Omnibus Energy Legislation, 109th Congress: Side-by-Side Assessment of House and Senate Versions of H.R. 6
Released: 2005-07-25T00:00:00

Introduction

Since the Arab oil embargo in 1973-1974, Congress has periodically taken up energy policylegislation with a comprehensive scope -- often spurred by the price of oil and U.S. dependence uponimported oil. The price of crude oil began to rise in 2003 -- exceeding $60/barrel (bbl) in early July2005 -- setting much of the context for renewed debate over omnibus energy legislation in the 109thCongress.

National and world demand for oil continues to grow. However, domestic oil production inthe United States continues to decline. As a consequence, the gap between U.S. production andconsumption has had to be covered by increased oil imports. These imports, roughly 6 millionbarrels per day (mbd) after the Arab oil embargo, now exceed 10 mbd to satisfy total U.S. oilconsumption of nearly 21 mbd. (1)

Addressing dependence on imported oil raises a number of issues touching on both demandand consumption of fossil fuels. Chief among these are the production of additional fossil fuels,development of alternative energy sources, and conservation and energy efficiency. Energyinfrastructure has also been a growing issue, including the oil refining and distribution sector, andelectricity transmission, reliability, and regulation. Increased use of domestic coal and reassessmentof many issues associated with nuclear energy have drawn attention as well.

Developing a comprehensive approach to energy policy that balances economic, security, andenvironmental issues -- as well as competing regional priorities in the United States -- is anenormous challenge for policymakers. Keeping a clear eye on distinguishing between short- andlong-term policies is also difficult but important in keeping expectations realistic for whatcomprehensive legislation can achieve.

In the 109th Congress, the House approved an omnibus energy bill ( H.R. 6 ) onApril 21, 2005, that would open the Arctic National Wildlife Refuge (ANWR) to oil and gas leasing,substantially change oversight of electric utilities, increase the use of alternative motor fuels, provide$8.1 billion in energy tax incentives, extend the nuclear accident liability system, and authorizenumerous energy R&D programs. The Senate passed its version of H.R. 6 on June 28without ANWR provisions but including $14.1 billion in tax incentives and provisions on globalclimate change. The two versions of the bill contain many provisions from the conference report onan omnibus energy bill (also numbered H.R. 6 ) in the 108th Congress that was blockedby a Senate filibuster.

The House- and Senate-passed bills in the 109th Congress would mandate increasing levelsof ethanol production through 2012 but allow regions to opt out under certain conditions. Use ofmethyl tertiary butyl ether (MTBE) as a domestic gasoline additive would be phased out, but statescould authorize continued use and under the House bill the President could void the ban. Producersof MTBE and renewable fuels would be granted protection (a "safe harbor") from product liabilitylawsuits under the House bill, while only renewable fuels would be covered in the Senate bill. MTBE liability protection proved highly contentious in the Senate in the 108th Congress.

The Senate bill includes a "renewable portfolio standard" (RPS) -- rejected by the HouseEnergy and Commerce Committee -- requiring utilities to generate at least 10% of their electricityfrom renewable energy sources by 2020. Also, the Senate bill would establish a credit-baseddeployment program to encourage technologies to reduce greenhouse gas intensity and establishprograms to deploy technologies in developing countries. Neither of those provisions is in the Housebill.

Provisions are also included in both bills to increase access by energy developers to federallands. Several new statutory efficiency standards would be established for consumer and commercialproducts and appliances, and other standards would be set by the Department of Energy (DOE).

Major Provisions

Electricity Regulation. Title XII in the House-and Senate-passed bills would create an electric reliability organization (ERO) that would enforcemandatory reliability standards for the bulk-power system. All ERO standards would be approvedby the Federal Energy Regulatory Commission (FERC). Under this title, the ERO could imposepenalties on a user, owner, or operator of the bulk-power system that violates any FERC-approvedreliability standard. This title also addresses transmission infrastructure issues. The Secretary ofEnergy would be able to certify congestion on the transmission lines and issue permits totransmission owners. Permit holders would be able to petition in U.S. District Court to acquirerights-of-way for the construction of transmission lines through the exercise of the right of eminentdomain. In the Senate bill, FERC could approve participant funding for transmission lineconstruction. A provision that would have required FERC to approve participant funding for newtransmission lines was removed in markup by the House Committee on Energy and Commerce.

Under the House bill, FERC's Standard Market Design notice of proposed rulemaking wouldbe remanded. The Senate bill would terminate FERC's Standard Market Design notice of proposedrulemaking. Under both Senate- and House-passed bills, native load service obligations would beclarified, and federal utilities would be allowed to participate in regional transmission organizations.

Under both bills, the electricity title would repeal the mandatory purchase requirements underthe Public Utility Regulatory Policies Act (PURPA). The Public Utility Holding Company Act of1935 (PUHCA) would be repealed. The Federal Energy Regulatory Commission and stateregulatory bodies would be given access to utility books and records.

FERC would be required to issue rules to establish an electronic system that providesinformation about the availability and price of wholesale electric energy and transmission servicesunder the House version, and could issue such rules under the Senate version. Under both versions,for electric rates that the Federal Energy Regulatory Commission finds to be unjust, unreasonable,or unduly discriminatory, the effective date for refunds would begin at the time of the filing of acomplaint with FERC but not later than five months after filing of a complaint. Criminal and civilpenalties would be increased. Under the House version, the Federal Power Act would be amendedto give FERC review authority for transfer of assets valued in excess of $10 million. The Senateversion would also apply to the purchase, lease, or acquisition of an existing generating facility thathas a value in excess of $10 million and is used to generate electricity for FERC jurisdictionalinterstate wholesale sales. In addition to the House requirements, the Senate version would requireFERC to determine that the proposed transaction would not result in harmful cross-subsidizationwith a non-utility associate company.

(For additional discussion on these issues, see CRS Report RL32728 , Electric UtilityRegulatory Reform: Issues for the 109th Congress ; and CRS Report RL32133 , Federal MergerReview Authority .)

Renewable Fuel Standard and MTBE. The Houseand Senate versions of H.R. 6 would amend the Clean Air Act to eliminate therequirement that reformulated gasoline (RFG) contain 2% oxygen to reduce automotive emissions,a requirement which prompted the widespread use of MTBE and, to a lesser degree, ethanol. Instead, the bills would establish a new requirement that an increasing amount of gasoline containrenewable fuels such as ethanol. The House bill would require that 3.1 billion gallons of renewablefuel be used in 2005, increasing to 5.0 billion gallons by 2012, and the Senate bill would require 8.0billion gallons by 2012 (compared with 3.4 billion gallons used in 2004). However, concerns havebeen raised that this requirement could significantly increase the pump price for gasoline in someareas.

Because of concerns over drinking water contamination by MTBE (a major competitor withethanol), both bills would ban the use of MTBE in motor vehicle fuel, except in states thatspecifically authorize its use, not later than December 31, 2014, under the House version and fouryears after enactment in the Senate version. The ban has two possible exceptions. First, theEnvironmental Protection Agency (EPA) may allow MTBE in motor fuel up to 0.5 percent byvolume, in cases that the Administrator determines to be appropriate; and second, under the Houseversion, the President may make a determination, not later than June 30, 2014, that the restrictionson the use of MTBE shall not take place. The House bill would authorize $2.0 billion and theSenate bill $1.0 billion to assist the conversion of merchant MTBE production facilities to theproduction of other fuel additives. Further, the bills would preserve the reductions in emissions oftoxic substances achieved by the RFG program (although they use different baselines for determiningrequired reductions).

One of the most controversial provisions in the House version of H.R. 6 is theestablishment of a "safe harbor" from product liability lawsuits for producers of MTBE andrenewable fuels (such as ethanol). The safe harbor provision would protect anyone in the productchain, from manufacturers down to retailers, from liability for cleanup of MTBE and renewable fuelsor for personal injury or property damage based on the product being deemed defective. (That legalapproach has been used in California to require refiners to shoulder liability for MTBE cleanup.) Thesafe harbor would be retroactive to September 5, 2003. Prior to that date, five lawsuits had beenfiled. After that date, at least 150 suits were filed, on behalf of 210 communities in 15 differentstates. The Senate bill includes the safe harbor provision for renewable fuels but not MTBE; theSenate safe harbor would not be retroactive.

(For additional information, see CRS Report RL32865(pdf) , Renewable Fuels and MTBE: AComparison of Selected Legislative Initiatives ; CRS Report RL30369, Fuel Ethanol: Backgroundand Public Policy Issues ; and CRS Report RL32787 , MTBE in Gasoline: Clean Air and DrinkingWater Issues .)

Energy Taxes. After the conference report on H.R. 6 in the 108th Congress was blocked in the Senate, several of the measure's energytax provisions -- estimated at $1.3 billion over 10 years -- were included in the Working FamiliesTax Relief Act of 2004 ( P.L. 108-311 ), enacted on October 4, 2004. About $5 billion in additionalenergy tax incentives over 10 years were part of the American Jobs Creation Act of 2004 ( P.L.108-357 ) enacted on October 22, 2004.

Many of the energy tax incentives in H.R. 6 from the 108th Congress that werenot enacted in 2004 have been repackaged into the H.R. 6 in the 109th Congress, withsignificant differences between the House and Senate versions. First, the Senate bill would providenet tax reductions of $14.1 billion over 11 years compared with $8.1 billion in the House-passedversion. Second, most of this difference is accounted for by tax cuts for the electricity industry,energy efficiency, and renewable and alternative fuels. The Senate bill provides absolutely andrelatively more tax cuts for energy efficiency and alternative fuels. The differences in tax cuts foralternative fuels are particularly striking: $12 billion in the Senate bill vs. $0.6 billion in the Housebill. The Senate bill also provides more tax incentives for energy efficiency investments than theHouse bill. The House bill provides much larger tax cuts for the electricity industry, particularly forelectricity infrastructure.

Thus, in a relative sense, the House bill is tilted more toward fossil fuel production, whilethe Senate bill's tax cuts are tilted more to the production of alternative and renewable fuels andenergy conservation. However, the absolute dollar tax cuts for oil, gas, and coal are also somewhatlarger in the Senate bill than in the House bill ($5.8 billion vs. $4.7 billion).

(For more background, see CRS Issue Brief IB10054, Energy Tax Policy .)

Nuclear Energy. Strong incentives for buildingnew commercial nuclear power plants are included in the Senate version of H.R. 6 , andboth the House and Senate bills would reauthorize the Price-Anderson Act nuclear liability systemfor 20 years and authorize DOE to build an advanced reactor in Idaho.

The strongest nuclear incentive is the Senate bill's 1.8-cents/kilowatt-hour tax credit forelectricity produced by nuclear reactors. The credit would be available for up to 6,000 megawattsof new capacity -- the equivalent of about five or six new reactors -- for the first eight years ofoperation. The nuclear production tax credit was also included in the energy bill conference reportin the 108th Congress, and the Energy Information Administration concluded then that the creditwould provide sufficient incentives for new commercial reactors to be built. (2) The Senate bill would alsoauthorize loan guarantees for new reactors. Neither of those incentives is included in the Houseversion.

Reauthorization of the Price-Anderson Act is generally considered to be a prerequisite fornew reactors. Under Price-Anderson, commercial reactor accident damages are paid through acombination of private-sector insurance and a nuclear industry self-insurance system. Liability iscapped at the maximum coverage available under the system, currently about $10.7 billion. Evenwithout reauthorization, existing reactors continue to be covered, but any new ones would not. Price-Anderson also authorizes the Department of Energy to indemnify its nuclear contractors. Thelimit on DOE contractor liability is the same as for commercial reactors, except when the limit forcommercial reactors drops because of a decline in the number of covered reactors.

Both versions of H.R. 6 would provide a 20-year extension of Price-Andersonto the end of 2025. The nuclear industry contends that the system has worked well and should becontinued, but opponents charge that Price-Anderson's liability limits provide an unwarrantedsubsidy to nuclear power. The House version of the bill would also require the Nuclear RegulatoryCommission (NRC) to assess nuclear power plant security and require additional security measures.

(For more information, see CRS Issue Brief IB88090, Nuclear Energy Policy .)

Renewable Portfolio Standard and EnergyEfficiency. The Senate version of H.R. 6 would require retailelectricity suppliers (electric utilities, except for those in Hawaii and that sold less than 4 billionkwh) to obtain a minimum percentage of their power from a portfolio of new renewable energyresources. The minimum renewable energy target, or Renewable Portfolio Standard (RPS), wouldstart at 2.5% in 2008, rise in steps of 2.5% every four years, and level off at 10% from 2020 to 2030. The House version of H.R. 6 does not have an RPS provision.

Eligible resources for the RPS in the Senate bill would include "new renewable energy"produced from solar, wind, ocean, and geothermal energy, most forms of biomass, landfill gas, andincremental hydropower. Also, additional energy above the average generation in the threepreceding years from "existing" (already placed in service) facilities using solar, wind, ocean,biomass, landfill gas, incremental hydropower, or incremental geothermal energy would be eligibleto satisfy the RPS target. The base for calculating the target production level would exclude powerfrom existing hydropower and municipal solid waste generation. Thus, states with a large amountof existing hydropower or municipal solid waste generation would have a proportionately lowertarget for new generation. However, there may be a debate in conference about whether existingnuclear and hydro generation, or some portion of it, would be eligible to satisfy the RPS target.

Tradable credits would be created, which could be purchased in place of alternative powersources. The credits would function like those in the Clean Air Act emission allowance tradingsystem, which has lowered compliance costs for air pollution regulations. Electricity suppliers could"carry forward" surplus credits for up to three years. Double credits would be provided for facilitieson Indian land and triple credits would go to distributed generators under 1 megawatt in size. A costcap for the credits is set as the lesser of 1.5 cents/kilowatt-hour (kwh) or 200% of the average marketvalue of the credits. DOE collections from credit sales and penalties would fund grants to states topromote renewables.

Both versions of H.R. 6 would legislate new energy efficiency standards forseveral consumer and commercial products and appliances. For certain other products andappliances, DOE would be empowered to set new standards. Also, the bill would provide increasedfunding authorizations for the DOE weatherization program and establish a voluntary program topromote energy efficiency in industry.

(For additional information, see CRS Issue Brief IB10020, Energy Efficiency: Budget, OilConservation and Electricity Conservation Issues , and CRS Issue Brief IB10041, RenewableEnergy: Tax Credit, Budget, and Electricity Production Issues .)

Arctic National Wildlife Refuge. Thecongressional debate over whether to open ANWR to development has continued for more than 40years. H.R. 6 as passed by the House would authorize oil and gas exploration,development, and production in a portion of ANWR, with a 2,000-acre limit on certain productionand support facilities. The Senate version contains no ANWR provisions.

Development advocates argue that ANWR oil would reduce U.S. energy markets' exposureto crises in the Middle East; boost North Slope oil production; lower oil prices; extend the economiclife of the Trans Alaska Pipeline System; and create many jobs in Alaska and elsewhere in the UnitedStates. They maintain that ANWR oil could be developed with minimal environmental harm, andthat the footprint of development could be limited to a total of 2,000 acres.

Opponents of development in ANWR argue that intrusion on this ecosystem cannot bejustified on any terms; that economically recoverable oil found (if any) would provide little energysecurity and could be replaced by cost-effective alternatives, including conservation; and that jobclaims are overstated. They also maintain that the footprint of oil development, despite a provisionin the measure to limit certain facilities to 2,000 acres, would still be scattered in many parcels acrossthe landscape, and would have a greater impact than is implied by any limit on total acreage. Theyalso argue that past proposals to limit any footprint have not been worded so as to apply clearly tothe extensive Native lands in the Refuge, which could be developed if the Arctic Refuge wereopened.

(For additional information, see CRS Issue Brief IB10136, The Arctic National WildlifeRefuge: Controversies for the 109th Congress ; and CRS Report RL31115 , Legal Issues Related toProposed Drilling for Oil and Gas in the Arctic National Wildlife Refuge and CRS Report RS22143 , Oil and Gas Leasing in the Arctic National Wildlife Refuge (ANWR): the 2,000-Acre Limit. )

Domestic Energy Production. The Departmentof the Interior (DOI) has estimated that roughly a quarter of oil resources and less than one-fifth ofgas resources on Indian lands have been developed. Both versions of H.R. 6 wouldencourage production on federal lands through royalty reductions for marginal oil and gas wells onpublic lands and the outer continental shelf. Provisions are also included to increase access tofederal lands by energy projects -- such as drilling activities, electric transmission lines, and gaspipelines. In addition, the House bill would prohibit EPA from regulating hydraulic fracturing toprotect drinking water sources.

(For additional information, see CRS Reports RL32873, Environment and Energy: SelectedIssues in H.R. 6, 109th Congress , and RL32262, Selected Legal and Policy Issues Relatedto Coalbed Methane Development .)

Hydrogen and Fuel Cells. The House version of H.R. 6 would authorize $4 billion for FY2006-2010 for hydrogen and fuel cell R&D;the Senate version would authorize $3.3 billion over the same time frame. The bill would alsoestablish a goal of producing commercial fuel cell vehicles and developing hydrogen infrastructureby 2020. Critics of the Administration suggest that the hydrogen program is intended to forestall anyattempts to significantly raise vehicle Corporate Average Fuel Economy (CAFE) standards, and thatit relieves the automotive industry of assuming more initiative in pursuing technological innovations.On the other hand, some contend that it is appropriate for government to become involved in thedevelopment of technologies that could address national environmental and energy goals but are toorisky to draw private-sector investment.

(For additional information, see CRS Report RS21442 , Hydrogen and Fuel Cell R&D:FreedomCAR and the President's Hydrogen Fuel Initiative ; and CRS Report RL32196, A HydrogenEconomy and Fuel Cells: An Overview .)

Overview of House and Senate Versions

The House and Senate versions of H.R. 6 generally address similar areas ofenergy policy, although there are major differences. For example, only the House bill would openANWR to oil and gas activities, and only the Senate version includes extensive provisions explicitlyaddressing global climate change. Table 1 provides a brief comparison.

Table 1. Major Provisions of House and Senate Energy Bills

Organization of Report

The remainder of this report provides a section-by-section summary comparison of theprovisions of H.R. 6 as passed by the House and Senate. The sections are listed innumerical order as they appear in the House-passed version. Some of the most controversial sectionsare discussed in greater detail in a number of appendicies. Funding authorizations are shown in Tables 2 and 3 at the end of the report.

The following analysts in the CRS Resources, Science, and Industry Division contributed tothis report:

[author name scrubbed], electric utilities;

[author name scrubbed], nuclear security, DOE management;

[author name scrubbed], energy security;

Carl Behrens, nuclear nonproliferation;

[author name scrubbed], Federal Water Pollution Control Act;

Lynne Corn, ANWR;

Bernard Gelb, gasoline industry;

[author name scrubbed], Native American energy, generalauthorizations;

[author name scrubbed], nuclear energy;

[author name scrubbed], federal energy leasing, coal;

Larry Kumins, oil and gas;

[author name scrubbed], taxes;

Jim McCarthy, Clean Air Act, MTBE;

Dan Morgan, science programs;

[author name scrubbed], hydropower;

[author name scrubbed], conservation and renewable energy;

[author name scrubbed], underground storage tanks, drinkingwater;

Brent Yacobucci, motor fuels, vehicles, hydrogen;

Jeff Zinn, Coastal Zone Management Act.

Energy Efficiency

Federal Programs

Energy Assistance and State Programs

Energy-Efficient Products

Public Housing

Renewable Energy

General Provisions

Hydroelectric

Oil and Gas

Petroleum Reserve and Home Heating Oil

Production Incentives

Access to Federal Land

Refining Revitalization

Coal

Clean Coal Power Initiative

Clean Power Projects

Coal and Related Programs

Indian Energy

Nuclear Matters

Price-Anderson Act Amendments

General Nuclear Matters

Advanced Reactor Project

Nuclear Security

Vehicles and Fuels

Existing Programs

Hybrid Vehicles, Advanced Vehicles, and Fuel Cell Buses

Clean School Buses

Miscellaneous

Automobile Efficiency

Hydrogen

Research and Development

Science Programs

Research Administration and Operations

Energy Efficiency -- Vehicles, Buildings, and Industries

Energy Efficiency -- Distributed Energy and Electric Energy Systems

Renewable Energy

Nuclear Energy

Fossil Energy -- Research Programs

Fossil Energy -- Ultra-Deepwater and Unconventional Natural Gas and Other Petroleum Resources

Department of Energy Management

Electricity

Reliability Standards

Transmission Infrastructure Modernization

Transmission Operation Improvements

Transmission Rate Reform

Amendments to PURPA

Repeal of PUHCA

Market Transparency, Enforcement, and Consumer Protection

Merger Reform

Definitions

Economic Dispatch and Other Electricity

Energy Tax Incentives

Energy Infrastructure Tax Incentives

Conservation and Energy Efficiency Provisions

Alternative Minimum Tax Relief

Other Fossil Fuels Incentives -- Oil and Gas

Other Fossil Fuels Incentives -- Coal

Renewable Energy Supply

General Tax Incentives

Tax Increases

Non-Tax Provisions

Miscellaneous

Other Provisions

Ethanol and Motor Fuels

General Provisions

Underground Storage Tank Compliance

Boutique Fuels

Studies

Renewable Energy -- Resources

Geothermal Energy

Hydropower -- Resources

Oil and Gas -- Resources

Production Incentives

Access to Federal Lands

Naval Petroleum Reserves

Miscellaneous Provisions

Coal -- Resources

Energy Development in Arctic Refuge

Set America Free (SAFE)

Grand Canyon Hydrogen-Powered Transportation Demonstration

Additional Provisions

Studies

Incentives for Innovative Technologies

Climate Change

National Climate Change Technology Deployment

Climate Change Technology Deployment in Developing Countries

Index of Senate Sections

House sections in italics have no comparable Senate section. Rather, they are the closest House section beforethe indicated Senate section.

Appendix A: Hydraulic Fracturing (Sec. 327 House Bill)

Before 1997, EPA had not considered regulating hydraulic fracturing for oiland gas development, because it did not view this well-production process as anactivity subject to regulation under SDWA's UIC program. In 1997, the 11th CircuitCourt of Appeals ruled that the injection of fluids for the purpose of hydraulicfracturing constituted underground injection, that all underground injection must beregulated, and that hydraulic fracturing of coalbed methane (CBM) wells in Alabamamust be regulated under the state's UIC program ( LEAF v. EPA , 118 F. 3d 1467).

Hydraulic fracturing involves the high-pressure injection of fluids into coalbeds to enhance the recovery of oil and natural gas from underground formations.Water-based fluids are typically used as fracturing fluids; however, diesel fuel oftenis used instead of water, and various chemicals are added to fracturing fluids. (3) Whilehydraulic fracturing has been used in the recovery of conventional oil and gas sincethe 1950s, this practice has been used for CBM recovery mainly since the 1990s.

A growing concern is that, in many CBM-producing regions, the target coalbeds occur within underground sources of drinking water, and the fracturing processinjects fluids directly into the drinking water sources; EPA has determined that theuse of diesel fuel as a fracturing fluid introduces benzene and other toxic substancesdirectly into underground sources of drinking water. (4) Also, becausethe process fractures rock, fracturing can create new pathways for natural gas(primarily methane) to enter drinking water aquifers. As the number of coalbedmethane (CBM) wells and the use of hydraulic fracturing have increased rapidly inrecent years, so has concern over the potential impact on water resources, particularlyin the water-scarce West. Very few studies have been done to evaluate these impacts.

In 2003, EPA's National Drinking Water Advisory Council recommended thatEPA work to eliminate the use of diesel fuel and related additives in fracturing fluidsthat are injected into formations containing drinking water sources. In 2003, EPAentered into an agreement with three companies that provide most hydraulicfracturing services (BJ Services, Halliburton Energy Services, and SchlumbergerTechnology Corporation). (5) Under this voluntary agreement, the companiesconditionally agree to remove diesel fuel from CBM fluids injected directly intodrinking water sources, if cost-effective alternatives are available. EPA has notsought to limit other toxic components in fracturing fluids, and other companies didnot agree to cease injecting diesel fuel into drinking water sources.

The National Drinking Water Advisory Council further recommended thatEPA continue to study the extent and nature of public health and environmentalproblems that could occur as a result of hydraulic fracturing for coalbed methaneproduction, and defend its authority to implement the UIC program in a manner thatprotects groundwater resources from contamination. However, oil and gas industryrepresentatives argue that regulation is unnecessary and would slow natural gasdevelopment.

In 2004, EPA issued a report, based primarily on a review of the literature,that concluded that the injection of hydraulic fracturing fluids into CBM wells poseslittle threat to underground sources of drinking water and requires no further study;however, EPA noted that very little documented research has been done on theenvironmental impacts of injecting fracturing fluids. (6) EPA alsonoted that estimating the concentration of diesel fuel components and other fracturingfluids beyond the point of injection was beyond the scope of its study. (7) The report hasbeen criticized by some, and the EPA Inspector General has been asked to review awhistle-blower's assertions that EPA's findings are scientifically unfounded. (8) (For moreinformation, see CRS Report RL32873 , Selected Environmental Provisions Relatedto the Omnibus Energy Bill (H.R. 6), 109th Congress , and CRS Report RL32262 , Selected Legal and Policy Issues Related to Coalbed MethaneDevelopment .)

Appendix B: Oil and Gas Exploration and Production Defined (Sec. 328, House Bill)

The issue of how oil and gas exploration and production facilities are definedin the Clean Water Act (CWA) arises from stormwater permitting rules for smallconstruction sites and municipal separate storm sewer systems that were issued bythe Environmental Protection Agency (EPA) in 1999 and became effective March 10,2003. Those rules, known as Phase II of the CWA stormwater program, require mostsmall construction sites disturbing one to five acres and municipal separate stormsewer systems serving populations of up to 100,000 people to have a CWA dischargepermit. The permits require pollution-prevention plans describing practices forcurbing sediment and other pollutants from being washed by stormwater runoff intolocal water bodies. Phase I of the stormwater program required construction siteslarger than five acres (including oil and gas facilities) and larger municipal separatestorm sewer systems to obtain discharge permits beginning in 1991.

As the March 2003 compliance deadline approached, EPA authorized atwo-year extension of the Phase II rules for small oil and gas construction sites toallow the agency to assess the economic impact of the rule on that industry. In March2005 EPA extended the exemption until June 2006 and said it would propose aspecific rule for small oil and gas construction sites by September 11, 2005. EPAhad initially assumed that most oil and gas facilities would be smaller than one acrein size and thus excluded from the Phase II rules, but recent Department of Energydata indicate that several thousand new sites per year would be of sizes subject to therule.

The provision in the House-passed version of H.R. 6 is identicalto one in H.R. 6 / S. 2095 in the 108th Congress, makingEPA's delay permanent and making it applicable to construction activities at all oiland gas development and production sites, regardless of size, including thosepreviously covered by Phase I rules. Industry has argued that the stormwater rulecreates costly permitting requirements, even though the short construction period fordrilling sites carries little potential for stormwater runoff pollution. Supporters saythe amendment is intended to clarify existing CWA language. Opponents argue thatthe provision does not belong in the energy legislation, and that there is no evidencethat construction at oil and gas sites causes less pollution than other constructionactivities, which are regulated under EPA's stormwater program.

Appendix C: Clean Air Coal Program (Sec. 441 House, Sec. 956 Senate)

A total of $500 million over FY2006-FY2010 would be authorized forpollution control projects to control mercury, nitrogen dioxide, sulfur dioxideemissions, particulate matter, or more than one pollutant; and allow use of the wastebyproducts. Additional authorizations totaling $2.5 billion over FY2007-FY2013would be provided for projects using coal-based electrical generation equipment andprocesses, and associated environmental control equipment.

Project selection criteria would be based on significantly improving airquality, replacing less efficient units, and improving thermal efficiency. Up to 25%of projects would be cogeneration or other gasification projects. At least 25% of theprojects would be solely for electrical generation, with priority for those generatingless than 600 MW. Federal loans or loan guarantees would not exceed 30% of thetotal funds obligated during any fiscal year. The federal share of projects fundedwould not exceed 50%.

No technology funded by the program, or level of emissions reductionachieved by funded projects, would be considered adequately demonstrated forpurposes of Sections 111, 169, or 171 of the Clean Air Act.

Appendix D: Price-Anderson Nuclear Liability Coverage (Secs. 601-612)

Current Law. Under Price-Anderson,the owners of commercial reactors must assume all liability for nuclear damagesawarded to the public by the court system, and they must waive most of their legaldefenses following a severe radioactive release ("extraordinary nuclear occurrence"). To pay any such damages, each licensed reactor must carry financial protection in theamount of the maximum liability insurance available, which was increased by theinsurance industry from $200 million to $300 million on January 1, 2003. Anydamages exceeding that amount are to be assessed equally against all coveredcommercial reactors, up to $95.8 million per reactor (most recently adjusted forinflation on August 20, 2003). Those assessments -- called "retrospectivepremiums" -- would be paid at an annual rate of no more than $10 million perreactor, to limit the potential financial burden on reactor owners following a majoraccident. According to the Nuclear Regulatory Commission (NRC), 103 commercialreactors are currently covered by the Price-Anderson retrospective premiumrequirement.

Funding for public compensation following a major nuclear incident,therefore, would include the $300 million in insurance coverage carried by thereactor that suffered the incident, plus the $95.8 million in retrospective premiumsfrom each of the 103 currently covered reactors, totaling $10.2 billion. On top ofthose payments, a 5% surcharge may also be imposed, raising the total per-reactorretrospective premium to $100.6 million and the total potential compensation foreach incident to about $10.7 billion. Under Price-Anderson, the nuclear industry'sliability for an incident is capped at that amount, which varies depending on thenumber of covered reactors, the amount of available insurance, and an inflationadjustment that is made every five years. Payment of any damages above thatliability limit would require congressional approval under special procedures in theact.

The Price-Anderson Act also covers contractors who operate hazardous DOEnuclear facilities. The liability limit for DOE contractors is the same as forcommercial reactors, excluding the 5% surcharge, except when the limit forcommercial reactors drops because of a decline in the number of covered reactors. Because two closed reactors had been covered until recently (for a total of 105), theliability limit for commercial reactors, minus the surcharge, had been $10.4 billion,which remains the liability limit for DOE contractors. Price-Anderson authorizesDOE to indemnify its contractors for the entire amount, so any damage payments fornuclear incidents at DOE facilities would ultimately come from the U.S. Treasury. However, the law also allows DOE to fine its contractors for safety violations, andcontractor employees and directors can face criminal penalties for "knowingly andwillfully" violating nuclear safety rules. However, Section 234A of the AtomicEnergy Act specifically exempts seven non-profit DOE contractors and theirsubcontractors. Under the same section, DOE automatically remits any civilpenalties imposed on non-profit educational institutions serving as DOE contractors.

Policy Context. The Price-AndersonAct's limits on liability were crucial in establishing the commercial nuclear powerindustry in the 1950s. Supporters of the Price-Anderson system contend that it hasworked well since that time in ensuring that nuclear accident victims would have asecure source of compensation, at little cost to the taxpayer. However, opponentscontend that Price-Anderson subsidizes the nuclear power industry by protecting itfrom some or most of the financial consequences of the worst conceivable accidents.

Because no new U.S. reactors are currently planned, missing the deadline forextension has had little immediate effect on the nuclear power industry, as existingreactors continue to be covered. For the first time in more than 20 years, however,several U.S. utilities have announced that they are considering whether to build newreactors. It is unlikely that any such projects would move forward withoutPrice-Anderson coverage. A lapse in Price-Anderson would also affect allsubsequently signed DOE nuclear facility contracts, which would have to usealternate indemnification authority.

Appendix E: Electric Reliability Standards (Sec. 1211)

In both the House- and Senate-passed bills, this provision would require thatFERC establish a regional advisory body if requested by at least two-thirds of thestates within a region that have more than half of their electric load served within thatregion. The advisory body would be composed of one member from eachparticipating state in the region, appointed by the Governor of each state, and couldprovide advice to the ERO or FERC on reliability standards, proposed regionalentities, proposed fees, and any other responsibilities requested by FERC. The entirereliability provision would not apply to Alaska or Hawaii. Under the House version,the state of New York would be authorized to develop rules that would result ingreater reliability for New York, as long as those rules do not result in lowerreliability for neighboring states.

Both House- and Senate- passed H.R. 6 would require the EROto be funded through contributions from its utility members. The CongressionalBudget Office (CBO) determined that, under the Unfunded Mandates Reform Act(UMRA) of 1995, (9) these contributions would constitute an unfundedmandate both on the private sector and intergovernmentally, because both privatesector utilities and those run by local governments (munis) would be obligated tocontribute. The House-passed H.R. 6 would limit the total amount "of alldues, fees, and other charges collected by the ERO" to $50,000,000 annually, withno adjustment for inflation, through 2015. This limit was initially included in theHouse-passed H.R. 6 to avoid a point of order based on the budgetresolution. UMRA limits would not apply to dues collected from Canadian utilities,and it is unclear whether the $50,000,000 limit on the ERO budget applies to feescollected from U.S. and Canadian utilities or just the U.S. utilities'contributions. (10) This limit would restrict the cost of this mandateto less than the threshold at which UMRA subjects congressional consideration oflegislation containing intergovernmental mandates to a point of order. The 2005budget for NERC and all of its regional entities, however, is $51,950,000, of whichmunis contributed approximately $6,370,000, and the ERO would be required toengage in functions beyond what NERC already performs. One new function is theability of the ERO to impose and collect penalties. A $50,000,000 cap on all dues,fees, and other charges that can be collected by the ERO could limit the penalties thatcould be collected by the ERO.

CBO provided no separate estimate for the cost of the mandates in thissubtitle, but estimated that House-passed H.R. 6 as a whole containsboth intergovernmental and private sector unfunded mandates that would exceed theapplicable thresholds. The CBO estimate stated that the cost of complying withintergovernmental mandates, in aggregate, could be significant and likely wouldexceed the threshold established in UMRA ($62 million in 2005, adjusted annuallyfor inflation) at some point over the next five years because CBO expects futuredamage awards for state and local governments under the bill's safe harbor provision(title XV) would likely be reduced. (11)

House-passed Section 1211(c) would authorize to be appropriated not morethan $50 million per year for fiscal years 2006 through 2015 for all activities underthe amendment to the Federal Power Act that creates the ERO. This is in additionto the dues paid by the ERO members. It is unclear whether FERC would be thesole recipient of the $50 million annual authorization since section 1211(b)specifically states that the ERO, and its regional entities, are not Departments,agencies, or instrumentalities of the United States Government.

The proposed legislation is intended to provide federal jurisdiction overactivities that are required to support reliability of the U.S. bulk power system. Clarifying FERC authority to establish and regulate an ERO is intended to improvereliability as restructuring of the U.S. bulk power system proceeds. Similarprovisions were included in the conference report of H.R. 6 in the 108thCongress.

Advocates of giving FERC authority over the ERO contend that centraljurisdiction would provide more accountability. FERC would be ultimatelyresponsible for reliability issues. If the penalties employed by the ERO were notsuccessful, then FERC would have the authority to enforce penalties for entities thatdid not comply with reliability standards. Establishing this new relationship betweenFERC and the ERO would have the potential to improve coordination betweenmarket functions and reliability functions. Similar legislation has been introducedduring the past several sessions of Congress, but has not been enacted, despitegeneral support. Minor opposition to this proposal has centered on giving FERCjurisdiction over bulk power system reliability, contending that FERC has noexperience in this area. If FERC is given this authority, it would have to rely on theERO for much of its expertise. Placing FERC in this position may add to theuncertainty associated with the changes in institutional structure as FERC takes onthis new role.

Appendix F: Standard Market Design (House Sec. 1235, Senate Sec. 1234)

Under the NOPR, FERC would assert jurisdiction over all powertransmission, including service to bundled retail customers. Commissioners from 15states (Alabama, Arkansas, California, Georgia, Idaho, Kentucky, Louisiana,Mississippi, New Hampshire, North Carolina, South Carolina, Oregon, SouthDakota, Washington, and Wyoming) have argued that the SMD proposal usurps stateauthority. On August 15, 2002, state regulators from 22 states and the District ofColumbia (Illinois, Indiana, Iowa, Michigan, Minnesota, Missouri, Montana, NorthDakota, Ohio, Oklahoma, Texas, Wisconsin, Delaware, the District of Columbia,New Jersey, New York, Pennsylvania, West Virginia, Connecticut, Maine,Massachusetts, New Hampshire, and Rhode Island) released a statement that "voicedsupport for FERC's ongoing effort to remedy undue discrimination in the use of thenation's interstate high voltage transmission system in order to create a trulycompetitive bulk power market." Some industry groups have voiced concerns aboutthe implementation of SMD.

On April 28, 2003, FERC staff issued Wholesale Power Market Platform , aWhite Paper intended to clarify FERC's SMD proposal. The White Paper respondsto approximately 1,000 sets of formal comments submitted to FERC. In the WhitePaper, FERC states its intention to eliminate a proposed requirement that utilities joinan Independent Transmission Provider. Instead, the final rule would require utilitiesto join an RTO or ISO. In the NOPR, FERC proposed to assert jurisdiction over thetransmission component of bundled retail service. The White Paper reverses thisposition and states that the final rule will not assert new FERC jurisdiction overbundled retail sales.

Some state officials have expressed concern that the proposed rule wouldinfringe on state authority. FERC responded to this in the White Paper by clarifyingthat the final rule would not include a requirement for a minimum level of resourceadequacy. In addition, the final rule would eliminate the NOPR's requirement thatFirm Transmission Rights be auctioned. The White Paper noted that each RTO orISO would need to have a cost recovery policy outlined in its tariff, but each regionmay differ on how participant funding would be used. In addition, FERC stated thatthe final rule would allow for phased implementation to address regional differences.

The report language that accompanied the FY2003 ConsolidatedAppropriations Resolution asked the Department of Energy to analyze the SMDNOPR's impact on wholesale electricity prices, and the safety and reliability ofgeneration and transmission facilities. (12) DOE issued its report to Congress on April 30,2003, but did not include changes from FERC's White Paper in its analysis. DOE,in part, quantitatively analyzed the wholesale and retail price impacts of SMD usingtwo economic models: General Electric's Multi-Area Production Simulation (MAPS)and DOE's Policy Office Electricity Modeling System (POEMS).

Some of the assumptions that DOE uses are: the annual increase in electricitydemand is assumed to be approximately 1.8% per year from 2005 to 2020; mostregions are assumed to have reserve margins of 15%; current environmental laws andregulations are assumed to apply; generator efficiency for fossil steam plants isassumed to be 2% to 4% higher in new RTO regions with SMD. In the non-SMDcase, the models were not able to take into account freezes on retail rates in statesthat are transitioning to competitive markets, and no increase in transmission capacityis assumed. Under the SMD case, a 5% increase in transmission capability by 2005is assumed by DOE due to improved operational efficiency at regional seams. Inaddition, DOE assumes that adopting the SMD would result in some savings that aredifficult to quantify but would be a result of several factors including theconsolidation of control areas from the currently existing 150, the possible avoidanceof capital cost and software expenditures that would have been needed at existingcontrol centers, improved regional planning, and consistency of market design. DOEassigns a 10% savings due to these efficiency improvements. DOE believes that theassumptions used in the models are conservative and result in an underestimation ofthe net economic benefits of the SMD.

DOE calculates the median cost of FERC's SMD rule to be about $760million per year, or about 21 cents per megawatt-hour. The model's range foruncertainties is estimated to be about $100 million. The cost varies significantly byregion, ranging from 47 cents per megawatt-hour for GridFlorida to 12 cents permegawatt-hour for PJM. (13) Regions with existing RTOs have zero additionalcosts. Under the SMD case, the effects of SMD on retail rates are influenced to asignificant extent by whether the states in question have cost-of-service regulationor competitive retail choice. DOE found that for some importing regions withcost-based rates, the net result could be increased costs associated with wholesalepurchases, which would be passed through to retail customers. For some exportingregions with cost-based rates, additional utility revenues from exports are expectedto lead to lower retail prices for the region under the SMD case. In contrast, inregions in which most states have adopted retail choice, increased electricity exportsare expected to lead to higher market-clearing prices in the short-term markets andsomewhat higher consumer prices. However, in areas such as California that areprojected to see increased imports, lower wholesale prices and lower prices forconsumers are expected. DOE found that the magnitude of the projected changes,both positive and negative, decreases through 2020. Overall, DOE projects the netbenefit for all consumers would be about $1 billion per year over the first six years,after factoring in the estimated $760 million per year and RTO costs. Over thelong-term (2016-2020), the net benefit is expected to be about $700 million per year. However, the projected change in retail prices varies by region. The mid-Atlanticregion is expected to see a 4% decrease in retail prices, but Illinois, Wisconsin, andArizona are expected to have a 3% increase in retail prices as a result of SMD.

Appendix G: Cogeneration and Small Power Production Purchase and Sale Requirements (Sec. 1253)

In addition to PURPA, the Fuel Use Act of 1978 (FUA) helped qualifyingfacilities (QFs) become established. (14) Under FUA, utilities were not permitted to usenatural gas to fuel new generating technology. QFs, which are by definition notutilities, were able to take advantage of abundant natural gas as well as newgenerating technology, such as combined-cycle plants that use hot gases fromcombustion turbines to generate additional power. These technologies lowered thefinancial threshold for entrance into the electricity generation business as well asshortened the lead time for constructing new plants. FUA was repealed in 1987, butby this time QFs and small power producers had gained a portion of the totalelectricity supply.

This influx of QF power challenged the cost-based rates that previouslyguided wholesale transactions. Before implementation of PURPA, FERC approvedwholesale interstate electricity transactions based on the seller's costs to generate andtransmit the power. Since nonutility generators typically do not have enough marketpower to influence the rates they charge, FERC began approving certain wholesaletransactions whose rates were a result of a competitive bidding process. These ratesare called market-based rates.

This first incremental change to traditional electricity regulation started amovement toward a market-oriented approach to electricity supply. Following theenactment of PURPA, two basic issues stimulated calls for further change: whetherto encourage nonutility generation and whether to permit utilities to diversify intonon-regulated activities.

The Energy Policy Act of 1992 (EPACT) removed several regulatory barriersfor entry into electricity generation to increase competition of electricity supply. (15) However,EPACT does not permit FERC to mandate that utilities transmit exempt wholesalegenerator (EWG) power to retail consumers (commonly called "retail wheeling" or"retail competition"), an activity that remains under the jurisdiction of state publicutility commissions. PURPA began to shift more regulatory responsibilities to thefederal government, and EPACT continued that shift away from the states by creatingnew options for utilities and regulators to meet electricity demand.

Proponents of PURPA repeal -- primarily investor-owned utilities (IOUs)located in the Northeast and in California -- argue that their state regulators'"misguided" implementation of PURPA in the early 1980s has forced them to paycontractually high prices for power they do not need. They argue that, given thecurrent environment for cost-conscious competition, PURPA is outdated. ThePURPA Reform Group, which promotes IOU interests, strongly supports repeal ofÂ§210 of PURPA contending that the current law's mandatory purchase obligation isanti-competitive and anti-consumer.

Opponents of mandatory purchase requirement repeal (independent powerproducers, industrial power customers, most segments of the natural gas industry, therenewable energy industry, and environmental groups) have many reasons to supportPURPA as it stands. Mainly, their argument is that PURPA introduced competitionin the electric generating sector and, at the same time, helped promote wider use ofcleaner, alternative fuels to generate electricity. Since the electric generating sectoris not yet fully competitive, they argue, repeal of PURPA would decreasecompetition and impede the development of the renewable energy industry. Additionally, opponents of PURPA repeal argue that it would result in lesscompetition and greater utility monopoly control over the electric industry. Somestate regulators have expressed concern that Â§210 repeal would prevent them fromdeciding matters currently under their jurisdiction.

Appendix H: Repeal of the Public Utility Holding Company Act of 1935 (House Sec. 1263, Senate Sec. 1273)

Historically, electricity service was defined as a natural monopoly, meaningthat the industry has (1) an inherent tendency toward declining long-term costs, (2)high threshold investment, and (3) technological conditions that limit the number ofpotential entrants. In addition, many regulators have considered unified control ofgeneration, transmission, and distribution as the most efficient means of providingservice. As a result, most people (about 75%) are currently served by a verticallyintegrated, investor-owned utility.

As the electric utility industry has evolved, however, there has been a growingbelief that the historic classification of electric utilities as natural monopolies hasbeen overtaken by events and that market forces can and should replace some of thetraditional economic regulatory structure. For example, the existence of utilities thatdo not own all of their generating facilities, primarily cooperatives and publiclyowned utilities, has provided evidence that vertical integration has not been necessaryfor providing efficient electric service. Moreover, recent changes in electric utilityregulation and improved technologies have allowed additional generating capacityto be provided by independent firms rather than utilities.

The Public Utility Holding Company Act and the Federal Power Act (FPA)of 1935 (Title I and Title II of the Public Utility Act) established a regime ofregulating electric utilities that gave specific and separate powers to the states and thefederal government. A regulatory bargain was made between the government andutilities. In exchange for an exclusive franchise service territory, utilities mustprovide electricity to all users at reasonable, regulated rates. State regulatorycommissions address intrastate utility activities, including wholesale and retailrate-making. State authority currently tends to be as broad and as varied as the statesare diverse. At the least, a state public utility commission will have authority overretail rates, and often over investment and debt. At the other end of the spectrum, thestate regulatory body will oversee many facets of utility operation. Despite thisdiversity, the essential mission of the state regulator in states that have notrestructured is the establishment of retail electric prices. This is accomplishedthrough an adversarial hearing process. The central issues in such cases are the totalamount of money the utility will be permitted to collect and how the burden of therevenue requirement will be distributed among the various customer classes(residential, commercial, and industrial).

Under the FPA, federal economic regulation addresses wholesale transactionsand rates for electric power flowing in interstate commerce. Federal regulationfollowed state regulation and is premised on the need to fill the regulatory vacuumresulting from the constitutional inability of states to regulate interstate commerce. In this bifurcation of regulatory jurisdiction, federal regulation is limited andconceived to supplement state regulation. FERC has the principal functions at thefederal level for the economic regulation of the electric utility industry, includingfinancial transactions, wholesale rate regulation, transactions involving transmissionof unbundled retail electricity, interconnection and wheeling of wholesale electricity,and ensuring adequate and reliable service. In addition, to prevent a recurrence of theabusive practices of the 1920s (e.g., cross-subsidization, self-dealing, pyramiding,etc.), SEC regulates utilities' corporate structure and business ventures underPUHCA.

The electric utility industry has been in the process of transformation. Duringthe past two decades, there has been a major change in direction concerninggeneration. First, improved technologies have reduced the cost of generatingelectricity as well as the size of generating facilities. Prior preference for large-scale -- often nuclear or coal-fired -- powerplants has been supplanted by a preference forsmall-scale production facilities that can be brought on line more quickly andcheaply, with fewer regulatory impediments. Second, this has lowered the entrybarrier to electricity generation and permitted non-utility entities to build profitablefacilities.

One argument for additional PUHCA change has been made by electricutilities that want to further diversify their assets. Currently under PUHCA, aholding company can acquire securities or utility assets only if the SEC finds thatsuch a purchase will improve the economic efficiency and service of an integratedpublic utility system. It has been argued that reform to allow diversification wouldimprove the risk profile of electric utilities in much the same way as in otherbusinesses: the risk of any one investment is diluted by the risk associated with allinvestments. Utilities have also argued that diversification would lead to better useof under-utilized resources (due to the seasonal nature of electric demand). Utilityholding companies that have been exempt from SEC regulation argue that PUHCAdiscourages diversification because the SEC could repeal exempt status if exemptionwould be "detrimental to the public interest."

For a number of years there has been significant bipartisan congressionalsupport for repealing much of PUHCA. Since the 1980s, the Securities andExchange Commission has testified before Congress that many provisions ofPUHCA are no longer relevant and other provisions are redundant with state andother federal regulations. (16) However, as a result of Enron's dealings andcollapse, some in Congress have taken a somewhat different view towardsignificantly amending or repealing PUHCA. (17) Eventhough Enron had claimed exemption from PUHCA, on February 6, 2003, Securitiesand Exchange Commission Chief Administrative Law Judge Brenda P. Murraydenied Enron's PUHCA exemption applications of April 12, 2000, and February 28,2002, amended on May 31, 2002. (18) In the case of Enron, PUHCA, and many otherlaws, did not deter or prevent fraudulent filing of information with the SEC.

State regulators have expressed concerns that increased diversification couldlead to abuses, including cross-subsidization: a regulated company subsidizing anunregulated affiliate. Cross-subsidization was a major argument against the creationof exempt wholesale generators (EWGs) and has reemerged as an argument againstfurther PUHCA change. In the case of electric and gas companies, non-utilityventures that are undertaken as a result of diversification may benefit from theregulated utilities' allowed rate of return. Moneymaking non-utility enterpriseswould contribute to the overall financial health of a holding company. However,unsuccessful ventures could harm the entire holding company, including utilitysubsidiaries. In this situation, opponents fear that utilities would not be penalized forfailure in terms of reduced access to new capital, because they could increase retailrates.

Appendix I: Continuation of Transmission Security Order (Sec. 1441)

In 2002, a 24-mile 330-megawatt (MW) transmission cable was installedbeneath the seabed of Long Island Sound between Connecticut and Long Island. Shortly after the line was installed, it was determined that in several places the cablewas not buried to depths specified in permits issued by the U.S. Army Corps ofEngineers (Corps) and the Connecticut Department of Environmental Protection(CDEP). While the Corps determined that operation of the cable would not poseenvironmental or navigational harm and did not object to the operation of thetransmission line, the CDEP objected to the operation of the line based on proceduralgrounds. CDEP's position was that operation of the cable would violate the permit,unless the cable was installed to the permitted depth requirements. CDEP denied arequest to modify the permit.

On June 12, 2003, Cross-Sound, the owners of the cable, filed a new permitapplication with the CDEP. However, on June 26, 2003, Connecticut Governor JohnRowland signed into law a bill extending a prohibition on considering permits orapplications related to certain infrastructure crossings of the sound. On August 14,2003, the Northeast experienced a widespread electric blackout. In response,Secretary of Energy Spencer Abraham issued an emergency order to energize thecross-sound cable. This order was rescinded on May 7, 2004. Long Island PowerAuthority (LIPA) and Cross-Sound filed a petition with FERC to have the cablere-energized by July 1, 2004. At a June 17, 2004, FERC meeting, Chairman PatWood asked the parties to negotiate a settlement within seven days, after whichFERC was ready to issue an order. On June 25, 2004, the parties came to anagreement and the cross-sound cable was re-energized.

Appendix J: Deadline for Decision on Appeals under the Coastal Zone Management Act (Sec. 2013)

Current Law. The consistencyprovisions in Section 307 of the CZMA guides state consideration of whether aproposed federal activity will be compatible with a federally approved andstate-administered coastal zone management plan. Since the first state plan wasapproved in the mid-1970s, there has been considerable friction between states andfederal agencies over the reach of the consistency provisions. States have soughtbroader application to have a strong role in decisions about the largest possible arrayof proposed federal activities, while the federal government has sought narrowerinterpretations, especially relating to offshore energy development. Determining anexact boundary separating actions on which the state is to have a primary role inhalting a proposal from actions on which the state does not have such powers hasbeen a subject of federal appeals and litigation, including decisions by the U.S.Supreme Court (notably Secretary of the Interior v. California , 464 U.S. 312 (1984)),in which the court determined that the sale of oil and gas leases on the outercontinental shelf was not an act affecting the coastal zone).

When a state and a federal agency cannot reach an agreement on aconsistency determination, the law and regulations lay out an elaborate process forresolving that disagreement. Most disagreements are resolved through this process,but if no agreement can be reached, the final step is an appeal to the Secretary ofCommerce to make a decision. Appeals to the Secretary have not been common. According to citations of appeals posted on the website of the Office of Ocean andCoastal Resource Management in the National Oceanic and AtmosphericAdministration (NOAA) (viewed May 12, 2005), 38 consistency determinations wereappealed to the Secretary between 1984 and 1999, and 19 of them involved proposedactivities by oil companies. The appeals process, like all other aspects of consistency,is currently covered under a final rule issued by NOAA in the December 8, 2000, Federal Register.

Section 319 in current law has less detail than the proposed amendment. Itstates that the Secretary will either issue a final decision on the appeal or publish anotice in the Federal Register stating why a decision cannot be reached within 90days after the record has closed. If the Secretary publishes a notice that a decisionhas not been made, that decision must be issued within 45 days of the date ofpublication of that notice.

Policy Context. Consistency appealshave been contentious and, in some instances, the appeals process has dragged on forlong time periods. The 1996 amendments in Section 319 were meant to addressthose delays by establishing some time limits. This has proved unsatisfactory tosome, who seek additional statutory language that would remove decisions aboutdeadlines from the unpredictable rulemaking process by defining the length ofcomponent steps in law, and therefore the overall process, after an appeal to theSecretary has been filed.

The consistency provision creates an unusual relationship where states canhalt most federal actions that are incompatible with state interests. When enacted,the consistency requirement was viewed as a main reason why states would pursuedevelopment and implementation of coastal plans since the other incentive toparticipate, federal financial grants, always has been modest. This view appears tohave some validity, as 34 of the 35 eligible states and territories are nowadministering federally approved coastal management programs.

Appendix K: Domestic Offshore Energy Reinvestment (Sec. 2053)

Policy Context. This is the mostrecent of repeated efforts to allocate a portion of federal offshore oil and gas revenuesto coastal states to assist them in addressing the impacts of these activities. RecentCongresses, starting with the 105th, considered numerous similar legislativeproposals. These proposals came to be known as CARA, or the Conservation andReinvestment Act. In the 106th Congress, the House passed a version of CARA onMay 11, 2000 ( H.R. 701 ). Some of these proposals were also reflectedin the Clinton Administration's Lands Legacy Initiative proposal in 2000, and alsoa one-time $150 million appropriation provided in the FY2001 Commerceappropriations legislation ( P.L. 106-553 ) for coastal impact assistance.

Support for the CARA proposals, which would also have funded many relatedfederal natural resource protection programs, grew as the budget deficit of the earlyand mid-1990s was replaced by forecasts of a surplus, as protecting natural resourcescame to be viewed as part of the effort to address sprawl, and as efforts and supportto secure federal funding for coastal resource protection and restoration efforts grew. With the replacement of the budget surplus forecast with deficit forecasts andchanging national priorities since the 9/11 terrorist attacks, broad support forwide-ranging legislation like CARA has declined, but interest has remained inreturning a portion of the money currently paid to the federal government by privatecompanies leasing offshore areas to those locations most affected by the offshoreactivity.