| Annual Energy Outlook 2005 Introduction Because analyses by the EIA are required to be policy-neutral, the projections in this AEO2005 generally are based on Federal and State laws and regulations in effect on or before October 31, 2004. The potential impacts of pending or proposed legislation, regulations, and standards—or of sections of legislation that have been enacted but that require funds or implementing regulations that have not been provided or specified—are not reflected in the projections. Examples of Federal and State legislation incorporated in the projections include the following:
AEO2005 assumes that State taxes on gasoline, diesel, jet fuel, and E85 (fuel containing a blend of 70 to 85 percent ethanol and 30 to 15 percent gasoline by volume) will increase with inflation, and that Federal taxes on those fuels will continue at 2003 levels in nominal terms. AEO2005 also assumes the continuation of the ethanol tax incentive through 2025. Although these tax and tax incentive provisions include “sunset” clauses that limit their duration, they have been extended historically, and AEO2005 assumes their continuation throughout the forecast. Examples of Federal and State regulations incorporated in AEO2005 include the following:
AEO2005 includes the CAAA90 requirement of a phased-in reduction in vehicle emissions of regulated pollutants. In addition, AEO2005 incorporates the CAAA90 requirement of a phased-in 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. AEO2005 also incorporates nitrogen oxide (NOx) boiler standards issued by the EPA under CAAA90. The 19-State NOx cap and trade program in the Northeast and Midwest is also represented. Limits on emissions of mercury, which have not yet been promulgated, are not represented. AEO2005 reflects “Tier 2” Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements finalized by the EPA in February 2000 under CAAA90. The Tier 2 standards for reformulated gasoline (RFG) were required by 2004 but will not be fully realized in conventional gasoline until 2008 due to allowances for small refineries. AEO2005 also incorporates the “ultra-low-sulfur diesel” (ULSD) regulation finalized by the EPA in December 2000, which requires the production of at least 80 percent ULSD (15 parts sulfur per million) highway diesel between June 2006 and June 2010 and a 100-percent requirement for ULSD thereafter (see Appendix F for more details). It also includes the new rules for nonroad diesel issued by the EPA on May 11, 2004, regulating nonroad diesel engine emissions and sulfur content in fuel. The AEO2005 projections reflect legislation that bans or limits the use of the gasoline blending component methyl tertiary butyl ether (MTBE) in the next several years in 17 States and assumes that the Federal oxygen requirement for RFG in Federal nonattainment areas will remain intact. 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 AEO2005 projections include only those equipment standards for which final actions have been taken and for which specific efficiency levels are provided. More detailed information on recent legislative and regulatory developments is provided below. 13 SEER Standard for Central Air Conditioners and Heat Pumps In January 2004, after years of litigation in a case that pitted environmental groups and Attorneys General from 10 States against the U.S. Secretary of Energy, the U.S. Court of Appeals for the Second Circuit reestablished the central air conditioner and heat pump standard originally set in January 2001 [3]. The Court’s ruling, which struck down a May 2002 rollback of the 2001 standard to a 12 SEER, mandates that all new central air conditioners and heat pumps meet a 13 SEER standard by January 2006, requiring a 30-percent increase in efficiency relative to current law. The AEO2005 reference case incorporates the 13 SEER standard as mandated by the Court’s ruling. In order to gauge the impact of the new standard on electricity consumption, consumer expenditures, and carbon dioxide emissions, a sensitivity case assuming a continuation of the previous 12 SEER standard was modeled. Table 2 shows the impacts of the 13 SEER standard assumed in the reference case, as compared with the 12 SEER standard assumed in the sensitivity case. As expected, the projections for electricity consumption and expenditures are lower in the reference case than in the 12 SEER case; however, the savings come at an additional cost to consumers. Through 2015 the additional costs of new equipment outweigh savings, resulting in a negative net present value for the 13 SEER standard (assuming a 7-percent real discount rate). In the long run, however, additional years of savings per unit provide a positive ($3.6 billion) net present value, meaning that the standard, on average, provides economic benefits to consumers in the form of reduced energy expenditures.
The difference between projected carbon dioxide emissions in the two cases depends on the fuel mix associated with the electricity generation. In the near term, the reduction in electricity demand in the reference case is not large enough to change the pattern of capacity additions or fuel mix, and lower electricity demand causes a decrease in carbon dioxide emissions both in 2015 and cumulatively from 2006 to 2015 (Table 2). In later years, the amount of peak demand relative to baseload demand is lower in the reference case, and more coal-fired capacity is added at the expense of natural gas capacity. The change in fuel mix causes carbon dioxide emissions to increase, despite slightly lower levels of electricity demand. Emissions in 2025 are 3.6 million metric tons (0.2 percent) higher in the reference case, but cumulative emissions from 2003 through 2025 are 1.0 million metric ton lower than in the 12 SEER case (1 metric ton is equal to 1,000 kilograms). Maximum Achievable Control Technology for New Industrial Boilers As part of CAAA90, the EPA on February 26, 2004, issued a final rule—the National Emission Standards for Hazardous Air Pollutants (NESHAP)—to reduce emissions of hazardous air pollutants (HAPs) from industrial, commercial, and institutional boilers and process heaters [4]. The rule requires industrial boilers and process heaters to meet limits on HAP emissions to comply with a MACT “floor level” of control that is the minimum level such sources must meet to comply with the rule. The major HAPs to be reduced are hydrochloric acid, hydrofluoric acid, arsenic, beryllium, cadmium, and nickel. The EPA predicts that the boiler MACT rule will reduce those HAP emissions from existing sources by about 59,000 tons per year in 2005 [5]. The MACT standards apply to major sources of HAPs, or units that emit or have the potential to emit a single HAP at 10 tons or more per year or a combination of HAPs at 25 tons or more per year. The EPA estimates that 58,000 existing boilers and process heaters and 800 new boilers and process heaters built each year over the next 5 years will be subject to the rule. Existing boilers and process heaters must comply with the rule no later than 3 years after it is published in the Federal Register. In addition, the owners of existing units may petition for an extra year to comply. New boilers and process heaters must comply when they are brought on line. The final rule provides flexibility in compliance through averaging of emissions from multiple units on a single site and lowering of emissions by altering work practices, installing control devices, or physically removing toxics. Fuel switching is not an available option to meet the MACT floor level, because it may increase emissions of some HAPs while reducing the emissions of others. The industries most affected by the rule will be furniture, paper, lumber, and electrical services, which together account for nearly 60 percent of the affected units. The EPA estimates the total nationwide capital costs for the final rule to be $1.4 billion to $1.7 billion over the first 5 years, with annualized costs between $690 million and $800 million. New boilers are expected to meet the standards in the absence of the rule, and retrofit costs are anticipated to be relatively small in aggregate. Consequently, inclusion of the rule does not materially affect the AEO2005 projection for the industrial sector. On June 29, 2004, the EPA issued a comprehensive final rule regulating emissions from nonroad diesel engines and sulfur content in nonroad diesel fuel [6]. The nonroad fuel market makes up more than 18 percent of the total distillate pool. The rule applies to new equipment covering a broad range of engine sizes, power ratings, and equipment types. There are currently about 6 million pieces of nonroad equipment operating in the United States, and more than 650,000 new units are sold each year. The rulemaking covers such equipment as tractors, bulldozers, graders, backhoes, heavy construction, mining, and logging equipment, airport tugs, locomotives, and commercial marine vessels. The regulations represent a tiered emissions reduction approach based on engine horsepower, with phased-in restrictions on emissions of particulate matter (PM), NOx, and nonmethane hydrocarbons. The rule reduces diesel engine emissions by more than 90 percent and fuel sulfur content by 99 percent from current levels. The regulation addresses emissions and fuels simultaneously to maximize emission reductions by integrating engine and fuel controls as a system. To meet the standards, engine manufacturers will be required to produce new engines with advanced emission control technologies similar to those already expected for on-road (highway) heavy trucks and buses. Refiners will be supplying new lower sulfur diesel fuels in both cases. Emission Standards
By 2014, the new Tier 4 regulations will require nonroad diesel engines to cut emissions of pollutants by more than 90 percent [7]. Standards for new engines will be phased in starting with the smallest engines in 2008 until all but the very largest diesel engines meet both NOx and PM standards in 2014 (Table 3). Some of the largest engines (750-plus horsepower) will have one additional year to meet the emissions standards. The final rule includes flexibility provisions aimed at helping small engine manufacturers meet the requirements. The EPA Tier 4 standards do not require retrofitting older diesel engines currently in service and do not apply to diesel engines used in locomotives and marine vessels, but they do cover fuel requirements for those equipment categories. In a separate action, the EPA took the first step toward proposing new emissions standards for diesel engines by issuing an Advanced Notice of Proposed Rulemaking on June 29, 2004 [8]. Contemplated standards would apply to marine diesels used in all new commercial, recreational, and auxiliary marine diesel engines except for very large engines used for propulsion of deep-sea vessels. For locomotives, both new and existing diesel units would require advanced emission control technologies similar to those for heavy-duty trucks and buses. The widespread availability of clean nonroad diesel fuel required under the new fuel standards will enable the use of advanced control technology on locomotive and marine engines. The EPA estimates that anticipated compliance costs will vary with the size and complexity of equipment, in the range of 1 to 3 percent of total purchase price for most categories of nonroad diesel equipment [9]. The new nonroad diesel emission standards, when fully implemented, are expected to provide significant public health benefits. Fuel Standards The final rule, to be implemented in multiple steps, requires sulfur content for all nonroad locomotive and marine (NRLM) diesel fuel produced by refiners to be reduced to 500 parts per million (ppm) starting in mid-2007. It also establishes a new ULSD limit of 15 ppm for nonroad diesel by mid-2010. For locomotive and marine diesel, the action establishes a ULSD limit of 15 ppm in mid-2012, providing the refining industry flexibility to align fuel supply operations with all other on-road and nonroad ULSD fuel regulations, which take effect in mid-2010. After refiners, the new standards will apply to terminals, wholesalers, retailers, and end users in subsequent months as production flows through the distribution chain.
The nonroad diesel requirements have implications for the refining industry and, especially, for small refiners (defined as having less than 155,000 barrels per day of crude oil charge capacity and less than 1,500 corporate employees). Approximately 20 refiners fall into the small refiner category. They are dispersed across the country, with the largest concentration located in the Rocky Mountain Region. Small refiners are granted three additional years to meet the 500 ppm standard for NRLM diesel, starting in mid-2007 (Table 4). The challenges facing small refiners include additional time needed to secure capital funding, a need for longer leadtimes because of limited engineering expertise, and limits on the availability of contractors, who will be performing upgrades for major refiners. For early or overcompliance with the fuel sulfur standards, a regional averaging, banking, and trading program will be created; however, credits may not be used or traded for use outside the credit trading region in which they are generated [10]. For the 500 ppm standard beginning in mid-2007, small refiners outside the Northeast/Mid-Atlantic area can use credits to continue producing high-sulfur nonroad fuel until the credits expire in mid-2010. After mid-2014, small refiners must comply with the 15 ppm standard for NRLM diesel. The rule recognizes certain exceptions. For Alaska, NRLM diesel covers only areas served by Federal highways. Rural and remote areas are not required to convert to ULSD until 2011. For stationary power sources, the rule excludes No. 4, 5, and 6 heavy distillates. In special marine situations, giant Category 3 ocean ship engines face a separate regulation expected by April 2007. Category 2 or 3 marine diesel engines using distillate with a distillation point over 700oF are excluded. There are also special exceptions for transmix facilities on pipelines [11]. Because transmix facilities do not have sulfur removal equipment to clean up pipeline interface mixes, the final rule provides that they may produce fuels for sale into the NRLM markets that meet small refiner provisions, in order to avoid the burden of additional investment in treating equipment or returning mix to refineries for reprocessing. After the NRLM small refiner provisions expire in 2014, transmix processors may continue to sell 500 ppm fuel into the locomotive and marine market. The rule also prescribes certain dyeing, tracking, and record keeping requirements to ensure that fuel is not diverted from authorized channels and that taxes are properly paid. The Internal Revenue Service ordinarily requires that fuel used in NRLM engines be dyed before leaving the terminal, to indicate its nontaxed status. Fuels that meet on-road diesel specifications but are destined for NRLM markets can leave the terminal undyed, provided that the tax is paid first. NRLM users can then apply for a tax refund. To minimize misfueling, a system of labels is prescribed on diesel retail pumps, fuel tank inlets, and dashboard and instrument panels, corresponding with the introduction of new diesel engines and equipment. The EPA did not specify lubricity standards in the rule, because the industry has been working to finalize a universal standard for all diesel fuel. If the American Society for Testing and Materials does not establish a universal lubricity standard, a separate rulemaking applying to lubricity additives will be issued by the EPA. Impacts of the Emission and Fuel Standards The effects of the new NRLM diesel standards are represented in AEO2005. The National Energy Modeling System (NEMS) has been revised to reflect the nonroad rule and recalibrated for market shares of highway, NRLM diesel, and other distillate (mostly heating oil and excluding jet fuel and kerosene). The nonroad rule, following closely on the heels of the highway diesel rule, represents an incremental tightening of the entire diesel pool that will cause demand for high-sulfur distillate to diminish over time while demand for ULSD (both highway and NRLM) increases.
After 2007, during the rule’s implementation, the projections for refinery distillate production are slightly lower with the rule in place because of the more stringent and costly processing requirements, and imports of distillate are higher. For the composite distillate market, prices are slightly higher with the rule in place and vary by sector. Table 5 shows key projections for distillate fuel prices, production, and imports in the AEO2005 reference case, which includes the new nonroad diesel rule, and in a sensitivity case that does not include the new rule. Because heating oil is not subject to NRLM diesel rules, residential distillate prices are not expected to be affected significantly. Eventually, however, residential prices are projected to parallel those in other sectors as the distillate market converges toward a universal ULSD standard. More than two-thirds of all high-sulfur distillate use after 2010 is projected to be concentrated in the Northeast. In the commercial and industrial sectors, distillate fuel prices after 2010 are projected to be higher with the rule in place. Nonroad diesel is a relatively small portion of commercial distillate use, but it dominates industrial use. Thus, the price impact is greater for the industrial sector. For the electric power sector there is little or no projected impact on distillate prices. Diesel prices in the transportation sector are projected to be about 2 cents per gallon higher in 2010-2012 because of the nonroad diesel sulfur reduction and about 3 cents per gallon higher in 2014, when the sulfur content of all NRLM diesel fuel is reduced to 15 ppm. EPA estimates [12] place the added cost of ULSD for NRLM diesel use in the range of about 7 cents per gallon; however, the EPA expects the added cost to be offset by reduced engine maintenance expenses, lowering the net incremental impact to about 4 cents per gallon. The EPA estimates assume complete turnover of nonroad diesel engines by 2030. American Jobs Creation Act of 2004 The American Jobs Creation Act of 2004 [13] was signed into law on October 22, 2004. Most of the 650 pages of the Act are related to tax legislation. Provisions pertaining to energy are described below. Diesel Excise Taxes Section 241 phases out an excise fuel tax of 4.3 cents per gallon on railroads and inland waterway transportation incrementally between January 1, 2005, and January 1, 2007. Under current law, diesel fuel used in trains and fuels used in barges on certain inland waterways are subject to an excise tax of 4.4 cents per gallon. Revenues from 4.3 cents of the tax are retained in the General Fund. The remaining 0.1 cent is put in the Leaking Underground Storage Tank Fund, which is scheduled to expire on March 31, 2005. AEO2005 reflects the phaseout of these excise taxes. Ethanol Tax Credits Section 301 establishes the Volumetric Ethanol Excise Tax Credit (VEETC). Before this Act, gasoline blenders could choose between an income tax credit of 51 cents per gallon of ethanol blended or a reduced rate of Federal excise tax on each gallon of gasoline blended with ethanol. Thus, gasoline containing 10 percent ethanol would be taxed at 13.2 cents per gallon instead of the usual 18.3 cents per gallon in calendar year 2005. Gasoline blended with 5.7 percent or 7.7 percent ethanol would receive a proportionally smaller reduction in the excise tax. The VEETC is instead assessed at a rate of 51 cents per gallon of ethanol, and the entire excise tax is assessed on the finished gasoline. This gives several advantages over the existing structure. VEETC applies to any blend of ethanol and gasoline. It also applies to ethyl tertiary butyl ether (ETBE), a gasoline blending component made from ethanol. The excise tax exemption does not apply to blends containing less than 5.7 percent or more than 10 percent ethanol, such as E85. The income tax credit can be taken for ethanol used in such blends or to make ETBE, but not all gasoline blenders have sufficient Federal income tax liability to take the credit. The VEETC is effective through 2010; the excise tax reduction will expire in 2007. This section also extends the alcohol income tax credit through 2010. AEO2005 includes these tax credits and, in addition, assumes that they will remain in force indefinitely, given that historically they have been extended when they expired. Biodiesel Tax Credits The VEETC also applies to biodiesel blends. A diesel fuel blender can claim a credit of $1 per gallon of biodiesel made from agricultural commodities such as soybean oil and can claim a credit of 50 cents per gallon of biodiesel made from recycled oil such as yellow grease. Section 302 extends income tax credits for biodiesel blending similar to the alcohol income tax credits. The VEETC provision for biodiesel and the biodiesel income tax credits expire after 2006. Section 302 is modeled in the AEO2005 reference case. Rural Electric Cooperatives Income Treatment Current law gives tax-exempt status for rural electric cooperatives if at least 85 percent of the cooperative’s income comes from amounts collected from members for the sole purpose of meeting losses and expenses incurred in providing service to those members. Section 319 provides that, under certain actions approved or accepted by the FERC, gains realized by a rural electric cooperative from a voluntary exchange or involuntary conversion of certain property are excluded in determining whether that cooperative meets the 85-percent test. This provision applies only to the extent that the gain would qualify for deferred recognition under tax laws or the replacement property is used to generate, transmit, distribute or sell electricity or natural gas. This provision represents a level of detail that is not characterized in NEMS. Low-Sulfur Diesel Fuel Production Credit Sections 338 and 339 contain provisions allowing small business refiners a 25-percent credit for production of ultra-low-sulfur diesel fuel (15 parts sulfur per million or less), with additional provisions for expensing the remaining 75 percent of the capital investment. Current law does not provide a credit for the production of low-sulfur diesel fuel. The Act allows a small business refiner to claim a credit at a capture rate equal to about 5 cents per gallon for each gallon of low-sulfur diesel fuel produced in compliance with the Highway Diesel Fuel Sulfur Control Requirements law. The credit is a qualified business credit under Section 169(c) of the Act. The existing carry-back and carry-forward provisions for a qualified business credit apply [14]. The effective date for this provision is December 31, 2002. Taxpayers may currently recover the cost of investments in refinery property through annual depreciation deductions. A separate expensing provision permits small business refiners to deduct as an expense up to 75 percent of the costs paid or incurred in making upgrades to comply with the EPA’s Highway Diesel Fuel Sulfur Control Requirements. Small business refiners (up to 205,000 barrels per day and up to 1,500 employees in refining) can claim a tax credit of up to 25 percent of the capital investment costs incurred since 2003 for producing ultra-low-sulfur diesel. Most of the credit would result from refining the first 155,000 barrels per day, with pro rata credits for the next 50,000 barrels. The credit expires 1 year after EPA’s applicable ultra-low-sulfur diesel deadline or by the end of 2009. Because NEMS does no model individual companies, these tax provisions are not included in the AEO2005 reference case. Marginal Wells Tax Credit Section 341 creates a new tax credit of up to $3 per barrel for the production of crude oil and a credit of up to $0.50 per thousand cubic feet for the production of natural gas from qualified marginal wells. A marginal well is defined as one that produces less than 25 barrels per day of oil equivalent and produces water at a rate not less than 95 percent of total well effluent. Full credit is provided to such marginal wells at reference prices less than or equal to $15 per barrel for oil and $1.67 per thousand cubic feet for natural gas [15]. The credit declines linearly to zero when reference prices, adjusted for inflation, reach $18 per barrel of oil and $2 per thousand cubic feet of natural gas. The tax credit applies to the first 1,095 barrels of oil equivalent produced, and the limit is reduced in proportion to the numbers of days in the taxable year for which the well is not in production. The tax credit takes effect in taxable years beginning after December 31, 2004. Because NEMS does not contain a separate marginal well category, the impact of this legislative provision is not quantified in AEO2005. Green Building Bonds Section 701 contains a brownfields demonstration program that provides tax-exempt status for facility bonds issued to finance qualified “green” buildings and sustainable design projects. The program, designed to encourage the use of solar photovoltaic and fuel cell generation, applies to bonds issued from January 1, 2005, through December 31, 2009; however, projects must be nominated by a State or local government and meet several criteria in addition to the specific green or sustainable criteria. For example, eligible projects must include a brownfields site, be of a certain size, provide a certain level of employment, not include a sports stadium or restaurant, and receive State or local government resources of at least $5 million. Because of the process involved and the site- and company-specific nature of the provision, it is not characterized in the AEO2005 reference case. Tax Incentives for Alaska Natural Gas Pipeline and Gas Processing Facilities Section 706 provides a 7-year cost-of-investment recovery period for the Alaska natural gas pipeline, as opposed to the currently allowed 15-year recovery period, for tax purposes. The provision would be effective for property placed in service after 2013, or treated as such. The expected return on equity for the pipeline was lowered to reflect this provision in AEO2005. Section 707 extends the 15-percent tax credit currently applied to costs related to enhanced oil recovery to construction costs for a gas treatment plant that supplies natural gas to a 2 trillion Btu per day pipeline, lies in Northern Alaska, and produces carbon dioxide (CO2) for injection into hydrocarbon-bearing geological formations. A gas treatment plant on the North Slope that feeds gas into an Alaska pipeline to Canada is expected to satisfy this requirement. The provision would be effective for costs incurred after 2004. For AEO2005, lowering the expected charges for gas treatment on the North Slope captured this provision. Extension and Expansion of the Production Tax Credit for Renewable Electricity Section 710 expands application of the renewable electricity PTC to wind, closed-loop biomass, and poultry-litter plants in service by December 31, 2005 [16]. Eligibility for a modified PTC is also extended to geothermal, solar, small irrigation hydropower, open-loop biomass, municipal solid waste, and landfill gas facilities, also with a December 31, 2005, in-service date. This change has been incorporated in AEO2005. Modified Alternative Minimum Tax Rules for the PTC and Alcohol Fuels Tax Credit The law exempts the alcohol fuel tax credit (Section 40 of the Internal Revenue Code) and the first 4 years of the PTC (Section 45 of the Internal Revenue Code) from tax liability under the Alternative Minimum Tax (AMT), allowing businesses with AMT liability to recover the full value of the affected tax credits. This provision is not included in the AEO2005 reference case, because EIA assumes that these tax credits are generally able to be used at full value. Section 45 Tax Credit for Coal Products The refined coal provisions in Section 710 establish Section 45 tax credits for producers of qualified refined coal products. The refined product must be at least 50 percent higher in market value than the coal or high-carbon fly ash feedstock, and combustion of the refined product must result in 20 percent less emissions of NOx and either SO2 or mercury than the feedstock. The refined coal must be sold for the purpose of creating steam. This provision represents a level of detail that is not characterized in NEMS. Alcohol Alternative Minimum Tax Section 711 allows the alcohol income tax credit, biodiesel income tax credit, and small ethanol producer income tax credit to offset liability under the AMT. The small ethanol producer credit applies only to firms with capacity of 15 million gallons per year or less. Because NEMS does not model individual tax obligations, these changes are not incorporated in the AEO2005 reference case. Suspension of Duties on Nuclear Steam Generators and Reactor Vessel Heads Section 714 extends from January 31, 2006, to January 31, 2008, the period in which nuclear steam generators can enter the United States duty-free. The law allows nuclear reactor vessel heads to enter the United States duty-free through January 31, 2008, suspending the current 3.3-percent duty. This provision represents a level of detail that is not characterized in NEMS. Disposition of Transmission Property to Implement FERC Restructuring Section 909 allows companies to spread capital gains from the sale of transmission assets over 8 years. This provision applies to property sold by a utility to comply with FERC electricity market restructuring efforts. Money from the sale must be used to buy reinvestment property within 4 years of the initial transaction. This restructuring provision is not incorporated in the AEO2005 reference case. Tax Evasion Provisions Subtitle C, Part III, of Title VIII of the Act contains 21 provisions related to fuel tax evasion. Some of the more pertinent provisions and economic impacts are described below. Because NEMS does not model oil and gas income statements, these changes are not incorporated into AEO2005.
Working Families Tax Relief Act of 2004 The Working Families Tax Relief Act of 2004 [18] was signed into law on October 13, 2004. Primarily, the Act reduces taxes for individuals and businesses. At least two provisions relate to energy. Depletion of Marginal Properties Section 314 extends to oil and gas an exemption for marginal properties from the 100 percent of net income limitation on the percentage of assets that can be depleted in a year for tax purposes. In computing taxable income, oil and gas producers generally receive a reasonable allowance for depletion and for depreciation of improvements, based on the amount of resource extracted. Under current law, the deduction cannot exceed 100 percent of taxable income from the property (computed without allowance for depletion). An exemption from the limitation, allowing the deduction to exceed 100 percent of taxable income for production from marginal properties expired on December 31, 2003. This provision extends the exemption to January 1, 2006. The exemption is applicable only to “marginal production,” which is defined as production coming from property that is a stripper well property or a property from which substantially all the production is heavy oil (weighted average gravity of 20 degrees API or less). A stripper well property is a property from which the average production per well is less than 15 barrels of crude oil equivalent per day. Because production from stripper well properties and production of heavy oil are not projected separately from total oil and gas production in the EIA modeling framework, the impact of this provision is not quantified in AEO2005. Qualified Vehicles Sections 318 and 319 repeal the phaseout of credits allowed for qualified electric and clean fuel vehicles for property acquired in 2004 and 2005. For vehicles acquired in 2006, the 2004 and 2005 credits of $2,000 for clean fuel vehicles and $4,000 for electric vehicles are reduced by 75 percent. This provision is not included in AEO2005. Military Construction Appropriations and Emergency Hurricane Supplemental Appropriations Act, 2005 H.R. 4837, The Military Construction Appropriations and Emergency Hurricane Supplemental Appropriations Act, 2005 [19], was signed into law on October 13, 2004. The Act provides for construction to support the operations of the U.S. Armed Forces and for military family housing. It also provides funds to help citizens in Florida and elsewhere in the aftermath of multiple hurricanes and other natural disasters. In addition, it authorizes construction of an Alaska Natural Gas Pipeline. Alaska Natural Gas Pipeline Loan Guarantee Section 116 gives the Secretary of Energy authority to issue Federal loan guarantees for an Alaska natural gas transportation project, including the Canadian portion, that would carry natural gas from northern Alaska through the Canadian border south of 68 degrees north latitude, into Canada, and to the lower 48 States. The authority would expire 2 years after the issuance of a final certificate of public convenience and necessity. In aggregate, the loan guarantee would not exceed: (1) 80 percent of total capital costs (including interest during construction), (2) $18 billion dollars (indexed for inflation at the time of enactment), and (3) a term of 30 years. The Act also promotes streamlined permitting and environmental review, an expedited court review process, and protection of rights-of-way for the pipeline. The impact of the loan guarantee is reflected in AEO2005 by a reduction of the expected return on debt and an increase in the percentage of pipeline costs financed through debt. Additional assistance related to the construction of the Alaska Natural Gas Pipeline is provided in the American Jobs Creation Act of 2004. State Renewable Energy Requirements and Goals: Status Through 2003 As of the end of 2003, 15 States had legislated programs to encourage the development of renewable energy for electricity generation. Of the 17 programs (two States have multiple programs), 9 are renewable portfolio standards (RPS), 4 are renewable energy mandates, and 4 are renewable energy goals.
Renewable Portfolio Standards The type of program used most frequently by the States is an RPS requiring that some specified percentage of electricity supply be provided by qualifying renewable energy sources (Table 6). Most State RPS programs were initiated when privately owned electric utilities were being deregulated, in order to ensure their continued investment in renewables. Key differences among the State RPS programs include their definitions of qualifying renewables, alternatives to new renewable capacity, approaches to cost recovery, opt-out provisions, and enforcement mechanisms. For example, RPS definitions of qualifying renewable technologies vary widely among the States. Landfill gas, solar thermal electric, solar photovoltaic, and wind energy are acceptable in all nine RPS States, but the rules vary for other technologies. Some also include alternatives to new capacity, such as natural-gas-powered fuel cells or solar thermal water heating. Some favor certain renewable energy technologies, especially solar, by offering more than one credit per kilowatthour. This practice may stimulate favored technologies but reduce the effective size of the RPS if they are developed. The States use several approaches for funding their RPS programs, including passing the higher costs directly to all utility ratepayers, applying charges on selected categories of sales, or encouraging voluntary purchases through “green power” programs. Most call for reducing or delaying RPS requirements if costs are excessive (“cost-outs”). They may also reduce or eliminate RPS requirements for non-cost reasons, such as if the entities are deemed not creditworthy or if existing contracts meet all the utility’s requirements. Most State RPS programs do not appear to have specific enforcement procedures, except for revoking operating licenses. Some provide for cost penalties for unmet requirements, payments into research and development funds, fines, and other sanctions; however, collaboration and cooperation appear to be the preferred enforcement tools. Through the end of 2003, no electric utility in any State had incurred a penalty for noncompliance with a State RPS. Mandates Four States have mandates that narrowly specify the new renewable capacity required (Table 6). Iowa’s 1983 mandate, the oldest, ordered its three investor-owned utilities to develop 105 megawatts of new renewable energy capacity, with each utility’s share based on its share of peak demand. Minnesota’s 1994 mandate required Xcel Energy to acquire 425 megawatts of wind capacity by December 31, 2002, plus 125 megawatts of biomass capacity, in exchange for storing additional nuclear waste at its Prairie Island plant. An additional 700 megawatts of new wind capacity has since been added to the mandate, some of which must come from small facilities (2 megawatts of capacity or less). The wind requirements are being met, but Minnesota’s biomass requirements have not been met because of technological and financial difficulties. Additional legislation in 2003 requires a power purchase agreement for 10 to 20 megawatts of biomass energy, operational by 2005, at no more than $55 per megawatthour. The 1999 renewable energy mandate in Texas requires the installation of 2,000 megawatts of new renewable generating capacity by 2009. The Texas mandate has resulted in more new renewable capacity than any other State-level requirement to date, including 1,180 megawatts of new wind capacity installed by the end of 2003 as well as small amounts of landfill gas and other renewable capacity. A fourth State, Wisconsin, in 1998 required four eastern utilities to install 50 megawatts of new renewable energy capacity by December 31, 2000, a requirement that was met by the utilities. Voluntary Goals, Objectives, and Settlements Four States—Hawaii, Illinois, Minnesota, and Pennsylvania—have instituted programs that encourage, but do not require, new renewable energy capacity (Table 6). Hawaii’s 2001 goal resembles a typical RPS, except for the absence of penalties and the inability to obtain supplies from other States. Illinois in 2001 set targets for electricity production from qualified renewables; however, the goal is not supported by schedules, a menu of acceptable renewable technologies or alternatives other than solar and wind, compliance mechanisms, credit trading, or most of the other features of State RPS programs. In Minnesota, utilities other than Xcel are subject to the State’s 2001 Renewable Energy Objective, which requires a “good faith effort” to increase renewable energy’s contribution. The objective is considered a mandate for Xcel. In 1996, five Pennsylvania utilities settled restructuring cases on terms requiring a minimum percentage of renewables. Among these settlements, only the Pennsylvania Electric Company (PECO) energy program was implemented; however, the five utilities also established four sustainable energy funds that are reported to have supported development of significant amounts of new wind and other generating capacity. Results
State renewable portfolio standards, mandates, and goals are all relatively new, with the majority just now entering their initial compliance years. Because of alternative compliance options and adjustments that would likely be made if renewable energy costs are found excessive in the future, it is difficult to assess the future impacts of these programs. Nevertheless, through the end of 2003, requirements or goals for new renewable energy capacity in 15 States has resulted in an estimated 2,335 megawatts of new renewable electricity supply (Table 7). Most of the new capacity is fueled by wind power (2,183 megawatts), with smaller amounts of landfill gas, hydroelectricity, biomass, and solar photovoltaic technologies. The 321 megawatts that entered service in the nine RPS States accounted for 14 percent of total new renewable energy capacity from RPS, mandates, and goals through 2003. State mandates—especially in Texas—have led to the development of 2,004 megawatts of renewable capacity, 86 percent of the total. Nearly 51 percent (1,186 megawatts) of all the new capacity was installed in Texas. Recognizing that States with renewable energy requirements have not added capacity as rapidly as projected in earlier forecasts, projections for new renewable energy capacity resulting from State RPS programs, mandates, and nonmandatory goals are reduced in AEO2005. Update on State Air Emission Regulations That Affect Electric Power Producers Several States have recently enacted air emission regulations that will affect the electricity generation sector. The regulations are intended to improve air quality in the States and assist them in complying with the revised 1997 National Ambient Air Quality Standards (NAAQS) for ground-level ozone and fine particulates. The affected States include Connecticut, Massachusetts, Maine, Missouri, New Hampshire, New Jersey, New York, North Carolina, Oregon, Texas, and Washington. The regulations govern emissions of NOx, SO2, CO2, and mercury from power plants. Where firm compliance plans have been announced, State regulations are represented in AEO2005. For example, installations of SO2 scrubbers and selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) NOx removal technologies associated with the largest State program, North Carolina’s “Clean Smokestacks Initiative,” are included. Overall, the AEO2005 forecast includes 22 gigawatts of announced SO2 scrubbers, 27 gigawatts of announced SCRs, and 3 gigawatts of announced SNCRs. In addition to the existing regulations, Governor George Pataki of New York has announced proposed greenhouse gas reduction targets for the State of New York and has invited nine other States (Connecticut, Delaware, Maryland, Maine, New Hampshire, New Jersey, Pennsylvania, Rhode Island, and Vermont) to participate in a future “Northeast CO2 cap and trade” program. The program requires only CO2 trading among power plants but would also allow trading of other emissions allowances among power plants burning coal, natural gas, or oil. The first Commissioner-level meeting was held in September 2003, and a final agreement is expected to be in place by April 2005. Maryland and Pennsylvania are participating in discussions but have not committed to participation in the program.
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