参考資料2 「Legislation and Regulations」

　

Because analyses by the Energy Information Administration (EIA) are required to be policy-neutral,the projections in this Annual Energy Outlook 2002 (AE02002) are based on Federal, State, and local laws and regulations in effect on September 1,2001. The potential impacts of pending or proposed legislation,regulations, and standards―and sections of existing legislation requiring funds that have not been appropriated―are not reflected in the projections.

　

Federal legislation incorporated in the projections includes the National Appliance Energy Conservation Act of 1987; the Clean Air Act Amendments of 1990 (CAAA90); the Energy Policy Act of 1992 (EPACT); the Omnibus Budget Reconciliation Act of 1993,which added 4.3 cents per gallon to the Federal tax on highway fuels [1] ;the Outer Continental Shelf Deep Water Royalty Relief Act of 1995; the Tax Payer Relief Act of 1997; the Federal Highway Bill of 1998, which included an extension of the ethanol tax incentive; new standards for motor gasoline and diesel fuel and for heavy-duty vehicle emissions; and the new standards for energy-consuming equipment that were announced in 2001. AEO2002 assumes the continuation of the ethanol tax incentive through 2020. AEO2002 also assumes that State taxes on gasoline, diesel, jet fuel, M85, and E85 will increase with inflation and that Federal taxes on those fuels will continue at 2000 levels in nominal terms. Although the above tax and tax incentive provisions include "sunset" clauses that limit their duration, they have been extended historically, and AEO2002 assumes their continuation throughout the forecast.

　

AEO2002 also incorporates regulatory actions of the Federal Energy Regulatory Commission (FERC),including Orders 888 and 889, which provide open access to interstate transmission lines in electricity markets, and other FERC actions to foster more efficient natural gas markets. State plans for the restructuring of the electricity industry and State renewable portfolio standards are incorporated as enacted. As of July 1,2001, 24 States and the District of Columbia had passed legislation or promulgated regulations to restructure their electricity markets. The projections include recently announced delays in restructuring in several States. In California, retail competition has been suspended.

　

CAAA90 requires a phased reduction in vehicle emissions of regulated pollutants, to be met primarily through the use of reformulated gasoline. In addition, under CAAA90, there is a phased reduction in annual emissions of sulfur dioxide by, electricity generators, which in general are capped at 8.95 million tons per year in 2010 and thereafter although "banking" of allowances from earlier years is permitted. CAAA90 also calls for the U.S. Environmental Protection Agency (EPA) to issue standards for the reduction of nitrogen oxide (NOx) emissions; the forecast includes NOx caps for States where they have been finalized. The impacts of CAAA90 on electricity generators are discussed in "Market Trends" (see page 100).

　

The provisions of EPACT focus primarily on reducing energy demand. They require minimum building efficiency standards for Federal buildings and other new buildings that receive federally backed mortgages. Efficiency standards for electric motors, lights, and other equipment are required, and Federal, State, and utility vehicle fleets are required to phase in vehicles that do not rely on petroleum products. The projections include only those equipment standards for which final actions have been taken and for which specific efficiency levels are provided. A discussion of the status of efficiency standards is included later in this section.

　

Energy combustion is the primary source of anthropogenic (human-caused) carbon dioxide emissions. AEO2002 estimates of emissions do not include emissions from activities other than fuel combustion, such as landfills and agriculture, nor do they take into account "sinks" that absorb carbon dioxide, such as forests.

　

The AEO2002 reference case projections include analysis of the programs in the Climate Change Action Plan (CCAP)―44 actions developed by the Clinton Administration in 1993 to achieve the stabilization of greenhouse gas emissions (carbon dioxide, methane, nitrous oxide, and others) in the United States at 1990 levels by 2000. CCAP was formulated as a result of the Framework Convention on Climate Change, which was adopted at the United Nations on May 9, 1992, and opened for signature at Rio de Janeiro on June 4, 1992. As part of the Framework Convention, the economically developed signatories, including the United States, agreed to take voluntary actions to reduce emissions to 1990 levels. Of the 44 CCAP actions, 13 are not related either to energy combustion or to carbon dioxide and, consequently, are not incorporated in the analysis.

　

Although CCAP did not achieve the goal of reducing greenhouse gas emissions to 1990 levels by 2000 and no longer exists as a unified program, most of the individual programs, which are generally voluntary, remain. The impacts of those programs are included in the projections. The projections do not include carbon dioxide mitigation actions that may be enacted as a result of the Kyoto Protocol, which was agreed to on December 11, 1997, but has not been ratified, or other international agreements. The Kyoto Protocol, for which the Bush Administration has announced it will not seek ratification, and the status of international negotiations on climate change are discussed later in this section.

　

　

California formally ended competition (direct access) in its retail electricity market in September 2001, after a year and a half of very high wholesale prices exposed market design failures, forced competitive suppliers from the market, raised retail prices, and caused the bankruptcy of the State's largest utility [2]. California's energy crisis has led some States that were in the process of implementing electricity market restructuring legislation to postpone implementation and has forced other States in the process of negotiating the terms of restructuring legislation to rethink their priorities. The biggest fear among the States is that inadequate supply will allow a few suppliers to assert market power and raise prices beyond acceptable levels. States are also considering whether their transmission capacity is adequate to ensure a viable marketplace, and how to give electricity consumers more options for responding to price signals.

　

In March 2001, Nevada, New Mexico and Arkansas delayed the opening of their retail electricity markets to competition. Nevada's Governor halted the implementation of electric utility deregulation indefinitely―until such time as "the market stabilizes, adequate consumer protections are in place, and supply is at an acceptable level." New legislation in Nevada has re-regulated the State's utilities, delaying the sale of their power plants. At the same time, large customers with time-of-use meters (to be installed by the utility at the cost of the provider or customer) will be allowed to choose their suppliers and residential customers with renewable. distributed generators will be offered net metering [3].

　

New Mexico enacted new legislation to delay the opening of its retail electricity market to competition until 2007. The law also delays Public Service of New Mexico's unbundling of its distribution business from its generation and marketing businesses and allows the utilitly to proceed with plans to build new generation capacity and form a holding company.

　

Arkansas put off the start of deregulation from January 2002 to October 2003. The Arkansas Public Service Commission (PSC) is also authorized to initiate further delays based on the adequacy of the State's transmission system and generating capacity to support a competitive market. The PSC issued a request for utilities to provide an analysis of prices customers may pay for electric generation service under open access as compared with continued regulation, and to provide the information needed to evaluate the readiness of both retail and wholesale markets for implementation of retail open access.

　

Legislation was enacted to revise Oregon's restructuring law in August 2001, delaying the date for implementing retail access for large customers from October 2001 to March 2002. Most other provisions of Oregon's plans for restructuring were also delayed for 6 months to March 2002, including allowing residents to choose from a portfolio of retail options.

　

In June 2001, Oklahoma delayed retail competition. New legislation established a nine-member task force to study the effects of deregulation Competition, originally scheduled to be phased in from January 2002 to January 2004, will be put off until (1) the task force issues its final report, not later than December 2002, and (2) the legislature enacts enabling restructuring legislation.

　

In November 2000, the Montana Public Service Commission delayed the date for instituting complete retail access for all consumers from July 2002 to July 2004, because the State does not have a competitive power supply market in place. Most rural electric cooperatives have opted not to restructure or offer retail choice. Also, Montana Power customers have not been switching to retail choice in large numbers.

　

In light of the low cost of electricity in West Virginia and the price spikes that occurred this past summer in other States that have restructured retail markets, legislation was passed in October 2000 to require the 2001 West Virginia Legislature to pass a resolution before the provisions of the restructuring law can take effect. Consumer choice was to have started in January 2001. As of October 2001, no resolution had been passed.

　

North Carolina's legislation study panel decided in January 2001 that more study of restructuring issues was needed before recommending that the legislature open the State to competition by 2005, as previously recommended. The studies will focus on consumer protections and ways to encourage power plant construction in the State. In December 2000, the North Carolina Public Utilities Commission (PUC) staff recommended a limited deregulation plan to a legislative panel. In light of California's experience, the PUC recommended that restructuring in North Carolina proceed slowly and with caution.

　

　

Although many States delayed restructuring plans, others forged ahead by implementing restructuring on time or improving market designs to increase the competitiveness of their markets. Arizona, Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Pennsylvania, and Rhode Island had full or partial competitive retail markets in place before 2001 and are proceeding as scheduled with full implementation of their restructuring plans.

　

Both the District of Columbia and Ohio began allowing customers direct access to competitive electricity suppliers on January l, 2001, as mandated by restructuring legislation. Also in January 2001, the New Hampshire Supreme Court upheld New Hampshire's restructuring plan, clearing the way for competition to begin for the majority of consumers in April 2001.

　

Texas was still set to start full retail, competition by January 2002, although pilot programs got started two months late. In September 2001, utilities in Texas began the process of auctioning part of their generating capacity. Restructuring legislation requires each generation company affiliated with a former monopoly utility to sell at least 15 percent of its installed generation capacity at least 60 days before full retail competition begins.

　

Pennsylvania amended its restructuring rules to allow competitive suppliers to bid for default customers, in order to ensure that more suppliers will stay in the market. In January 2001, as required under the Philadelphia Electric Company (PECO) restructuring plan, 300,000 residential customers who had not chosen a competitive supplier were randomly chosen and switched to The New Power Company, which was chosen by PECO to provide "Competitive Discount Service" from March 2001 through January 2004. Customers may opt out of the program or choose another electricity supplier without penalty.

　

In March 2001, Virginia passed legislation allowing competitive suppliers to bid to supply "last resort" customers―those customers without access to other competitive retail options. In July 2001, the Virginia State Corporation Commission adopted rules to advance a competitive energy supply market and protect customers who shop for alternative electricity suppliers when the retail market opens―on time―in January 2002.

　

The New York PSC spent 2001 fine-tuning its competitive market design. In March, the bill credit (shopping credit) a customer could receive for switching to a lower cost supplier was increased to encourage more suppliers to enter the market. The new shopping credit is tied to the going market price to make it easier for suppliers to deal with fluctuating wholesale prices. It also includes a small amount to cover administrative costs. The old shopping credit, which had been set below market prices, discouraged suppliers from entering the market. In June, the PSC approved standards governing the electronic exchange of routine business information and data among electricity and natural gas service providers in New York. The PSC also issued an order in June to establish uniform retail access billing and payment processing practices that will facilitate a single-bill option for customers who buy power and/or natural gas from energy service companies. The orders are designed to facilitate retail energy competition in New York and provide for effrcient single-billing options for all New York electricity and natural gas customers.

　

In Washington State, a May 2001 agreement between Puget Sound and its six largest industrial customers allows them to buy power from any source. In January 2OO1, the Florida PSC issued a draft restructuring plan that would allow large industrial customers retail choice starting in January 2003. In March 2001, the legislatively mandated Energy 2020 Study Commission released an interim report, Proposal for Restructuring Florida's Wholesale Market for Electricity. The report made recommendations to the 2001 legislature that would result in the development of a competitive wholesale electricity market in Florida. Proposals included removing barriers to entry for merchant generation plants, requiring investor-owned load-serving utilities to acquire energy resources through a competitive acquisition process, and allowing utility affiliate companies to assume ownership of existing generation assets and to build new ones.

　

In January 2001, the Louisiana PSC issued a draft restructuring plan that would allow large industrial customers in Louisiana retail choice starting in January 2003. In March 2001, the staff of the PSC issued its final report, Final Response of the Commission Staff to Comments on Proposed Competitive Transition Plan. The report recommends some changes to the transition plan issued in January, including allowing open access to competitive service providers only for large industrial customers with loads averaging 5 megawatts or more rather than the original 2-megawatt load. Although the PSC ruled 2 years ago that open access was not in the State's best interest, study of the issue has continued in light of concerns about economic development. The report recommends another study, due in 2005, to determine whether competition would benefit all classes of customers.

　

Changes to the AEO2002 projections as a result of State legislation and regulation were minor, with the exception of California. The changes that have resulted from California's legislative and regulatory developments throughout 2001 and their effects on the AEO2002 forecasts are discussed in "Issues in Focus," pages 28-35.

　

Since 1988, the U.S. Department of Energy (DOE) has promulgated numerous efficiency standards requiring the manufacture of appliances that meet or exceed minimum levels of efficiency as set forth by DOE test procedures. In 1987, Congress passed the National Appliance Energy Conservation Act (NAECA), which permitted DOE to establish test procedures and efficiency standards for 13 consumer products. Under the auspices of NAECA, DOE is responsible for revising the test procedures and efficiency levels as technology and economic conditions evolve over time.

　

From 1988 to 1995, DOE established and revised efficiency standards almost on an annual basis, as shown in Table 2. In 1995, however, Congress issued a standards moratorium for fiscal year 1996, which prohibited DOE from establishing any new standards. As a result of the moratorium, no standards were promulgated from 1996 through July 2000, After a reevaluation of the standards program, DOE established a new process that allows for greater input from stakeholders by creating the Advisory Committee on Appliance Energy Efficiency Standards, which comprises technical experts representing the concerns of industry, environmentalists, and the general public.

　

　

With input from stakeholders early in the promulgation process, it was believed that the rulemaking process would become more predictable, more timely, and less controversial. The refrigerator standard issued for July 2001, for example, was promulgated through a series of compromises in December 1996, allowing a later enforcement date but at a higher efficiency level. Achieving similar consensus among such disparate concerns as the natural gas and electric power industries and environmentalists may prove difficult, however, when multi-fuel products, such as water heaters, are considered for review. The debate over end-use efficiency versus total system efficiency is a lively one, with electric power and natural gas concerns generally disagreeing as to how efficiency and environmental benefits should be measured. In fact, the inability to create a single national home energy rating system (HERS) has shown that achieving consensus among these groups is difficult, signaling a continued debate as to how efficiency should be evaluated across fuel types.

　

In January 2001, DOE published final rules for several residential and commercial appliances, including residential water heaters, clothes washers, and central air conditioners and heat pumps, as well as commercial water-cooled cooling equipment and natural-gas-fired water heaters and furnaces. In July, however, DOE issued a Notice of Proposed Rulemaking (NOPR) withdrawing the final rulemaking for central air conditioners and heat pumps. The NOPR, which invited public comment through the end of September 2001, essentially replaced the 13 seasonal energy efficiency ratio (SEER) standard issued in January with a 12 SEER standard. The decision to lower the standard has brought legal action from the Natural Resources Defense Council (NRDC) and 3 States, which have sued DOE over the legality of withdrawing the original l3 SEER standard. For AEO2002, it is assumed that the 12 SEER standard will prevail in 2006, when it is scheduled to become effective.

　

Currently, DOE is evaluating standards for distribution transformers and residential furnaces and boilers. Because the AEO2002 reference case includes only standards that have been finalized, with the effective dates and efficiency levels specified in the Federal Register, these efficiency standards are not included in the projections.

　

As part of EPACT, Congress established a tax credit of 1.5 cents per kilowatthour for electricity produced from new renewable generators using wind or closed-loop biomass energy sources. (Closed-loop biomass plants use feedstocks derived from "energy crops" grown specifically for energy production.) The credit is applicable for 10 years after a qualifying facility has been placed in service. Originally set to expire in 1999, the credit was extended by Congress to cover new units entering service by December 31, 2001. The tax credit was indexed to inflation and currently is worth 1.7 cents per kilowatthour.

　

In August 2001, the U.S. House of Representatives passed the Securing America's Future Energy Act of 2001 (SAFE Act of 2001, currently bill H.R. 4). The SAFE Act would extend the renewable electricity production tax credit (PTC) for another 5 years, for new facilities on line through December 31, 2006, and would expand eligibility to open-loop biomass and landfill gas facilities. (Open-loop biomass plants use feedstocks derived as waste from other activities, such as agricultural residue, yard trimmings, and commercial wood waste.) Other similar proposals before Congress would extend the credit for various durations and expand it to different renewable generating technologies.

　

Because the legislation is. still pending, it is not incorporated in the AEO2002 reference case. Additional analysis indicates that the PTC provisions of H.R. 4 could have a significant effect on the targeted industries. By 2020, the tax credit could result in an additional 4 gigawatts of wind capacity (13 gigawatts with the PTC extension, compared with 9 gigawatts without), an additional 2 gigawatts of dedicated biomass capacity (4 gigawatts with the extension and expansion, compared with 2 gigawatts without), and an additional 1 gigawatt of landfill gas capacity (5 gigawatts with the extension and expansion, compared with 4 gigawatts without). If all the potential new renewable capacity were built, the nonhydroelectric renewable share of total U.S. electricity generation in 2020 could increase to 3.4 percent, as compared with 2.9 percent projected in the AEO2002 reference case.

　

In December 2000, the EPA finalized new regulations on heavy-duty engine and vehicle standards and highway diesel fuel sulfur control requirements [4]. The engine and vehicle standards will affect new heavy-duty vehicles sold in model years 2004, 2007, and 2010. In 2004, the standard requires that all new heavy-duty vehicles achieve a 40-percent reduction in emissions of nitrogen oxides (NOx) and hydrocarbons (HC). In 2007, the rule requires 50 percent of new heavy-duty vehicles sold to meet significantly more stringent emissions standards. The 2007 standards require a 92-percent reduction in NOx emissions and an 89-percent reduction in HC emissions from the 2004 standard. For model years 2007 through 2009, the EPA allows engine manufacturers flexibility in meeting the NOx and HC standards, in that they are given the option to produce lOO percent of their engines to meet an average of the 2004 and 2007 NOx and HC emissions standards. In 1998, the EPA signed consent decrees with several manufacturers of heavy-duty diesel engines,stating that they would produce engines to meet the 2004 emissions standards by October 2002. New standards for heavy-duty gasoline engines and vehicles will reduce both NOx and HC emissions for all vehicles above 8,500 pounds gross vehicle weight not covered in the Tier 2 standards, beginning in 2004.

　

The new rule requires refiners and importers to produce highway diesel fuel meeting a 15 parts per million (ppm) maximum requirement, starting June l, 2006; however, pipelines are expected to require refiners to provide diesel fuel with an even lower sulfur content, somewhat below 10 ppm, in order to compensate for contamination from higher sulfur products in the system and to provide a tolerance for testing. Diesel fuel meeting the new specification will be required at terminals by July 15, 2006, and at retail stations and wholesalers by September 1, 2006. Under a "temporary compliance option" (phase-in), up to 20 percent of highway diesel fuel produced may continue to meet the current 500 ppm sulfur limit through May 2010; the remaining 80 percent of the highway diesel fuel produced must meet the new 15 ppm maximum.

　

Analysis included in an EIA study conducted at the request of the EPA, The Transition to Ultra-Low-Sulfur Diesel Fuel: Effects on Prices and Supply, released in May 2001, indicated the possibility of a tight diesel market at the onset of the new 15-ppm sulfur maximum in June 2006 [5]. Given the EPA's assumptions for refinery equipment costs and return on investment, the EIA analysis concluded that increases in highway diesel costs of between 5.4 and 6.8 cents per gallon could be expected in the short run in Petroleum Administration for Defense Districts (PADDs) I through IV, and even higher increases would be expected if a shortfall in diesel supply occurred. The EPA has taken steps to monitor the ultra-low-sulfur diesel fuel (ULSD) supply situation. The EPA's Final Rulemaking requires refiners and importers expecting to produce highway diesel in 2006 to register with the EPA by December 31, 2001, and to provide annual updates of expected ULSD production capacity beginning in 2003.

　

EIA's study also included a longer term analysis of increases in the average annual end-use price of highway diesel, based on a range of different assumptions. Using a set of assumptions similar to those used by the EPA in its Regulatory Impact Analysis of the diesel rule, EIA estimated increases in the average U.S. end-use price ranging from 6.5 to 7.0 cents per gallon between 2007 and 2010. When a set of assumptions more consistent with previous industry analyses was used, price differentials ranged from 8.4 to 8.8 cents per gallon. The additional costs associated with complying with the new diesel regulation are included in the AEO2002 reference case, based on the specific assumptions discussed in Appendix G.

　

In addition to the new highway diesel regulation, the EPA is in the early planning stages of new standards for diesel fuel used for other purposes, or "non-road" diesel. Since the specifics of the non-road standards have yet to be proposed by EPA, no changes in non-road diesel quality are reflected in the AEO2002 reference case.