Order Code RL32873
CRS Report for Congress
Received through the CRS Web
Selected Environmental Issues Related to the
Omnibus Energy Bill (H.R. 6), 109th Congress
Updated May 6, 2005
Brent D. Yacobucci, Coordinator
Specialist in Energy Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
Selected Environmental Issues Related to the
Omnibus Energy Bill (H.R. 6), 109th Congress
Summary
In response to high energy prices, increasing energy imports, and concerns over
environmental quality, the 109th Congress is currently considering omnibus energy
legislation. The 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.
In the 109th Congress, the House version of an omnibus energy bill (H.R. 6) was
introduced April 18, 2005. H.R. 6 passed the House April 21, 2005. As of this
writing, a comprehensive energy bill has not been introduced in the Senate. As
passed by the House, H.R. 6 contains various provisions involving environmental
protection and regulation. This report briefly reviews the following environmental
provisions: limits on the use of MTBE; a renewable fuel mandate for gasoline;
stricter regulation of underground storage tanks; 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;
and streamlining of environmental regulations. In addition, two issues of continuing
interest that were addressed by failed committee amendments were a renewable
portfolio standard and more stringent fuel economy standards.
This report will be updated as events warrant.
Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
MTBE and Ethanol: Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
MTBE and Leaking Underground Storage Tanks . . . . . . . . . . . . . . . . . . . . . . . . . 3
Oil and Gas Exploration and Production: Clean Water . . . . . . . . . . . . . . . . . . . . . 4
Hydraulic Fracturing: Drinking Water Regulation . . . . . . . . . . . . . . . . . . . . . . . . 5
Alternative Fuels and Vehicles: R&D and Incentives . . . . . . . . . . . . . . . . . . . . . . 8
Hydroelectric Power: Relicensing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Air Quality: Ozone Nonattainment Area Deadlines . . . . . . . . . . . . . . . . . . . . . . . 9
Oil Exploration in the Arctic National Wildlife Refuge (ANWR) . . . . . . . . . . . 10
Streamlining Environmental Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Other Issues Not Included in the Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Renewable Portfolio Standard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Modified Corporate Average Fuel Economy Standards . . . . . . . . . . . 12
Selected Environmental Issues Related to
the Omnibus Energy Bill (H.R. 6),
109th Congress
Introduction
In response to high energy prices, increasing energy imports, international
instability, and environmental concerns, there has been ongoing congressional
interest in developing comprehensive energy legislation. Energy bills were debated
in the 107th and 108th Congresses, but final agreement was not reached in either
Congress. The debate over omnibus energy legislation has continued in the 109th
Congress.
H.R. 6 (Barton) was introduced April 18, 2005, after various House committees
marked up discussion drafts of the bill. The bill passed the House on April 21, 2005,
and has been referred to the Senate. Among the bill’s provisions are the following
environmental provisions: limits on the use of MTBE; a renewable fuel mandate for
gasoline; stricter regulation of underground storage tanks; 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;
and streamlining of environmental regulations.
A short discussion of each of the above provisions is included in this report. In
addition, some key environmental issues not addressed by H.R. 6 are also discussed.
It should be noted that not all environment-related provisions of H.R. 6 are discussed
in this report.
MTBE and Ethanol: Fuels
Title XV of H.R. 6 contains several provisions addressing the gasoline additive
methyl tertiary butyl ether (MTBE). Some of the provisions in this title are among
the most controversial elements in the bill (notably the “safe harbor” for producers
of MTBE and renewable fuels from product liability lawsuits, discussed below).
Under the Clean Air Act Amendments of 1990, reformulated gasoline (RFG)
sold in many areas of the country with poor air quality must 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 19 states have taken steps to ban or regulate its use.
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The most significant of these bans (in California, New York, and Connecticut) took
effect at the end of 2003.1
H.R. 6 would ban the use of MTBE as a fuel additive, except in states that
specifically authorize its use, after December 31, 2014. EPA could allow MTBE in
motor vehicle fuel in quantities up to 0.5% in cases the Administrator determines to
be appropriate. The bill would also allow the President to make a determination, not
later than June 30, 2014, that the restrictions on the use of MTBE should not take
place.
The Clean Air Act requirement to use MTBE or other oxygenates in RFG would
be repealed; this provision would take effect 270 days after enactment — except in
California, where it would take effect immediately upon enactment. In place of the
oxygen requirement, the bill would provide a major new stimulus to the use of
ethanol: Under a renewable fuels standard (RFS), motor vehicle fuels would be
required to contain at least 5 billion gallons of ethanol or other renewable fuel
annually (about a 50% increase from 2004 levels) by 2012.
To prevent backsliding on air quality, the bill would require that reductions in
emissions of toxic substances achieved by RFG be maintained; and it authorizes $2
billion in grants to assist merchant MTBE production facilities in converting to the
production of other fuel additives. The bill also would authorize funds for cleanup
of MTBE at leaking underground storage tank sites (discussed in the next section
below).
Perhaps the bill’s most controversial provision is the “safe harbor” it would
provide for renewable fuels and fuels containing MTBE (i.e., such fuels could not be
deemed defective in design or manufacture by virtue of the fact that they contain
renewables or MTBE). The effect of this provision would be to protect anyone in the
product chain, from manufacturers to retailers, from liability for cleanup of MTBE
and renewable fuels or for personal injury or property damage based on the nature of
the product (a legal approach that has been used in California to require refiners to
shoulder liability for MTBE cleanup). Were liability for manufacturing and design
defects ruled out, plaintiffs would need to demonstrate negligence in the handling of
such fuels to establish liability — a more difficult legal standard to meet. The bill
sets an effective date of September 5, 2003, for the safe harbor, rather than the date
of enactment. This effective date would protect oil and chemical industry defendants
from defective product claims in about 150 lawsuits that were filed in 15 states after
that date.2 [This section prepared by James McCarthy, Specialist in Environmental
Policy.]
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 Legislative Initiatives, by Brent D.
Yacobucci, Mary Tiemann, James E. McCarthy, and Aaron M. Flynn.
2 For further discussion, see CRS Report RS21676, The Safe Harbor Provision for Methyl
Tertiary Butyl Ether (MTBE), by Aaron Flynn.
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MTBE and Leaking Underground Storage Tanks
As part of the legislative effort to address drinking water contamination by
MTBE, Title XV, Subtitle B, would amend Subtitle I of the Solid Waste Disposal
Act (SWDA) to add new leak prevention provisions to the underground storage tank
(UST) regulatory program, and to broaden the allowable uses of the Leaking
Underground Storage Tank (LUST) Trust Fund.
Congress created the UST leak prevention, detection, and cleanup program in
1984, to address a nationwide pollution problem caused by leaking tanks. 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 concerns the discovery of MTBE at thousands
of LUST sites across the country. This gasoline additive, used to reduce air pollution
from auto emissions, is very water soluble, and leaks involving MTBE are more
costly to remediate than conventional gasoline leaks. MTBE tends to separate from
the gasoline and spread further, and these leaks are more likely to reach water
supplies. 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 long sought larger appropriations from the trust fund to support the LUST
program, and some have sought more flexibility in using LUST funds.3
H.R. 6 would require EPA or the state to conduct compliance inspections of
USTs every three years; prohibit fuel delivery to ineligible tanks; and require EPA,
with Indian tribes, to develop and implement a strategy to address releases on tribal
lands. It also would direct states to develop training requirements for persons
responsible for operating and maintaining tanks and responding to spills. The bill
would allow EPA and states to use LUST funds to conduct inspections and enforce
UST release prevention and detection requirements. Further, it would require 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.
Section 1530 would require 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
3 The LUST Trust Fund has been funded primarily through a 0.1 cent-per-gallon motor fuels
tax that commenced in 1987. During FY2004, the tax generated $193 million in revenues,
and the fund earned $66.7 million in interest (on an accrual basis). At the end of FY2004,
the fund’s net assets were $2.24 billion. For EPA and states to administer the LUST cleanup
program, Congress appropriated from the Fund nearly $76 million for FY2004 and nearly
$70 million for FY2005. The President has requested $73 million for FY2006. Roughly 81%
of the appropriated amount goes to the states to oversee and enforce cleanups by responsible
parties. EPA uses the remainder for its program responsibilities and for LUST activities on
Indian lands.
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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 environment.
Section 1531 would authorize annually, from the LUST Trust Fund for FY2005
through FY2009, the appropriation 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). (Note that the
MTBE cleanup money is for the LUST program, and this money can only be used to
clean up contaminated drinking water supplies if the contamination can be tied to a
federally regulated underground storage tank. However, because no federal standard
has been established for MTBE in drinking water, some states do not require testing
for MTBE at LUST sites, and fewer than half the states are taking steps to ensure that
MTBE and other oxygenates are not migrating beyond the standard monitoring
boundaries for LUST cleanup.)4
Also from the trust fund, Section 1531 would authorize to be appropriated, for
each of FY2005 through FY2009, $155 million for EPA and states to carry out and
enforce the UST leak prevention and detection requirements added by this bill and
the LUST cleanup program. From general revenues, this section would authorize the
appropriation of another $50 million, for each of FY2005 through FY2009, for EPA
and states to carry out the general UST program. (For more information on the LUST
program, see CRS Report RS21201, Leaking Underground Storage Tanks: Program
Status and Issues. For more information on MTBE issues, see CRS Report RL32787,
MTBE in Gasoline: Clean Air and Drinking Water Issues.) [This section prepared
by Mary Tiemann, Specialist in Environmental Policy.]5
Oil and Gas Exploration and Production:
Clean Water
Section 328 of H.R. 6 would give 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, but the construction of these facilities is not. The
amendment would modify the act 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.
4 New England Interstate Water Pollution Control Commission, Survey of State Experiences
with MTBE and Other Oxygenate Contamination at LUST Sites, August 2003, Executive
Summary, pp. 1-2.
5 For more information on the LUST program, see CRS Report RS21201, Leaking
Underground Storage Tanks: Program Status and Issues, by Mary Tiemann.
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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
100,000 people to have a CWA discharge permit. The permits require pollution-
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 compliance deadline approached, EPA authorized a
two-year extension of the Phase II rules for small oil and gas construction sites to
allow the agency to assess the economic impact of the rule on that industry. In March
2005, EPA extended the exemption until June 2006 and said it will propose a specific
rule for small oil and gas construction sites by September 11, 2005. 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 recent Department of Energy data indicate
that several thousand new sites per year would be of sizes subject to the rule.6
The provision in H.R. 6 as passed by the House on April 21 is identical to one
in H.R. 6/S. 2095, comprehensive energy policy legislation in the 108th Congress,
making EPA’s delay permanent and making 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 has argued that the stormwater rule creates
costly permitting requirements, even though the short construction period for drilling
sites carries little potential for stormwater runoff pollution. Supporters say the
amendment is intended to clarify existing CWA language. Opponents argue that the
provision does not belong in the energy legislation, and that there is no evidence that
construction at oil and gas sites causes less pollution than other construction
activities. [This section prepared by Claudia Copeland, Specialist in Resources and
Environmental Policy.]
Hydraulic Fracturing: Drinking Water Regulation
Section 327 would amend the Safe Drinking Water Act (SDWA), § 1421(d), to
specify that the definition of “underground injection” excludes the injection of fluids
or propping agents used in hydraulic fracturing operations for oil and gas production.
This language would prevent EPA from regulating the underground injection of
fluids for hydraulic fracturing purposes, thus removing EPA’s existing authority to
do so under SDWA; it also would effectively overturn two court rulings.
The SDWA requires controls on the underground injection of fluids to protect
underground sources of drinking water. EPA had not considered hydraulic fracturing
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.
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to fall within the regulatory definition of underground injection. Then, in 1997, the
Court of Appeals for the 11th Circuit ruled that the hydraulic fracturing of coalbeds
for methane production constitutes underground injection and must be regulated.
(This decision applied only to Alabama (LEAF v. EPA, 118 F. 3d 1467).)7
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
of coalbed methane primarily since the mid-1990s.8 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 typically used as
fracturing fluids; however, the industry reports that diesel fuel often is used instead
of water, and methanol and various chemical substances also are used in fracturing
fluids.9
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.”10 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.11 Also, because the process fractures rock,
fracturing can create new pathways for natural gas (primarily methane) to enter
7 In January 2000, a second suit was filed against EPA for approving Alabama’s revised UIC
program when it contained several alleged deficiencies. (Legal Environmental Assistance
Foundation, Inc. v. U.S. EPA., 276 F.3d 1253 (11th Cir. 2001)). The U.S. Court of Appeals
for the 11th 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 §1425, rather than the more stringent
underground injection control requirements of §1422.
8 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
25,000 wells were planned for Montana.
9 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.
10 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.
11 Ibid., pp. 4-9 - 4-10.
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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
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 potentially toxic additives in the hydraulic fracturing process,
and the potential impact of coalbed methane development on local underground
water resources and on the quality of surface waters.12
The 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 95% of hydraulic
fracturing services (BJ Services, Halliburton Energy Services, and Schlumberger
Technology Corporation).13 Under this voluntary agreement, the firms agree to
remove diesel fuel from CBM fluids injected directly into drinking water sources, if
cost-effective alternatives are available.
The 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 development.
In response to the 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.14 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
12 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,
Washington, D.C.
13 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.
14 U.S. Environmental Protection Agency. Draft Evaluation of Impacts to Underground
Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. EPA
816-D-02-006. Aug. 2002 p. 6-20 - 6-21.
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final report that concluded that the injection of hydraulic fracturing fluids into CBM
wells poses little or no threat to underground sources of drinking water and requires
no further study; however, EPA noted that very little documented research has been
done on the environmental impacts of injecting fracturing fluids.15 The report has
been criticized by some, and the EPA Inspector General has been asked to review a
whistle-blower’s assertions that EPA’s findings are scientifically unfounded.16 (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
H.R. 6 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. As passed by the House, Title VIII
would authorize $4 billion for hydrogen fuel and fuel cell R&D over the course of
FY2006-FY2010. 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. Therefore, this $4
billion authorization would represent a significant increase. In addition, Section 930
would authorize $1.4 billion over five years for research on vehicle energy efficiency,
including hydrogen infrastructure.
Section 713 would require the Environmental Protection Agency to establish a
program to promote the domestic production and sale of hybrid and advanced diesel
vehicles. As part of the program, the agency is required to provide grants to domestic
auto manufacturers to encourage production and provide consumer purchase
incentives. A total of $3 billion would be authorized between FY2006 and FY2015.
Section 1316 would establish a tax credit for the purchase of certain advanced
lean-burn engine vehicles. Depending on the fuel economy and projected fuel
savings, the purchaser of a lean-burn vehicle could qualify for a tax credit of up to
$3,500. The credit would expire after 2007. [This section prepared by Brent
Yacobucci, Specialist in Energy Policy.]17
Hydroelectric Power: Relicensing
H.R. 6 (Subtitle C — Hydroelectric, Part 1), as passed by the House, gives
applicants for hydroelectric licenses increased flexibility in complying with
conditions imposed by federal agencies. Currently, the Federal Power Act gives
15 Ibid. p. 4-1.
16 Letter (and technical analysis) to Senators Wayne Allard and Ben Nighthorse Campbell
and Representative Diana DeGette from Weston Wilson, U.S. Environmental Protection
Agency, Region 8, Oct. 8, 2004.
17 For more information, see CRS Issue Brief IB10128, Alternative Fuels and Advanced
Technology Vehicles: Issues in Congress.
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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 generation costs by reducing
operational flexibility.
The provision in H.R. 6 would allow license applicants to propose alternative
license conditions, and would require federal agencies to consider alternatives
proposed by license applicants. It would also require an agency to accept an
applicant’s proposed alternative if it found 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 less to
implement, and/or will improve operation of the project for electricity production.
H.R. 6 also requires agencies that are issuing conditions 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. This equal consideration clause
may be a topic of debate during further consideration of H.R. 6. Opponents of the
provision are concerned that it would hamper agencies’ ability to protect the
resources under their jurisdiction; proponents argue that conditioning agencies, like
FERC, should be required to balance competing water uses. [This section prepared
by Kyna Powers, Analyst in Energy and Environmental Policy.]
Air Quality: Ozone Nonattainment Area Deadlines
Section 1443 of H.R. 6 would amend 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.
Deadlines for nonattainment areas were established by the 1990 Clean Air Act
Amendments. Under this statute, ozone nonattainment areas were classified in one
of five categories: marginal, moderate, serious, severe, or extreme. Areas with higher
concentrations of the pollutant were given more time to reach attainment. 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 the next highest category and the imposition of more
stringent controls.
For a variety of reasons, EPA has often not reclassified areas when they failed
to reach attainment by the statutory deadlines. As of April 2005, the agency’s
website listed 18 marginal areas, 6 moderate areas, and 9 serious areas; most of the
33 should have been categorized as severe under the statutory requirements. In
several cases, the agency granted additional time to reach attainment on the grounds
that a significant cause of the area’s continued nonattainment was pollution generated
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outside the area and transported into it by prevailing winds. EPA has been sued over
its failure to bump up five of these areas; the agency lost the first three cases decided
(Washington, D.C.; St. Louis; and Beaumont-Port Arthur, Texas).18
Section 1443 would roll back reclassifications that have occurred since April 1,
2003, and would extend attainment deadlines in areas affected by upwind pollution
to the date on which the last reductions in pollution necessary for attainment in the
downwind area are required to be achieved in the upwind area. The specific date is
open to interpretation. Under EPA’s overturned policy, areas were given extensions
no longer than the attainment or compliance deadline in the upwind area (generally
2004, 2005, or 2007). The language of Section 1443 appears to give EPA flexibility
to extend the deadlines beyond those dates, however. It also would apply to the
agency’s new eight-hour ozone standard implemented last year, making many
additional areas eligible for extensions. [This section prepared by James McCarthy,
Specialist in Environmental Policy.]19
Oil Exploration in the
Arctic National Wildlife Refuge (ANWR)
One major element of the energy debate in the 109th Congress is 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 open ANWR (including Native lands) to energy leasing, specify
environmental lease stipulations, modify existing law to allocate 50% of revenues to
the federal government (rather than 10%, as specified in the Alaska Statehood Act),
limit judicial review and requirements under the National Environmental Policy Act,
and limit certain features of federal leasing development to no more than 2,000 acres.
[This section prepared by M. Lynne Corn, Specialist in Natural Resources.]20
Streamlining Environmental Requirements
H.R. 6 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
18 The three cases were Sierra Club v. EPA, 311 F.3d 853, 55 ERC 1385 (7th Cir. 2002);
Sierra Club v. EPA, 314 F.3d 735, 55 ERC 1577 (5th Cir. 2002); and Sierra Club v. EPA,
294 F.3d 155, 54 ERC 1641 (D.C. Cir. 2002).
19 For more information, see CRS Report RS21611, Ozone and Particulate Air Quality:
Should Deadlines for Attainment Be Extended?
20 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).
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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. Streamlining provisions are generally intended to better
coordinate the interagency interaction necessary to complete applicable
environmental requirements.
The environmental streamlining provisions in H.R. 6 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. 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)). Streamlining provisions often
propose legislative or administrative procedures intended to expedite the process for
completing an EIS.
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 project alternatives required to be considered for a given
class of projects; requiring the creation of a “memorandum of understanding”
between agencies specifying project milestones and deadlines; and authorizing the
lead agency to establish a consolidated or coordinated environmental review process.
Categories of projects for which environmental streamlining provisions are
proposed in H.R. 6 include:
! The construction, expansion, or operation of liquefaction or
gasification natural gas terminals (Title III Oil and Gas —
Commerce, Subtitle B — Production Incentives § 320);
! Refinery expansion projects in designated “Refinery Revitalization
Zones” (Title III Oil and Gas — Commerce, Subtitle D — Refining
Revitalization §§ 374-378);
! Siting interstate electric transmission facilities (Title XII —
Electricity, Subtitle B — Transmission Infrastructure Modernization
§ 1221);
! “Renewable energy projects,” meaning those projects using an
energy source other than nuclear power, coal, oil, or natural gas,
including the use of wind, solar, geothermal, biomass, or tidal forces
to generate energy (Title XVII — Renewable Energy § 1702);
! Land leasing on the Arctic Coastal Plain (Title XXII — Arctic
Coastal Plain Domestic Energy § 2203);
! Onshore oil and gas leasing and permitting on federal land (Title XX
— Oil and Gas — Resources, Subtitle B — Access to Federal Land
§§ 2021-2028);
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! The designation of energy facility rights-of-way and corridors on
federal lands (Title XX — Oil and Gas — Resources, Subtitle B —
Access to Federal Land §§ 2030-2031); and
! Designated actions by the Department of the Interior to manage
public lands (if conducted for the purpose of exploration or
development of a domestic federal energy source) (Title XXVI —
Additional Provisions § 2601).
Some Members of Congress have argued that streamlining provisions in H.R.
6 are needed to reduce delays and more efficiently facilitate delivery of needed
projects. Others argue that they are unnecessary or may undercut needed
environmental protection. [This section prepared by Linda Luther, Analyst in
Environmental Policy.]
Other Issues Not Included in the Legislation
Renewable Portfolio Standard. 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 April 12
markup by the House Committee on Energy and Commerce, an amendment to add
an RPS (1% in 2008, increasing by 1% annually through 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 resource limits for the southeastern
United States. [This section prepared by Fred Sissine, Specialist in Energy Policy.]21
Modified Corporate Average Fuel Economy Standards. There has
been continuing interest in modifying the existing corporate average fuel economy
(CAFE) standards, either to tighten the standards for passenger cars and light trucks,
or to modify the existing system to address some its perceived shortcomings. In the
House Committee on Energy and Commerce markup, an amendment was offered to
require the Department of Transportation to increase CAFE standards in order to save
10% of fuel consumption by 2014. The amendment was rejected. On the House
floor, H.Amdt. 73 would have required the Secretary of Transportation to increase
car and light truck CAFE standards to 33 miles per gallon (up from 27.5 and 21.0,
respectively). This amendment was also rejected.
While not modifying the existing CAFE structure, Subtitle E of Title VII does
address the implementation of the current fuel economy standards, including
authorizing funds for rulemaking, and extending CAFE incentives for the production
of alternative fuel vehicles. [This section prepared by Brent Yacobucci, Specialist
in Energy Policy.]22
21 For more information, see CRS Issue Brief IB10041, Renewable Energy: Tax Credit,
Budget, and Electricity Production Issues.
22 For more information, see CRS Issue Brief IB90122, Automobile and Light Truck Fuel
Economy: The CAFE Standards.