this provision would have been to protect anyone in the product chain,
from manufacturers to retailers, from liability for cleanup of MTBE or for personal
injury or property damage based on the nature of the product. (Defective product
liability is a legal approach that has been used in California to require refiners to
shoulder liability for MTBE cleanup.) If liability for manufacturing and design
defects had been ruled out, plaintiffs would have needed to demonstrate negligence
in the handling of such fuels to establish liability — a more difficult legal standard
to meet. The House version of the bill had set a retroactive effective date of
September 5, 2003, for the safe harbor, rather than the date of enactment. This
effective date would have protected oil and chemical industry defendants from
1 For more details, see CRS Report RL32787, MTBE in Gasoline: Clean Air and Drinking
Water Issues, by James E. McCarthy and Mary Tiemann, and CRS Report RL32865,
Renewable Fuels and MTBE: A Comparison of Selected Provisions in the Energy Policy Act
of 2005 (H.R. 6), by Brent D. Yacobucci, Mary Tiemann, James E. McCarthy, and Aaron
2 However, MTBE is not only used as an oxygenate. MTBE is also used to extend gasoline
stocks and to increase octane.
defective product claims in about 150 lawsuits that were filed in 15 states after that
In addition to the House bill’s safe harbor for MTBE producers, both the House
and Senate versions of the bill contained a safe harbor for producers of renewable
fuels, such as ethanol. This provision was less controversial, since there was no
pending litigation that would have been affected, but it was also dropped from the
[This section prepared by James McCarthy, Specialist in Environmental Policy.]
MTBE and Leaking Underground Storage Tanks
As part of the legislative effort to address drinking water contamination by
MTBE, P.L. 109-58 (Title XV, Subtitle B) amends Subtitle I of the Solid Waste
Disposal Act (SWDA) to allow funds appropriated from the Leaking Underground
Storage Tank (LUST) Trust Fund to be used to enforce UST leak prevention
regulations, and authorizes appropriations from the fund specifically for remediating
gasoline tank leaks involving MTBE and other oxygenated fuels (including ethanol).
The subtitle adds several leak prevention provisions and new requirements for states,
EPA, and tank owners, and makes other changes to the underground storage tank
(UST) regulatory program.
To address a nationwide groundwater contamination problem caused by leaking
underground storage tanks, Congress created the UST leak prevention, detection, and
cleanup program in 1984 (Solid Waste Disposal Act, Subtitle I). In 1986, Congress
established the LUST Trust Fund to help EPA and states pay the costs of cleaning up
leaking petroleum USTs where owners fail to do so, and to oversee LUST cleanup
activities. While much progress has been made in the program, several issues remain.
A major issue has concerned the discovery of MTBE at thousands of LUST sites
across the country. This gasoline additive, which has been used to reduce air
pollution from auto emissions, is very water soluble. Once released, MTBE tends to
spread further than conventional gasoline; consequently, these leaks are more likely
to reach water supplies and are more costly to remediate.4 Another issue is that state
resources have not met the demands of overseeing the UST regulatory program,
which is aimed at preventing leaks. States have sought larger appropriations from
the trust fund to support the LUST program, and some have sought flexibility to use
LUST funds to enforce the UST leak prevention regulations.
3 For further discussion, see CRS Report RS21676, The Safe Harbor Provision for Methyl
Tertiary Butyl Ether (MTBE), by Aaron Flynn.
4 A June 2005 study by the American Water Works Association concludes that a “reasonable
best estimate” of the cost of addressing MTBE-contamination of public drinking water wells
is roughly $25 billion, with a range of $4 billion to $85 billion.
Source: American Water Works Association. A Review of Cost Estimates of MTBE
Contamination of Public Wells. June 21, 2005.
Subtitle B, which is based on the House bill, adds several leak prevention
provisions to the UST program. It requires EPA or states to conduct compliance
inspections of USTs every three years; prohibits fuel delivery to ineligible tanks,
directs states to develop training requirements for persons responsible for operating
and maintaining tanks and responding to spills; clarifies and expands UST
compliance requirements for federal facilities; and requires EPA, with Indian tribes,
to develop and implement a strategy to address releases on tribal lands. The subtitle
further requires that, when determining the portion of cleanup costs to recover from
a tank owner or operator, EPA or a state must consider the owner or operator’s ability
to pay for cleanup and still maintain basic business operations. It also allows EPA
and states to use LUST funds to conduct inspections and enforce UST release
prevention and detection requirements.
To further protect groundwater, the enacted law requires states to do one of the
following: (1) require that new tanks are secondarily contained and monitored for
leaks if the tank is within 1,000 feet of a community water system or potable well;
or (2) require that UST manufacturers and installers maintain evidence of financial
responsibility to pay for corrective actions, and require that persons installing UST
systems are certified or licensed, or that their UST system installation is certified by
a professional engineer or inspected and approved by the state, or is compliant with
a code of practice or other method that is no less protective of human health and the
This subtitle authorizes appropriations from the LUST Trust Fund, for each of
FY2005 through FY2009, of $200 million for cleaning up leaks from petroleum
tanks generally, and another $200 million for responding to tank leaks involving
MTBE or other oxygenated fuel additives (e.g., ethanol). It also authorizes to be
appropriated from the trust fund, for each of FY2005 through FY2009, $155 million
for EPA and states to administer the LUST cleanup program and to enforce the UST
leak prevention requirements. From general revenues, it authorizes $50 million to be
appropriated for each of FY2005 through FY2009 for EPA and states to administer
the remainder of Subtitle I.
[This section prepared by Mary Tiemann, Specialist in Environmental Policy.]5
Title XVI of P.L. 109-58 establishes a voluntary national program designed to
accelerate demonstration and deployment of less-carbon-intensive technology to
encourage voluntary reductions in greenhouse gases. The sections of this title
attempt to support actions focused on reducing U.S. carbon intensity (the ratio of
greenhouse gas emissions per unit of gross domestic product). The enacted law does
not establish a requirement to reduce emissions. This title also establishes a program
5 For more information on the LUST program, see CRS Report RS21201, Leaking
Underground Storage Tanks: Program Status and Issues, by Mary Tiemann. For a
discussion of MTBE issues, see CRS Report RL32787, MTBE in Gasoline: Clean Air and
Drinking Water Issues, by James McCarthy and Mary Tiemann.
to encourage exports of carbon intensity-reducing technologies to developing
countries. Title XVI contains provisions similar to those added to the bill on the
Senate floor by amendments that incorporated language found in S. 883 and S. 887.
The House bill did not expressly address climate change issues.
Included in the Senate bill, but dropped in conference was a Sense of the Senate
resolution that human activities are a substantial cause of greenhouse gas
accumulation in the atmosphere, causing average temperatures to rise. Further, the
resolution stated that “Congress should enact a comprehensive and effective national
program of mandatory market-based limits and incentives on emissions of
greenhouse gases that slow, stop, and reverse the growth of such emissions at a rate
and in a manner that — (1) will not significantly harm the United States economy;
and (2) will encourage comparable action by other nations that are major trading
partners and key contributors to global emissions.” This is the first Sense of the
Senate resolution on climate change since S.Res. 98 was passed in 1997, which
voiced concern over the economic effects of emissions limits and the sense that
developing countries must participate in meaningful action to control emissions.
The Senate also debated whether to adopt S.Amdt. 826, which contained
language similar to S. 1151, the Climate Stewardship and Innovation Act of 2005.
This amendment would have established a mandatory cap-and-trade system to limit
greenhouse gas emissions from covered entities to year 2000 levels by 2010. This
amendment was rejected on a 38-60 vote.
Greenhouse gas emissions and climate change have been an issue of
congressional interest for over two decades. In 1993, the United States ratified the
United Nations’ Framework Convention on Climate Change (UNFCCC), which
called on industrialized countries to take the lead in making voluntary efforts to
reduce greenhouse gases. Subsequently, a variety of voluntary and regulatory actions
have been proposed or undertaken in the United States, including monitoring of
utility carbon dioxide emissions, improved appliance efficiency, and incentives for
developing renewable energy sources. Many of these policies were enacted as part
of the Energy Policy Act of 1992. However, debate over the causes and effects of
climate change, as well as the potential costs of any greenhouse gas reduction
strategy, curtailed legislative action concerning the issue. In 2001, President George
W. Bush rejected the Kyoto Protocol to the UNFCCC, which called for legally
binding commitments by developed countries to reduce their greenhouse gas
emissions. Instead, the Bush Administration has focused on voluntary actions to
reduce the greenhouse gas intensity of the U.S. economy.
[This section prepared by Brent Yacobucci, Specialist in Energy Policy.]
Oil and Gas Exploration and Production:
Section 323 of P.L. 109-58 gives a permanent exemption from Clean Water Act
(CWA) stormwater runoff rules for the construction of exploration and production
facilities by oil and gas companies and the roads that service those sites. Currently
under the CWA, the operation of facilities involved in oil and gas exploration,
production, processing, transmission, or treatment generally is exempt from
stormwater runoff regulations (so long as the runoff is uncontaminated by pollutants),
but the construction of these facilities is not. Section 323 modifies the CWA to
specifically include construction activities in the types of oil and gas facilities that are
covered by the law’s statutory exemption from stormwater rules.
The issue arises from stormwater permitting rules for small construction sites
and municipal separate storm sewer systems that were issued by EPA in 1999 and
became effective March 10, 2003. Those rules, known as Phase II of the CWA
stormwater program, require most small construction sites disturbing one to five
acres and municipal separate storm sewer systems serving populations of up to
prevention plans describing practices for curbing sediment and other pollutants from
being washed by stormwater runoff into local water bodies. Phase I of the
stormwater program required construction sites larger than five acres (including oil
and gas facilities) and larger municipal separate storm sewer systems to obtain
discharge permits beginning in 1991.
As the March 2003 Phase II compliance deadline approached, EPA authorized
a two-year extension of the rules for small oil and gas construction sites to allow the
agency to assess the economic impact on that industry. EPA had initially assumed
that most oil and gas facilities would be smaller than one acre in size and thus
excluded from the Phase II rules, but newer data developed for the Department of
Energy indicate that up to 30,000 new sites per year would be of sizes subject to the
rules.6 In a February 2005 report, GAO reported that the actual number of oil and
gas construction activities that could be affected is uncertain, and the financial and
environmental implications (including additional environmental protections) are
difficult to quantify.7 In March 2005, EPA extended the exemption until June 2006
and said it would propose a specific rule for small oil and gas construction sites by
September 2005, and issue a final rule in June 2006.
Section 323 of the law makes EPA’s regulatory delay permanent and makes it
applicable to construction activities at all oil and gas development and production
sites, regardless of size, including those covered by Phase I rules. Industry had
argued that the stormwater rule creates time-consuming permitting requirements,
even though the short construction period for drilling sites carries little potential for
stormwater runoff pollution. Supporters said the amendment was intended to clarify
existing CWA language. Opponents argued that there is no evidence that
construction at oil and gas sites causes less pollution than other construction
activities, which are regulated under EPA’s stormwater program. The legislative
provision originated in House-passed H.R. 6; the Senate bill did not include similar
6 Memorandum from Advanced Resources International, Inc., to U.S. Department of
Energy/Office of Fossil Energy, Estimated Economic Impacts of Proposed Storm Water
Discharge Requirements on the Oil and Natural Gas Industry, December 7, 2004.
7 U.S. General Accountability Office. Storm Water Pollution, Information Needed on the
Implications of Permitting Oil and Gas Construction Activities. GAO-05-240, February
language. As a result of the provision in the enacted law, which is intended to
exempt from the CWA all uncontaminated stormwater discharges that occur while
setting up drilling operations, EPA is expected to modify the rule that it said would
be proposed in September 2005, developing a new rule for discharges of
contaminated stormwater from oil and gas operations.
[This section prepared by Claudia Copeland, Specialist in Resources and
Hydraulic Fracturing: Drinking Water Regulation
Section 322 of P.L. 109-58 amends the Safe Drinking Water Act (SDWA),
Section 1421(d), to specify that the definition of “underground injection” excludes
the injection of fluids or propping agents (other than diesel fuels) used in hydraulic
fracturing operations related to oil, gas, or geothermal production activities. This
language prevents EPA from regulating the underground injection of fluids for
hydraulic fracturing purposes, thus removing EPA’s existing authority to do so under
SDWA, as needed to protect sources of drinking water. It also would effectively
overturn two court rulings. The provision is based on the House bill; conferees
added the references to diesel fuel and geothermal production activities. The Senate8
bill contained no similar provision.
The SDWA requires controls on the underground injection of fluids to protect
underground sources of drinking water. EPA had not considered hydraulic fracturing
to fall within the regulatory definition of underground injection until 1997, when the
U.S. Court of Appeals for the 11th Circuit ruled that the hydraulic fracturing of coal
beds for methane production constitutes underground injection and must be
regulated. (This decision applied only to Alabama (LEAF v. EPA, 118 F. 3d 1467).)9
While the practice of hydraulic fracturing has been used in the recovery of
conventional oil and gas since the 1950s, this practice has been applied for recovery
8 The Senate version of H.R. 6 in the 108th Congress had called for EPA to prepare a study
of the known and potential effects of hydraulic fracturing on underground sources of
drinking water, and for the National Academy of Sciences to provide for an independent
review of the study. th
As passed in the 109 Congress, P.L. 109-58, Section 1811, calls for the National Academy
of Sciences to conduct a study on the effect of coalbed natural gas production on surface and
ground water resources, including drinking water, in Montana, Wyoming, Colorado, New
Mexico, North Dakota, and Utah.
9 In 2000, a second suit was filed against EPA for approving Alabama’s revised UIC
program when it contained several alleged deficiencies. (Legal Environmental Assistanceth
Foundation, Inc. v. U.S. EPA., 276 F.3d 1253 (11 Cir. 2001)). The U.S. Court of Appealsth
for the 11 Circuit directed EPA to require Alabama to regulate hydraulic fracturing under
SDWA. The court determined that EPA could regulate hydraulic fracturing under SDWA’s
more flexible state oil and gas provisions in Section 1425, rather than the more stringent
underground injection control requirements of Section 1422.
of coalbed methane primarily since the mid-1990s.10 Hydraulic fracturing involves
the high-pressure injection of fluids into coal beds to enhance the recovery of oil and
natural gas from underground formations. Water-based fluids are used commonly
as fracturing fluids, but the industry reports that diesel fuel often is used; also,
methanol and various toxic chemicals are used in fracturing fluids.11 The volume of
fracturing and stimulation fluids injected into each well for coalbed fracturing is
estimated to range from 55,000 gallons to 350,000 gallons.12
A growing concern, reported by EPA, is that, “in many coalbed methane-
producing regions, the target coalbeds occur within USDWs [underground sources
of drinking water], and the fracturing process injects stimulation fluids directly into
the USDWs.”13 EPA has determined that the use of diesel fuel as a fracturing fluid
introduces benzene and other toxic and carcinogenic substances directly into
underground sources of drinking water.14 Also, because the process fractures rock,
fracturing can create new pathways for natural gas (primarily methane) and other
contaminants to enter drinking water aquifers. As the number of coalbed methane
(CBM) wells and the use of hydraulic fracturing have increased rapidly in recent
years, so has concern over the potential impact on water resources, particularly in the
water-scarce West, and very few studies have been done to evaluate these impacts.
In January 2003, EPA’s National Drinking Water Advisory Council (established
by Congress under SDWA) submitted to the EPA Administrator a report on hydraulic
fracturing, underground injection control, and coalbed methane production and its
impacts on water quality and water resources. The council noted several concerns,
including the use of diesel fuel and toxic additives in the hydraulic fracturing process,
10 Demand for natural gas, new technologies, federal tax credits, and the identification of
shallow coal formations have led to a dramatic growth in the coalbed methane development
industry. For example, the U.S. Geological Survey reports that the number of CBM wells
in the Powder River Basin in Wyoming and Montana increased from 110 wells in May 1994
to 5,446 wells in May 2001. (Testimony of Dr. Gene Whitney, Supervisory Geologist, U.S.
Geological Survey, before the Committee on Resources, Subcommittee on Energy and
Mineral Resources, U.S. House of Representatives, hearing on The Orderly Development
of Coalbed Methane Resources from Public Lands, Sept. 6, 2001). In 2002, the Bureau of
Land Management estimated that another 51,000 wells were planned for Wyoming and
11 Environmental Protection Agency, Evaluation of Impacts to Underground Sources of
Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs, Washington,
D.C., June 2004, pp. 4-3 - 4-4.
12 Ibid., p. 3-11.
13 Ibid, pp. 1-6. According to EPA, hydraulic fracturing of oil and gas found in conventional
geologic traps is well established; however, hydraulic fracturing of coal beds is relatively
new. Conventional sites are usually more than 1000 feet deep, and typically involve highly
saline ground water that is unsuitable for drinking water. In contrast, geologic formations
that contain coal bed methane can be near the surface where ground water may be used as
a source of drinking water supplies.
14 Ibid., pp. 4-9 - 4-10.
and the potential impact of coalbed methane development on local underground
water resources and on the quality of surface waters.15
The Advisory Council recommended that EPA work through regulatory or
voluntary means to eliminate the use of diesel fuel and related additives in fracturing
fluids that are injected into formations containing sources of drinking water. In 2003,
EPA entered into an agreement with three companies that provide most hydraulic
fracturing services (BJ Services, Halliburton Energy Services, and Schlumberger
Technology Corporation).16 Under this voluntary agreement, the firms conditionally
agree to remove diesel fuel from CBM fluids injected directly into drinking water
sources, if cost-effective alternatives are available. EPA has not sought to limit other
toxic components in fracturing fluids, and other companies did not agree to cease
injecting diesel fuel into drinking water sources.
The National Drinking Water Advisory Council further recommended that EPA
continue to study the extent and nature of public health and environmental problems
that could occur as a result of hydraulic fracturing for coalbed methane production,
and defend its authority to implement the UIC program in a manner that protects
groundwater resources from contamination. However, oil and gas industry
representatives argue that regulation is unneeded and would slow natural gas
In response to the 1997 court decision and citizen complaints about water
contamination attributed to hydraulic fracturing, EPA began to study the impacts of
hydraulic fracturing practices used in CBM production on drinking water sources,
and to determine whether further regulation was needed. In 2002, EPA issued a draft
report that identified alleged water quality and quantity problems attributed to
hydraulic fracturing in Alabama, New Mexico, Colorado, Wyoming, Montana,
Virginia, and West Virginia.17 Based on the preliminary results of the study, EPA
tentatively concluded that the potential threats to public health posed by hydraulic
fracturing of coalbed methane wells appeared to be small.
In 2004, EPA issued a final report, based primarily on a review of the available
literature, and concluded that the injection of hydraulic fracturing fluids into CBM
wells poses little threat to underground sources of drinking water and requires no
further study; however, EPA noted that very little documented research has been
15 National Drinking Water Advisory Council, Report on Hydraulic Fracturing and
Underground Injection Control and Coalbed Methane by the National Drinking Water
Advisory Council Resulting from a Conference Call Meeting Held December 12, 2002,
16 Memorandum of Agreement Between the United States Environmental Protection Agency
and BJ Services Company, Halliburton Energy Services, Inc., and Schlumberger Technology
Corporation, Dec. 12, 2003.
17 U.S. Environmental Protection Agency. Draft Evaluation of Impacts to Underground
Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. EPA
done on the environmental impacts of injecting fracturing fluids.18 EPA also noted
that estimating the concentration of diesel fuel components and other fracturing
fluids beyond the point of injection was beyond the scope of its study.19 The report
has been criticized by some, including EPA professional staff, and the EPA Inspector
General has been asked to review a whistle-blower’s assertions that EPA’s findings
are scientifically unfounded.20 (For more information, see CRS Report RL32262,
Selected Legal and Policy Issues Related to Coalbed Methane Development, by
Aaron M. Flynn.)
[This section prepared by Mary Tiemann, Specialist in Environmental Policy.]
Alternative Fuels and Vehicles: R&D and Incentives
P.L. 109-58 contains provisions on hydrogen and fuel cell research and
development, as one strategy to promote expansion of alternative fuels and advanced
technology vehicles and reduce dependence on foreign oil. Title VIII authorizes $3.3
billion for hydrogen fuel and fuel cell R&D over the course of FY2006-FY2010. The
House version would have authorized $4.0 billion over the same time frame; the
Senate bill would have authorized $3.2 billion. Further, the enacted law authorizes
funding for the development of a nuclear plant to produce electricity and hydrogen.
Title VI, Subsection C authorizes $1.25 billion over ten years for this project. Since
FY2003, funding for hydrogen and fuel cell R&D through the Department of Energy
has been steadily increasing, as part of the FreedomCAR and Hydrogen Fuel
initiatives. For FY2004 through FY2008, the Bush Administration is seeking a total
of $1.8 billion for the initiatives. If appropriated, the above authorizations would
represent a significant increase in hydrogen research funding.
P.L. 109-58 also authorizes research on vehicle energy efficiency; establishes
a program to promote the domestic production and sale of hybrid and advanced diesel
vehicles; and establishes tax credits for the purchase of alternative fuel, fuel cell,
hybrid, and advanced lean-burn engine vehicles. The enacted law also provides grant
funding for states, localities, school districts, and private cargo carriers to replace
existing diesel engines and vehicles with alternative fuel, fuel cell, and advanced
diesel technologies, or to retrofit emissions systems on existing engines.
[This section prepared by Brent Yacobucci, Specialist in Energy Policy.]21
18 Ibid. p. 4-1.
19 Ibid. p. 4-12.
20 Letter (and technical analysis) to Sens. Wayne Allard and Ben Nighthorse Campbell and
Rep. Diana DeGette from Weston Wilson, U.S. Environmental Protection Agency, Region
21 For more information, see CRS Issue Brief IB10128, Alternative Fuels and Advanced
Technology Vehicles: Issues in Congress.
Hydroelectric Power: Relicensing
Section 241 of P.L. 109-58 will give applicants for hydroelectric licenses
increased flexibility in complying with conditions imposed by federal agencies.
Currently, the Federal Power Act (16 U.S.C. Section 791 et al.) gives certain federal
agencies (conditioning agencies) the authority to attach conditions to Federal Energy
Regulatory Commission (FERC) licenses. For example, federal agencies may require
applicants to build passageways through which fish can travel around the dam,
schedule periodic water releases for recreation, release minimum flows of water for
fish migration, control water release rates to reduce erosion, or limit reservoir
fluctuations to protect the reservoir’s shoreline habitat. Once an agency issues such
conditions, FERC must include them in its license. While these conditions often
generate environmental or recreational benefits, they may also require construction
expenditures and may increase power generation costs by reducing operational
The enacted law allows entities to propose alternative license conditions and
will require federal agencies to consider the alternatives proposed by license
applicants and other parties to the license proceeding. The law also requires an
agency to accept a proposed alternative, if it finds that the alternative (1) provides for
the adequate protection and utilization of the federal reservation, or is no less
protective of the fish resource than the fishway initially prescribed, and (2) costs
significantly less to implement than the original condition, and/or will improve
operation of the project for electricity production. Agencies that are issuing
conditions will also be required to provide FERC with a written statement
demonstrating that the relevant Secretary gave “equal consideration” to the effects
of the conditions on factors such as energy supply, flood control, navigation, water
supply, and air quality. It remains to be seen how this equal consideration clause will
affect agencies’ resources and whether it will alter their responsibilities concerning
the resources under their jurisdiction.
[This section prepared by Kyna Powers, Analyst in Energy and Environmental
Small Hydroelectric Power: Alaska
P.L. 109-58, amends the conditions pursuant to which the State of Alaska may
regulate its small hydroelectric dams. Under current law (16 U.S.C. Section 823c),
Alaska’s regulatory program must meet certain conditions for FERC to grant it
jurisdiction. For example, the program must require “conditions for the protection,
mitigation, and enhancement of fish and wildlife based on recommendation received
pursuant to the Fish and Wildlife Coordination Act” (16 U.S.C. Section 823c
(a)(3)(c)). Under P.L. 109-58, the State of Alaska may decide against issuing such
conditions if it finds that the recommendation will not allow it to (1) protect the
public interest, multiple purposes, and the environment to the same extent provided
through FERC licensing and regulation, or (2) give equal consideration to the
purposes of energy conservation, fish and wildlife, recreation, the interests of Alaska
Natives, and other beneficial public uses (i.e., irrigation, flood control, water supply
Pursuant to a November 2000 amendment to the Federal Power Act (16 U.S.C.
823c), the State of Alaska is finalizing regulations to the state’s small hydroelectric
[This section prepared by Kyna Powers, Analyst in Energy and Environmental
Air Quality: Ozone Nonattainment Area Deadlines
Section 1443 of the House version of H.R. 6 would have amended the Clean Air
Act to extend deadlines for areas that have not attained the ozone air quality standard
if upwind areas “significantly contribute” to their nonattainment. Under the 1990
Clean Air Act Amendments, ozone nonattainment areas with higher concentrations
of the pollutant were given more time to reach attainment, but in return for the
additional time, they were required to implement more stringent controls on
emissions. Failure to reach attainment by the specified deadline was to result in
reclassification of an area to a higher category and the imposition of more stringent
controls. Section 1443 would have amended this system to extend deadlines (without
requiring more stringent controls) in areas affected by upwind sources of pollution.
There was no comparable provision in the Senate bill, and the conferees did not
include the House provision in the enacted law.
The enacted version does establish a demonstration project, however, to address
the issue of upwind pollution. In Section 996, the enacted law requires EPA to work
with State and local officials in a multi-county Western Michigan project area to
determine the extent of ozone and ozone precursor transport, to assess alternatives
to achieve compliance with the 8-hour ozone standard apart from local controls, and
to determine the timeframe in which such compliance could take place. (Western
Michigan is believed to be affected by pollution originating in the Chicago and
Milwaukee metropolitan areas.) EPA is prohibited from imposing requirements or
sanctions that might otherwise apply during the demonstration project.
[This section prepared by James McCarthy, Specialist in Environmental22
Streamlining Environmental Requirements
P.L. 109-58 includes a variety of provisions, applicable to several categories of
energy projects, that are intended to expedite the process for completing or
complying with environmental requirements. Commonly referred to as
“streamlining,” these provisions are most often specified for complex federal actions
such as oil and gas development projects that may trigger compliance with literally
22 For more information, see CRS Report RS21611, Ozone and Particulate Air Quality:
Should Deadlines for Attainment Be Extended?
dozens of federal, state, tribal, and local environmental statutory and regulatory
requirements. Such projects, in turn, may require the participation or input of
possibly dozens of agencies. Proponents of streamlining provisions indicate that they
are intended to better coordinate the interagency consultations necessary to complete
applicable environmental requirements.
The environmental streamlining provisions in the enacted law primarily specify
procedures intended to expedite the process for obtaining federal authorizations (e.g.,
permits, special use authorizations, or approvals) or to comply with the National
Environmental Policy Act of 1969 (NEPA, P.L. 91-190). Federal authorizations for
a given category of energy projects may be required under any of a number of local,
state, tribal, or federal requirements (e.g., permitting requirements under the Clean
Air Act or the Clean Water Act). Some element of NEPA compliance is required of
all federal actions potentially impacting the environment.
NEPA requires federal agencies to consider the environmental impacts of their
proposed actions before final decisions are made. For proposed federal actions
significantly affecting the quality of the environment, NEPA requires federal
agencies to provide a detailed statement of environmental impacts (referred to as an
environmental impact statement (EIS)). Projects for which it is not initially clear
whether impacts will be significant require the preparation of an Environmental
Assessment (EA) to determine the level of significance of the action’s impacts.
Projects that do not individually or cumulatively have a significant social, economic,
or environmental effect, and have been determined from past experience to have no
significant impact, are categorically excluded from the requirement to prepare and
EIS or an EA. Streamlining provisions regarding NEPA often propose legislative or
administrative procedures intended to expedite the process for completing the
necessary NEPA documentation.
Methods of expediting federal authorizations or NEPA compliance include
designating a specific agency (e.g., the Department of Energy or the Federal Energy
Regulatory Commission) as the “lead agency” to coordinate applicable federal
authorizations; specifying procedures to coordinate interagency consultations (often
accomplished through the creation of a “memorandum of understanding” between
agencies specifying project milestones and deadlines); and/or designating specific
types of projects that will be considered categorical exclusions.
Some Members of Congress have argued that streamlining provisions in P.L.
109-58 are needed to reduce delays and more efficiently facilitate delivery of needed
projects. Others members have argued that they are unnecessary or may undercut
needed environmental protection.
Categories of projects or actions for which environmental streamlining
provisions are provided include:
!Coordination of geothermal leasing and permitting on federal lands
!Procedures for complying with selected sections of the Natural Gas
Act (14 U.S.C. 717n) regarding the siting, construction, or operation
of liquefied natural gas import facilities and interstate natural gas
pipelines (Section 313);
!Onshore oil and gas leasing and permitting (Section 361-366);
!The designation of right-of-way corridors for oil, gas, and hydrogen
pipelines and electricity transmission and distribution facilities on
federal land (Section 368);
!Commercial leasing of federal land for commercial development of
oil shale and tar sands (Section 369);
!Granting rights-of-way on public land for natural gas pipelines and
“utility facilities” (e.g., facilities or systems for the transportation or
storage of oil, natural gas, synthetic liquid fuel, or gaseous fuel; or
the generation, transmission, and distribution of electric energy)
!Environmental permitting for new petroleum refineries (Section
!Siting interstate electric transmission facilities (Section 1221).
Also, P.L. 109-58 (Section 390) designates specific actions undertaken by the
Secretary of the Interior in managing public lands or the Secretary of Agriculture in
managing National Forest System Lands that will be presumed to be categorical
exclusions under NEPA. Those activities, if conducted pursuant to the Mineral
Leasing Act for the exploration or development of oil or gas, are:
!Individual surface disturbances of less than 5 acres (as long as the
total surface disturbance on the lease is not greater than 150 acres
and site-specific analysis in a document prepared pursuant to NEPA
has been previously completed);
!Drilling an oil or gas well at a location or well pad site at which
drilling has occurred previously within 5 years prior to the date of
spudding the well;
!Drilling an oil or gas well within a developed field for which an
approved land use plan or any environmental document prepared
pursuant to NEPA analyzed such drilling as a reasonably foreseeable
activity (if that plan or document was approved within the previous
!Placement of a pipeline in an approved right-of-way corridor (as
long as the corridor was approved within the previous five years);
!Maintenance of a minor activity, other than any construction or
major renovation or a building or facility.
[This section prepared by Linda Luther, Analyst in Environmental Policy.]
Key Environmental Provisions not Included in P.L.
Oil Exploration in the Arctic National Wildlife Refuge (ANWR)
One major element of the energy debate in the 109th Congress has been whether
to approve energy development in the Arctic National Wildlife Refuge (ANWR) in
northeastern Alaska, and if so, under what conditions, or whether to continue to
prohibit development to protect the area’s biological, subsistence, and recreational
resources. Current law forbids energy leasing in the Refuge. As passed by the
House, H.R. 6 would have opened ANWR (including Native lands) to energy leasing,
specified environmental lease stipulations, modified existing law to allocate 50% of
revenues to the federal government (rather than 10%, as specified in the Alaska
Statehood Act), limited judicial review and requirements under the National
Environmental Policy Act, and limited certain features of federal leasing
development to no more than 2,000 acres. The Senate version of H.R. 6 had no
ANWR development provisions. In the end, the enacted law dropped the ANWR
development provisions, although the matter is likely to recur in the debate over23
reconciliation for the FY2006 budget.
[This section prepared by M. Lynne Corn, Specialist in Natural Resources.]24
Renewable Portfolio Standard
The Senate version of H.R. 6 contained a renewable energy portfolio standard
(RPS). There was no RPS in the House version and the Senate provision was
dropped in conference. A description of the Senate provision follows.
For retail electricity suppliers, a renewable portfolio standard (RPS) sets a
minimum requirement (often a percentage) for electricity production from renewable
energy resources or for the purchase of tradable credits that represent an equivalent
amount of production. In the markup of H.R. 1640 (which was incorporated into H.R.
23 The budget resolution (H.Con.Res. 95, H.Rept. 109-62) as approved by the House and
Senate on April 28, 2005, contained reductions in mandatory spending targets of $2.4 billion
over FY2006 to FY2010 for House Resources and Senate Energy Committees that will be
difficult to achieve unless ANWR development legislation is passed. The inclusion of the
Senate target particularly sets the stage for including ANWR development legislation in a
reconciliation bill, since other approaches would face a threatened filibuster in the Senate.
(See CRS Issue Brief IB10136, Arctic National Wildlife Refuge (ANWR): Controversies
for the 109th Congress for additional information.)
24 For more information, see CRS Issue Brief IB10136, Arctic National Wildlife Refuge
(ANWR): Controversies for the 109th Congress; CRS Report RL31278, Arctic National
Wildlife Refuge: Background and Issues; and CRS Report RL31115, Legal Issues Related
to Proposed Drilling for Oil and Gas in the Arctic National Wildlife Refuge (ANWR).
(1% in 2008, increasing by 1% annually and reaching 20% in 2027) was rejected.
Proponents noted a growing number of states with an RPS and noted that EIA reports
show an RPS could reduce electricity bills. Opponents raised concerns about the
exclusion of existing hydropower facilities and renewable energy resource limits for
the southeastern United States.
The Senate-passed version of H.R. 6 had an RPS in Section 291.25 It set an
initial target of 2.5% in 2008, rising in steps to 10% by 2020, and remaining at 10%
through 2030. Multiplying 10% times the Energy Information Administration’s
(EIA’s) projected total generation for 2020 yields an estimate of renewable energy
peak generation slightly greater than 500 billion kilowatt-hours (kWh). Further, EIA
projects that the renewable energy stimulated by a 10% RPS would mostly displace
natural gas, but also some coal, with a cumulative (2005 through 2025) value of
saved energy projected at about $5 billion.26
Production from hydropower and municipal solid waste facilities would have
been excluded from the base amount used to calculate the annual target. “Existing
renewable energy” was defined as electricity produced from facilities already placed
in service that use solar, wind geothermal, ocean, or biomass (open and closed loop)
resources. Only “new renewable energy” would have been eligible to satisfy the
target. It would have been defined as electricity produced from facilities placed in
service after the RPS is enacted, that use solar, wind geothermal, ocean, or biomass
(open and closed loop), landfill gas, or incremental hydropower resources. Further,
for existing facilities, any “incremental” production above the previous three-year
average would also have qualified.27 Double value would have been given to
production from facilities on Indian land and triple value would be given to
production from distributed generators that are smaller than one megawatt in
The retail obligation to meet the annual target could have been met through
direct generation, purchases of renewable energy, and/or purchases of tradable credits
from the Department of Energy. Tradable credits would have had a cost cap of 1.5
cents/kWh, adjusted annually for inflation, and credits for surplus generation
exceeding the annual target could be carried forward for up to three years. A
noncompliance penalty would have been imposed, with a value that was the greater
of 1.5 cents/kWh or two times the national average market value of the tradable
A federal RPS would set a minimum requirement. The states would have been
free to set a higher requirement. DOE collections from credit sales and penalties
would have gone into an account that provided state grants to promote renewables,
especially in states with a small share of renewable energy capacity. Exempt retail
25 The RPS was proposed in S.Amdt. 791, which was adopted in Senate floor debate over
26 U.S. DOE, EIA, letter to Senator Jeff Bingaman, June 15, 2005, p. 2.
27 Incremental geothermal energy is defined in terms of an average for five of the previous
suppliers included those in Hawaii and all those that produced less than four million
megawatt-hours (million watt-hours) of electricity per year.
[This section prepared by Fred Sissine, Specialist in Energy Policy.]28
28 For more information, see CRS Issue Brief IB10041, Renewable Energy: Tax Credit,
Budget, and Electricity Production Issues.