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Report Contents Report#:EIA/DOE-0607(99)
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Impact of Asian Economic Crises on Oil Markets and the Economy Is Drive to Electricity Restructuring Short-Circuiting? Emerging Transportation Technologies Challenges of an Expanding Natural Gas Market Electricity Issues in a Competitive Environment Renewables in a Carbon-Constrained World
Introduction On March 22, 1999, the Office of Integrated Analysis and Forecasting (OIAF), Energy Information Administration (EIA), hosted the seventh annual National Energy Modeling System/Annual Energy Outlook Conference. These conferences are open to the general public and attract a wide range of participants from other Federal and State government agencies, trade associations, energy industries, private corporations, consulting firms, and academia. Earlier National Energy Modeling System/Annual Energy Outlook conferences concentrated on the initial development of the National Energy Modeling System (NEMS) and the underlying model methodologies and on the results of the first Annual Energy Outlook developed using NEMS. Recent conferences have focused less on specific projections and model developments and more on energy issues, key analytical assumptions, and their potential impacts on energy markets. Keynote Address Flexibility in the design and timing of climate mitigation measures can greatly affect the costs that must be borne. Two types of flexibility have been singled out for most of the attention. The first, “where flexibility,” concerns the actual location of the greenhouse gas emissions reductions that a country might agree to take. The United States has insisted that any climate agreement give those upon whom falls the initial burden of emissions reductions the option to buy an equivalent reduction someplace else in the world. The creation of a market for emissions reductions—particularly an international market—has the potential to greatly reduce the costs associated with whatever emissions reduction obligations are agreed upon. The second kind of flexibility, “when flexibility,” pertains to the schedule according to which emissions are reduced. Any initiative that calls for substantial emissions reductions in a relatively short period of time will be much more expensive than one that proceeds more gradually. This is because the latter approach will not necessitate the premature writeoff of capital investments, and will allow us to take advantage of the fruits of research and development into less carbon-intensive technologies. A third kind of flexibility, “what flexibility,” relates to the greenhouse gases that are covered. However, determining baseline emissions of methane and some of the other greenhouse gases and verifying future emissions reductions will be much more difficult than for carbon dioxide. Another type of flexibility, “whether flexibility,” examines whether the United States ought to take the Kyoto Protocol very seriously at all. It appears that virtually no one thinks that the Kyoto Protocol has any chance of coming into effect in its current form. One key reason is that the Kyoto Protocol requires no emissions reductions from developing countries, even though the United States insisted going into Kyoto that “meaningful participation” on their part was a sine qua non of any agreement. Yet developing countries will not compromise their future growth potential to help solve a problem that was largely the doing of the developed nations. Another problem with the Kyoto Protocol is the nagging concern that it would prove too costly to implement given its current targets and timetables. According to Portney, it is unlikely that the American public would be willing to accept the kinds of energy price increases that serious analysis suggests might be necessary to meet the goals of the Kyoto Protocol absent international emissions trading. Another concern is that the Kyoto Protocol does nothing to reduce emissions of carbon dioxide before the 2008 through 2012 period. Four economists at Resources for the Future recently published a proposal designed to effect emissions reductions in the United States beginning in 2002, with the following elements. First, it calls for mandatory emissions reductions in the United States during the period 2002 through 2008, to be brought about through an auctioned permit system. Second, in contrast to the Kyoto Protocol, the proposal is modest. It would cap carbon emissions at 1996 levels, which are about 10 percent greater than 1990 levels and about 10 percent less than carbon emissions are forecast to be in 2002, or 20 percent below forecasted emissions in 2008. Third, in order to guard against the possibility that meeting this goal would prove prohibitively expensive, there is a safety valve built in. Specifically, if the price of a permit should rise above $25 a ton in 2002, the government would offer extra permits—as many as are desired—at that price. This safety valve price would go up 7 percent a year above inflation from 2002 through 2008. Fourth, the proposal is designed to be equitable. Since it will increase household costs of energy and other goods, three-quarters of the revenues raised in the first year would be returned directly to households in the form of a rebate. The remaining 25 percent would be returned to the States, based on the vulnerability of low-income households and industries. The proposal has several attractive features. First, because it is modest there might even be a chance it could be adopted. Because of the safety valve feature, the marginal program costs are assured, and information can be learned about carbon mitigation costs, for which wildly divergent estimates have been given. Second, a program such as this would send a measured and gradual message to energy producers and consumers that they will have to pay closer attention to energy conservation opportunities in the future. Third, this program would be a signal to the developing countries that the United States is indeed willing to act first to curb its emissions of greenhouse gases. Fourth, valuable experience into the operation of a greenhouse gas trading system can be gained. There are limitations to this proposal: it begins to deal unilaterally with what is recognized as an international problem; it requires action where some prefer to see inaction; and it stops far short of where others think the United States needs to go. However, the proposal’s authors seem to have it about right. The full text for this address is posted at the Resources for the Future Weathervane site at www.weathervane.rff.org/refdocs/portney_flex.pdf.
Meeting U.S. Carbon Targets More than 80 countries have signed the Kyoto Protocol, but none of the Annex I developed countries with specific carbon emissions targets has ratified it through a parliamentary process. Only two countries (with no carbon emissions targets) had ratified the Protocol as of March 1, 1999. As the first speaker noted, “. . . no criteria, guidelines or modalities of operation were agreed to at Kyoto” and “all practical questions remained to be resolved.” The meeting of the parties in Buenos Aires provided little progress except to set a schedule for resolving the issues by the sixth Conference of the Parties in 2000. This session outlined the remaining issues of implementing the Kyoto Protocol and provided alternative perspectives on the cost of meeting the goals of the Protocol.
Unresolved Issues and Political Challenges to Implementing After outlining the principles and agreements—trading, inclusion of five additional greenhouse gases, joint implementation, and the Clean Development Mechanism—of the Kyoto Protocol, Dr. Mintzer noted that no criteria, guidelines, or modalities of operation were agreed to at Kyoto and that all practical questions remain to be resolved. Some of the key unresolved issues include: how is a ton defined with respect to global warming, for example, carryovers from previous periods; who can hold or trade tons; when is a ton a ton; is one ton as good as another; what if a party or entity has too many tons and not enough permits; how will baselines be set without requiring a workforce of 1,000 Ph.D.s on each project; is there a role for technology benchmarks; who will verify performance and certify projects; what is a share of the proceeds; how will buyers find sellers; who will run the store? Signs of progress came out of the fourth Conference of the Parties in Buenos Aires in 1998, the most important of which was a timetable to resolve the practical issues by the sixth Conference of the Parties in 2000.
International Trade and Industry Impacts of the Kyoto Protocol According to Dr. Montgomery, any limits on emissions trading will seriously harm the U.S. economy and industry. Global emissions trading has great potential to mitigate the costs of implementing the Kyoto Protocol. Costs could be reduced by 75 percent or more through global trading, but only if the United States is able to purchase permits to cover 80 to 90 percent of its required annual emissions reductions on a continuing basis. Unless global trading includes nearly all developing countries, there are likely to be significant impacts on U.S. trade and competitiveness. If China and India are not full partners in the Protocol and trading, harm to U.S. industries will remain significant. Without global trading, permanent disparities between Annex I and non-Annex I countries will be created, and Annex I energy prices will rise while non-Annex I prices will fall, with consequent risks for U.S. trade and competitiveness. U.S. agriculture, chemicals, and other energy-intensive industries will be harmed even with Annex I trading by between 2 to 4 percent of sales. Investment and growth in chemicals and other intensive industries are likely to shift from Annex I countries to non-Annex I countries. Leakage, the migration of business activity from Annex I countries to developing countries, is not significantly reduced by Annex I trading— full global trading is required. Commitments to larger emissions reductions in future budget periods could increase economic losses and trade impacts by 50 percent or more. Developing country participation without China and India and the Clean Development Mechanism do not noticeably reduce losses to the U.S. economy. Finally, restrictions on carbon permit trading which have been proposed by Europe are as bad as no trading at all.
Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity This paper summarized the major findings of the EIA analysis of the Kyoto Protocol.1 Because the exact rules that would govern the final implementation of the Protocol are not known with certainty, the specific reduction in energy-related emissions cannot be established. The EIA analysis includes six cases that assume a range of energy-related carbon emissions reductions in the United States, varying from 24 percent above 1990 levels to 7 percent below 1990 levels. Each case was analyzed to estimate the energy and economic impacts of achieving the assumed level of reductions domestically. In each case, the United States is assumed to meet its 7-percent net reduction in greenhouse gases; however, the various cases reflect different levels of offsets from carbon-absorbing sinks, other greenhouse gases, and international activities. Among the major findings of the analysis, the carbon price required to achieve the assumed range of carbon reduction targets domestically varies from $67 a metric ton in 2010 to $348 a metric ton. The transitional costs plus minimum economic losses range from 1 percent of gross domestic product (GDP) to more than 4 percent of GDP. In each case considered, most of the carbon reductions occur in the electricity generation sector, through a combination of reductions in the demand for electricity, the use of more efficient generation technologies, switching from coal generation to new natural gas generating plants and renewable energy sources, and the life extension of existing nuclear plants. Similarly, the end-use demand sectors respond by efficiency improvements, fuel switching, and reductions in service demand. Overall, coal consumption is significantly reduced and the use of natural gas, nuclear, and renewable energy increases. Petroleum consumption is reduced but still remains a significant share of U.S. energy use due to the continued dominance of petroleum products in the transportation sector.
Analysis of Policies and Measures To Meet or Surpass the U.S. Kyoto Commitments Dr. Bernow presented an analysis of a suite of policies and measures to reduce U.S. carbon dioxide emissions, using a modified version of the National Energy Modeling System. The policies and measures were targeted in each sector to overcome market barriers to more rapid diffusion of advanced energy-efficient, renewable, and low-carbon technologies and resources, rather than a single approach such as a carbon tax or cap and trade system. The policies included: regulatory and tax initiatives for combined heat and power systems; research, development, and tax incentives for investment in new, more efficient equipment in industry; efficiency standards, such as a fuel efficiency improvement of 1.5 miles per gallon a year; carbon content standards, such as a 10-percent reduction in carbon from light-duty vehicles by 2010; research and development for cellulosic ethanol and demand management in transportation; market transformation and standards in buildings; a renewable portfolio standard (RPS) for nonhydropower renewables of 10 percent by 2010; 10-percent biomass co-firing by 2010; caps on sulfur dioxide, nitrogen oxide, and particulates; and a carbon intensity cap in the electricity generation sector. The overall package achieves the carbon reductions with cumulative net savings of about $158 billion, expressed in present-value 1995 dollars, or levelized net savings of $17 billion (1995 dollars) per year from 1998 to 2010. Significantly, while the overall net savings were large, the policy package included a few measures that had net costs: 10-percent cellulosic ethanol in vehicle fuels, renewable RPS, and other policies for electricity generation. The marginal cost of the package of policies was about $56 a ton of carbon. The high marginal cost in an overall package with net savings affords a twofold opportunity to meet high carbon reduction goals and begin the process of technology diffusion, scale economies, and learning that will set the stage for lower costs in meeting the deeper reduction commitments that will likely be required in periods beyond the first commitment period of the Kyoto Protocol.
Impact of Asian Economic Crises on Oil Markets and the Economy The world oil market was characterized by significant turbulence during 1998. Prices fell by one-third on average from 1997 to 1998. Influencing this downturn in prices was an unexpected slowdown in the growth of energy demand, especially in Asia. Significant reductions in gross domestic product were experienced in Korea, Thailand, and Malaysia. Depression, accompanied by political turmoil, struck Indonesia. The region’s largest economy, Japan, went from slow or no economic growth to a decline. Although the Chinese economy continued to grow, it was hampered by a reduction in trade with neighboring countries. This session undertook to review the prospects for Asian economic recovery as well as the mid- to long-term impacts of the Asian economic crises on worldwide economies and the oil market.
World Outlook: Growing—and Ultimately Unsustainable—Imbalances According to Dr. Behravesh, several global vulnerabilities must be avoided in order to escape a worldwide economic recession. In the United States, the low personal savings rate and the ballooning current account deficit are economic liabilities. There are also arguments that the U.S. stock market is overvalued. In Europe, the United Kingdom and Norway could join Germany and Italy in a recession. In addition, the Euro currency is weak. In Japan, monetary policy has started to ease, but interest rates are still too high, and investors continue to be worried about government finances. The Japanese economy continues to shrink. In China, growth has slowed down but remains positive. Real interest rates are high, vast amounts of excess capacity exist, and a serious bad loan problem is pervasive. There are signs that the financial markets have stabilized in the developing economies of Asia, but large capacity overhang and vulnerability to the problems in Japan and China will slow the recovery process. In Latin America, Brazil is expected to be in a fairly deep recession in 1999. If inflexible domestic fiscal policies continue to persist in key Latin American economies, a lengthening of the current crisis could occur. World economic growth is expected to remain positive over the next 5 years, but only slightly above 1 percent in 1999.
The Asian Economic Downturn, Oil, The Asian economic recession is providing a comprehensive test of virtually every sector of the international petroleum market. Fallout will be felt in the operation of the market, in future investments, in industry structure, and in international petroleum politics. A misunderstanding about the determinants of oil prices inevitably results in cautious and unrealistic projections about future prices. The past has always been a terrible guide to the future and continues so today. What are the upper and lower limits within which prices will fluctuate? The floor is dictated by production restraints of the low-cost producers. The ceiling is dictated by a combination of new technologies, the existence of strategic reserves, and surplus production capacities. Technology reduces both costs and time horizons but accelerates resource depletion. Industrial countries have largely insulated themselves from oil shocks, regardless of whether the shock emanates from a price collapse or a price escalation. Non-OPEC supplies are eventually going to stagnate and fall. The timetable for this decline is dependent on technology’s ability to economically produce the vast deepwater resources of the Caspian Basin, offshore West Africa, the South China Sea, and the U.S. Texas Gulf. The structure of the petroleum industry will be governed by the need to manage and minimize risk and the ability to secure less expensive capital. Oil companies will be larger and more balanced in their vertical integration but significantly more horizontally integrated as full-service energy companies.
Is the Drive to Electricity Restructuring Short-Circuiting? The restructuring of electricity markets continues to be a topic of much debate at both the national and State levels. State referenda that could have led to repeal of some restructuring initiatives were soundly defeated by voters in California and Massachusetts in 1998, leading some to conclude that a new round of restructuring was in the offing. The momentum for both local and Federal action seems to have slowed, however, as low-cost States reconsider the impacts of competition and competing bills at the Federal level languish in Congress. The objective of this session was to provide details on the experience in three Northeastern States—Pennsylvania, New York, and Massachusetts—which have moved ahead with electricity restructuring. Both the successes and pitfalls were discussed, providing listeners a representative picture of what other States can expect as they continue to deliberate this contentious issue.
Current Status and Future Steps for Electricity Restructuring in Pennsylvania The key to the success of Pennsylvania’s competitive electricity market is consumer education. Pennsylvania has gone to great lengths to provide information to its consumers, especially those in the residential sector, in order to allow them to make intelligent decisions concerning their choice of electricity suppliers. More than 50 percent of the customers participating in the initial pilot program shopped for alternative suppliers, with half of those actually making a switch, a rate indicating that the program has had a large measure of success. Consumer education is believed to be a necessary ingredient to consumer acceptance of the new market regime. Less emphasis has been placed on educating larger customers—both commercial and industrial—both because they are more generally aware of the marketplace and because they have greater access to information from individual suppliers, given their greater importance in overall market share. Pennsylvania’s Electricity Generation Customer Choice and Competition Act was passed by the legislature in December 1996. One of the motivations for passage of the Act was the State’s higher-than-average electricity prices. Partial competition, following the pilot program, began on January 1, 1999, with gradual phasing in of full retail competition over the next 2 years. Individual agreements concerning their restructuring plans have been made with each of the State’s major electric utilities. Agreements with utilities were generally settled without litigation, as both the State and the utilities realized it was in their best interests to proceed expeditiously in the new regime. “Green power” packages are available under the program and have been chosen by some customers. Transition charges to recover stranded costs are a part of the restructuring program, with a transition period of approximately 4 years. “Slamming,” the unauthorized switching of some customers that has been a problem with long-distance telephone competition, was also addressed by the Commission. The difficulties of the competitive market have been illustrated by the fact that some suppliers withdrew from the residential market because they did not see how to make a profit. Overall, however, Pennsylvania’s large market and aggressive consumer information program seem to be keys leading to the general success of its restructuring efforts.
Electric Competition in New York: Wholesale and Retail The restructuring of New York’s electricity industry has proceeded through the auspices of its Department of Public Service, which has authority under the State’s laws to open up its electricity and gas markets to competition. As a result, no further legislation was needed. The stated goals of the Public Service Commission, which oversees the Department of Public Service, in terms of restructuring were:
As in Pennsylvania, agreements between the State and individual utilities are the key mechanisms for both wholesale and retail competition. Each agreement specifies that customers can now choose the energy services companies that will generate their electricity. The power is to be distributed to customers through their traditional utilities, which will remain regulated. The generation function is therefore to be separated from the transmission and distribution functions through divestiture. As of March 1999, Consolidated Edison had sold more than half of its generating capacity; Niagara Mohawk had sold more than 40 percent of its generating assets; and New York State Electric and Gas had sold almost 75 percent of its capacity. As a result, the concentration of generation assets in the eight largest holders in the State had shrunk from 92 percent before restructuring to 63 percent. Ultimately, New York utilities will be selling 70 percent of their generating capacity to nonutilities. Other elements of restructuring agreements include: the original utility becomes the provider of last resort in the event that the customer chooses not to switch; nuclear plants remain regulated by the State; there is some sharing of stranded costs between ratepayers and stockholders to help reduce electricity rates; and public benefits continue, but at somewhat lower rates than before, except for low income programs, which may expand slightly. Next steps in the wholesale market restructuring include establishment of location-based marginal cost pricing, starting up an Independent System Operator during the first half of 1999, and completing the divestiture of generating plants. Retail competition is also proceeding, but at a somewhat slower pace. Before restructuring, New York’s average electricity prices exceeded the national average by more than 50 percent. The main drivers were State and local taxes, uneconomical purchased power contracts, high operating costs, and the high cost of nuclear plants. Through approved settlements between the Commission and the utilities, rate reductions have been negotiated on the order of 25 percent for large industrial consumers and about 10 percent for all others. As of February 1999, only a small number of customers—about 95,000 out of a base of 7 million—had actually switched suppliers, but full phase-in of retail choice will not be complete for the largest utilities until the middle of 2001. The next steps in restructuring the retail market include public outreach and education to ease implementation; deciding what services, such as billing and metering, should be offered competitively; unbundling of those services: and looking at alternatives for making the local utility the provider of last resort.
Status of Electric Restructuring in Massachusetts: How the The goals of electricity restructuring in Massachusetts are to lower rates in the near term by 10 to 15 percent and to create a robust competitive market in the long term, with divestiture, corporate restructuring, and standards of conduct. The Electricity Restructuring Act of 1997 mandated customer choice of generation suppliers as of March 1, 1998, along with an average 10-percent rate reduction. Net stranded costs, after full mitigation, are to be fully recovered. Small municipal utilities were exempted, unless they choose to compete. Traditional public benefits were maintained, including preservation of low-income rate subsidies, increased funding for energy efficiency, and increased funding for renewable energy. The Act also called for consumer education in helping customers to make choices. Currently, a number of actions are being taken, all of which are to be completed by the beginning of 2000. These include certification of stranded costs through comprehensive audits, determination of the cost of wholesale power contracts and whether or not they can be renegotiated, divestiture of generation assets, and studying the feasibility of competitive metering, billing, and information systems. To date, plans approved by the Department of Telecommunications and Energy include those for Boston Edison, Commonwealth Electric, and Massachusetts Electric. There are also merger and acquisition applications pending, including one involving a merger of Boston Edison with Commonwealth Energy System. Interaction with the Independent System Operator (ISO) is a key ingredient of restructuring in Massachusetts and throughout New England. The role of the ISO is to ensure efficient markets and reliability. Questions have been raised about the independence of the ISO and the implications of that independence for customers. Future issues for Massachusetts include performance-based ratemaking for distribution companies and the impact of Federal legislation on the workings of the State’s newly deregulated electricity and natural gas markets. Federal legislation is needed because electricity is at least a regional, and ultimately a national, market and also to effect reform of the Public Utilities Holding Company Act and the Public Utilities Regulatory Policies Act, both of which may be at odds with much of the change in the rules and regulations now being promulgated by the States to increase wholesale and retail electricity competition.
Emerging Transportation Technologies The three topics for this session were emerging technologies in the Partnership for a New Generation of Vehicles (PNGV) program, advances in conventional technologies vs. alternative-fuel technologies, and environmental concerns and efficiency improvement. The National Research Council, which reviews the PNGV program annually, suggested in their last report that PNGV needs more funding and may not reach its fuel efficiency goal of 80 miles per gallon with the vehicle cost and performance goals. Several technologies, such as fuel cells, electric hybrids, and direct injection for conventional vehicles, have been chosen by PNGV to meet its goals. Both diesel electric hybrid and the direct injection technologies, including gasoline and diesel versions, may have difficulty meeting future nitrogen oxide and particulate standards that are currently being determined by the U.S. Environmental Protection Agency through Clean Air Act Tier II emissions standards. Due to the lack of funding and the enormous costs of advanced research and development, the question remains whether more effort should be placed on conventional advanced technologies or on alternative-fuel technologies. They have different potential for reducing future carbon emissions. Increasingly, environmental issues appear to be the main drivers for increasing fuel efficiency, although they may not remain as such. With flat fuel prices in the foreseeable future and rising income levels, it may be difficult to reduce carbon emissions and raise fuel efficiency levels. Current trends appear to be toward larger cars, light trucks, vans, and increasingly large sport utility vehicles. It is also questionable whether alternative-fuel vehicles can really assist in reducing carbon if most of the sales are flexible-fuel alcohol vehicles, which usually burn gasoline.
Making a Business Out of It Making a business out of new technology requires not only technical feasibility but also commercial viability. In order to be successful in business, manufacturers must see their business the way their customers see it. A price utility theory curve illustrates that for any given level of vehicle price there is a corresponding utility from the use of the vehicles. As customers pay higher prices for vehicles, they expect higher utility from the vehicle. The difficulty is that customers are used to paying a core vehicle price for conventional technology. Any new technology must either provide additional benefits to justify a higher price or retain the level of utility but at the same core price. The objective of technology is to reduce costs so that consumers will not experience any dropoff in utility and no vehicle price increases above the core level. Business leaders also must see their business through the eyes of their investors. With increasing risks there are greater returns. Investors expect high returns, but that can only happen if consumers purchase the technology. Higher risks without higher returns will not satisfy investors’ needs. The strategy to fulfill the requirements of both customers and investors is for manufacturers to get down the cost curve. For increasing volumes of production, costs will decline, but not without technical breakthroughs in research and development as well. There are currently three generations of vehicle designs that will assist manufacturers in achieving those cost reduction goals. Although most customers believe that manufacturers are currently at the generation three goals, we are actually only at the beginning of the second generation of advanced technologies.
The Transportation Challenge to Reduce Oil Use and Greenhouse Gases What is conventional technology? Incremental improvements in conventional engines, such as diesel direct injection (CIDI) and gasoline direct injection (SIDI), modest weight reduction, and blended fuels, represent the set of conventional technologies that could be used to reduce greenhouse gas emissions. Advanced technologies include hybrid vehicles, electric vehicles, fuel cell power, and hydrogen and biomass fuels. CIDI, SIDI, and weight reduction could lead to a vehicle that increases fuel efficiency by 50 percent. Hybridization, regenerative braking, and weight reduction have the potential to produce a vehicle with two times the efficiency of a conventional vehicle. Hydrogen fuel cell technology, a 40-percent weight reduction, and regenerative braking could result in a vehicle with three times the efficiency. There are three market considerations in the advancement of vehicle technology. First, consumer acceptance is the key to technology success. Second, evaluation must be made of vehicle cost, driving range, acceleration, luggage space, etc. Third, policies may be needed to influence consumer and manufacturer behavior. The U.S. Department of Energy’s Office of Transportation Technologies has projected that advanced technology vehicles will capture approximately 65 percent of all vehicle sales by 2020, resulting in a reduction of transportation fuel consumption by 2 quadrillion Btu. There are basically three strategies to reduce carbon emissions from light-duty vehicles: reduce the level of vehicle miles traveled (VMT), increase the fuel economy of new light-duty vehicles, and substitute low-carbon fuels, such as cellulosic ethanol, for petroleum-based fuels. Reductions in VMT can only realistically amount to about a 6-percent total reduction based on travel by trip purpose. Hypothetically, to reduce carbon emissions by 50 million metric tons in 2010, new car efficiency would have to be approximately 47.4 miles per gallon and new light truck efficiency about 31.5 miles per gallon. To achieve a 100 million metric ton reduction, new car and new light truck efficiency would have to be 88.8 miles per gallon and 54.6 miles per gallon, respectively. Ethanol from biomass or cellulosic feedstocks has the potential to significantly reduce carbon emissions; however, there are supply constraints.
PNGV: The Next Five Years, Where We’ve Been, Where We Are, Where We’re
Going The research strategy of the PNGV program can be categorized into three components: manufacturing, near-term conventional vehicles, and long-term next-generation vehicles. Manufacturing strategies are designed to reduce production costs and product development times for all car and light truck production. Near-term conventional vehicles can assist in pursuing advances that increase fuel efficiency and reduce emissions of standard vehicles. Long-term next-generation vehicles include a new class of vehicles with up to three times the fuel efficiency of today’s comparable vehicle. In 1995, technology areas for development were determined. Specific technology selections made in 1997. Concept vehicles will be available by 2000, and production prototypes will be ready in 2005. PNGV believes that 27 miles per gallon can be achieved by starting with current conventional technology. Reduction in mass or weight can add another 9 miles per gallon and aerodynamics an additional 6 miles per gallon, for a total of about 42 miles per gallon. Stratified charge direct injection of gasoline can add another 10 miles per gallon, and with a hybrid electric technology the fuel efficiency could potentially reach almost 64 miles per gallon. Another possible technology is compression ignition direct injection of diesel fuel, which could add 18 miles per gallon to the current 42 miles per gallon, including mass and aerodynamics, and another 12 miles per gallon in a hybrid electric configuration to reach a total efficiency of 72 miles per gallon. Alternatively, fuel cell technology could add another 38 miles per gallon to the base 42 miles per gallon. There are several sources of uncertainty, including the additional mass of components (due to immature components and lack of parts integration). Other factors are mass compounding, unaccounted losses in installation and transient effects, vehicle aerodynamic penalties due to packaging and heat rejection, and fuel economy reduction as a result of emissions controls. On the positive side, future improvements in technology may reduce costs beyond the level anticipated. The most promising technologies are light-weight materials; direct injection, which offers a 15- to 35-percent improvement in efficiency; electric traction, which permits electric hybrid and fuel cell propulsion; and proton exchange membrane fuel cells, which have the potential for low emissions and high efficiency. Light-weight materials have cost, safety, and joining problems which must be addressed. Electric traction has higher cost issues and also has complexity, high mass, and efficiency hurdles. Direct injection technologies must overcome problems with nitrogen oxide (NOx) and particulate emissions, cost, and clean fuel infrastructure and availability. Fuel cells must deal with much higher costs, on-board fuel storage and processing, complexity, efficiency hurdles, packaging, higher mass, and fuel infrastructure problems. Some of these problems can be solved with lower sulfur fuel, which would reduce NOx and particulate levels. Additional after-treatment with catalysts is another possible solution, but even when that is combined with low sulfur fuels, PNGV will have a very difficult time meeting the new Tier 2 emissions regulations formulated by the Environmental Protection Agency.
Challenges of an Expanding Natural Gas Market The Annual Energy Outlook 1999 (AEO99) projects that U.S. natural gas consumption will increase to 30 trillion cubic feet by 2013 and 32 trillion cubic feet by 2020. Other industry participants believe that 30 trillion cubic feet will be exceeded even earlier, perhaps by 2010. The requirement under the Kyoto Protocol to reduce greenhouse gas emissions would place even more pressure on the natural gas market. In one case in the EIA analysis of the Kyoto Protocol, Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity, natural gas consumption rises to 35 trillion cubic feet in 2020. In 1998, U.S. natural gas consumption was just over 21 trillion cubic feet. The significant gap between current and projected consumption raises several questions about the availability of natural gas for a 30 trillion cubic foot market, the availability of pipelines to move the gas, and the costs and risks of industry expansion.
Infrastructure Requirements In January 1999, the Interstate Natural Gas Association of America Foundation, Inc., released Pipeline and Storage Infrastructure Requirements for a 30 Tcf U.S. Gas Market. The purpose of the study was to create a realistic picture of what a 30 trillion cubic foot U.S. gas market might look like, by estimating the transmission and storage infrastructure requirements of the market and identifying the challenges facing the industry in supplying this infrastructure. The study was performed by Energy and Environmental Analysis with their Gas Market Data and Forecasting System. Two demand scenarios were created to simulate higher economic growth and higher gas use for electricity generation because of faster nuclear retirements and increased environmental restrictions on coal use. Two supply scenarios were created, increasing offshore Gulf of Mexico supplies and increasing onshore production, particularly in the Rocky Mountains. In both demand cases, consumption exceeded 30 trillion cubic feet by 2010 and was met at a spot price of about $2.50 per million Btu (1998 dollars). Pipeline investment requirements were estimated to range from $30 to $32 billion between 1998 and 2010, and storage investment requirements were estimated to range from $2.2 to $2.4 billion. The study concluded that a 30 trillion cubic foot gas market is economically feasible by 2010 or shortly thereafter. The infrastructure requirements are substantial but within the levels achieved in recent years, and the challenges to the gas industry are manageable if the demand growth is steady and anticipated.
Access to the Natural Gas Resource Base: Trends and Opportunities Focusing on the ability of natural gas producers to meet the demand projected in AEO99, a 1997 Gas Research Institute study, How Industry Has Increased Lower 48 Gas Production and Maintained Deliverability with Fewer New Wells, was cited. This report notes that, since the mid-1980s, technology has increased production and the maintenance of deliverability with fewer wells, shifts to more productive regions have improved deliverability, and more recompletions have reduced decline rates. On the technology front, improved multi-channel, three-dimensional seismic data, combined with better processing and vastly improved, integrated interpretation systems, have allowed geologists to visualize reservoirs. This has led to a recognition of reservoir heterogeneity, increased reserve growth, and allowed drillers to address more specific targets. Shifts to more productive regions include Norphlet sandstone in the Gulf of Mexico, deepwater Gulf of Mexico, and coalbed methane in the San Juan Basin. Targeted recompletions have improved reserves added per well. Forty-eight percent of increased production between 1986 and 1993 resulted from increased recompletions. The strongest areas for recompletions were the key producing regions of the Gulf Coast, both onshore and offshore, with established infrastructure. Due to the current economic conditions in the industry, jobs would be lost, mergers would occur, companies would go out of business, and expertise would be lost to the industry. However, more conservative companies will survive to take advantage of declining drilling costs, the substantial resource base, and new technologies— both hard and soft.
Forecasting the Future of Natural Gas: This talk opened with the caution that: “Not only were our forecasts wrong 20 years ago, they were totally and completely wrong.” Unlike the predictions of the late 1970s, resources are abundant and the Asian economies are suffering a severe economic recession. Nevertheless, future natural gas prices may be much more volatile than anyone expects. As a result, prices will be higher and consumption lower, all else being equal. The industry has little experience with gas commodity markets, and in other commodity markets, small imbalances in supply or demand can result in large price swings. Price volatility adds to the cost of doing business, and gas producers can be expected to require higher prices than if prices were expected to remain relatively constant. Current rates of return do not justify the investments made by gas producers. In other words, gas producers would probably have invested considerably less in gas production if they had been more prescient regarding gas commodity prices. As gas producers become more aware of the risks they face and begin to require higher rates of return, wellhead prices should rise or consumption should fall.
Electricity Issues in a Competitive Environment The electricity transmission network is a key component in the restructuring of electricity markets. Issues related to ownership, operations, and system expansion need to be addressed as part of the market design. Ancillary services that were previously provided as part of the bundled services under regulation need to be defined and provided for as part of the restructuring process. Concerns have been raised about the potential for exercise of market power, particularly during periods of peak demand when lines are congested. This session explored what recent experience has revealed about these issues, policy considerations that are being formulated, and structures that could be implemented to facilitate efficient operations in the marketplace.
Reliability and Market Power Reliability has a special importance in electricity markets because, unlike other commodities, electricity needs to be produced when it is demanded and cannot be stored to any great extent. The inability to store electricity can lead to the exercise of market power. This opportunity exists because the operation of the electrical system requires substantial amounts of backup capacity in order to ensure reliable operations. For example, operational requirements require that some generators be dispatched even if their costs are higher than other generators located elsewhere in the network. Owners of transmission systems can also exercise market power where lines are congested. When congestion occurs, owners can command prices that are higher than they would be if lines were loaded below their maximum ratings. In this case, transmission providers have an incentive to forestall expansion of the network in order to maintain prices. Policymakers need to design market rules that mitigate the potential for market power and assure that prices are consistent with the costs of providing transmission services.
Ancillary Services: Until recently, ancillary services were bundled with energy generation services provided by regulated electric utilities. These services include backup power, cold start capability, and voltage support. With the advent of competitive markets for generation services, it is necessary to address market designs that provide these services explicitly. Ancillary services have to be identified in order to develop such a market design. Currently, the Federal Energy Regulatory Commission and the North American Electric Reliability Council, which is charged with maintaining the reliability of the electrical system, have identified different ancillary services. Consistent definitions will need to be agreed upon in order to develop market structures to provide ancillary services. One approach is to allow the market to determine, on an ad hoc basis, which ancillary services need to be unbundled. This approach is attractive in minimizing the transaction costs in the provision of these services but suffers from the possibility of breaches in reliability in the delivery of electricity to customers. Ancillary services have public good aspects, and market responses may not be adequate mechanisms for providing them. Market-based pricing of ancillary services could require price caps to limit damages that could occur during disruptions. Mixed strategies are likely to evolve as markets develop. Market designs need to focus on making progress toward competitive markets, minimizing adverse impacts during transitions, and providing responsible and responsive governance.
Transmission Pricing in a TransCo World: Incentives for TransCos are for-profit corporations that own or lease transmission systems. TransCos will be responsible for the operation of the grid and will be subject to regulation. Regulators will determine returns to investors based on performance. TransCos will also be responsible for mitigating congestion on the transmission grid by making investments in new facilities. The concept of TransCos is not new. Worldwide, there are existing and proposed TransCos. The pricing method used to provide transmission service is currently being debated. One method is zonal pricing, which uses a fixed rate for broad geographic areas. Another method is nodal pricing, which specifies a tariff from one point to another point in the network. Zonal pricing is preferred to nodal pricing because players have information ex ante rather than ex post when nodal pricing methods are used. Financial instruments can be used to protect against congestion costs. For example, transmission capacity can be secured in advance by conducting auctions. In order to operate markets smoothly during the transition period, a direct allocation process could be used to accommodate existing contract obligations and native load commitments while employing auctions to allocate the balance of available capacity.
Renewables in a Carbon-Constrained World Focusing on hydroelectricity, biomass, and wind, this session highlighted important issues affecting either the quantities of natural resources available for electricity generation or the use of renewable energy technologies in U.S. electric power markets. The session highlighted the ability of renewable energy supplies to meet increased demand, such as might occur in meeting possible U.S. carbon reduction requirements. Congress and other interested parties frequently ask EIA to assess renewable energy under potential requirements to sharply decrease U.S. carbon emissions. In 1997, EIA examined proposed U.S. renewable portfolio standards, which included prospective reductions in carbon emissions. In 1998, EIA was asked by Congress to analyze the Kyoto Protocol and examined a range of scenarios for reducing U.S. carbon emissions. More recently, EIA was asked to analyze the impacts of the Climate Change Technology Initiative, which included proposals to increase the contribution of renewables and reduce carbon emissions. Conventional hydroelectricity, biomass, and wind are among the likely renewable choices in a carbon-constrained environment.
Hydropower— Hydroelectric power has been a mainstay of U.S. electric power throughout the 20th century, with more than 75,000 megawatts providing around 10 percent of all U.S. electricity supply. Hydropower is especially significant in the U.S. Northwest and in California, with more than 80 percent of the State of Washington’s electricity supply supplied by hydroelectricity. Hydroelectricity affords some of the Nation’s lowest electricity rates. Whereas States with lower percentages of hydropower, like New Hampshire and New York, have retail electricity prices in excess of 10 cents per kilowatthour, States with high proportions of hydropower, like Idaho and Washington, have some of the lowest, closer to 4 cents per kilowatthour. U.S. hydroelectric generating capacity is not increasing and is likely to decline, despite projected demands for as much as 300,000 megawatts of new generating capacity through 2020 and 30,000 megawatts of undeveloped hydroelectric potential, more than 70 percent of it at existing dams. Although nearly 1,500 megawatts of new capacity were added from 1987 through 1990, only around 500 megawatts were added from 1991 through 1994 and less than 100 megawatts in 1995 and 1996. Hydroelectric power growth is being slowed by increased project relicensing costs and reductions in relicensed hydropower project output. Relicensing costs for smaller projects (5 megawatts or smaller) averaged barely half a million dollars in 1987, but by 1997 the costs had nearly doubled, to more than a million dollars. For projects in excess of 100 megawatts, relicensing costs have also more than doubled, from less than $2.5 million in 1987 to $5 million in 1997. Relicensed facilities are also suffering losses of effective generating capability, about 2 percent for smaller projects and 3 to 5 percent for larger projects. Prospects for future U.S. hydroelectric expansion would be greater if: conflicts between State and Federal licensing requirements and procedures were resolved; the Federal Energy Regulatory Commission were the final authority in licensing decisions; consistent technical evaluation criteria existed to evaluate hydroelectric projects; and improved hydropower resource data and new hydroelectric generating technologies were supported. Licensing exemptions for small projects at existing dams would also speed additions of new hydroelectric generating capacity.
Biomass Resources in the United States—Potential Quantities and Prices Recently there has been growing interest in biomass as an energy source. Global climate change concerns are a major reason, but biomass has other advantages, such as being a domestic energy source and its development potential in rural areas. Biomass resources can be categorized as follows: forest resources, agricultural residues, mill residues, and urban wastes in the current mix, with dedicated bioenergy crops a distinct potential source. Estimates of the quantities of each type and their price ranges have been provided to EIA. Forest residues include logging residues and rough, rotten, and salvable dead trees. Quantities for each timber class are adjusted by site slope, accessibility, and retrieval efficiency. Costs, including collection, stumpage, and transportation, range up to $60 a ton for up to 38 million dry tons. Polewood (merchantable growing stock) is not included because of its higher value uses, but it could potentially add another 34 million dry tons at prices under $50 a ton. Agricultural residues include numerous crop residues, primarily corn stover and wheat straw. The quantities of crop residues are generally halved to account for what must be left to sustain soil quality. Prices range up to $46 a ton for as much as 143 million dry tons, accounting for collection, transportation, and profit to the farmer. A U.S. Forest Service survey of saw, pulp and paper, and veneer mills is used to develop quantities of primary mill residue by type (bark, fine residue, coarse residue) and use (fuel, fiber, and other). The data include only the material not used on site. Anecdotal evidence suggests that delivered prices are $10 to $20 per dry ton for unused residues and $20 to $30 per dry ton for residues used for fuel. Urban wood waste is that wood contained in municipal solid waste, including yard trimmings, and in construction and demolition debris. Quantities are based on estimates of the waste stream and an estimate of the share that is wood. Prices are very low or even negative. Although dedicated bioenergy crops are not currently available, potential supplies were projected in a joint project between Oak Ridge National Laboratory and the U.S. Department of Agriculture. POLYSYS, an agricultural model developed and maintained by the University of Tennessee, was modified to include three potential crops—switchgrass, hybrid poplar, and willow. The model includes all major crops, a livestock sector, and various demands, including exports, for 305 statistical districts, which can be aggregated into States or regions. The analysis is limited to acres in current crop production, i.e., no Conservation Reserve Program lands. Expected prices, costs, and yields determine profits, which are the basis for allocating acres of production. The great majority of the energy crop acreage is devoted to switchgrass.
Accessing U.S. Wind Resources The issue of U.S. wind resource availability is an important one, particularly in cases calling for increased U.S. renewable energy use. As a result, both actual wind resource availability and also EIA’s representation of wind availability in NEMS become important. Recently released EIA analyses, for example, forecast different future U.S. wind capacities, depending upon aggregate demand, costs of alternatives, and assumed legal requirements for renewable energy use. Reexamination of the modeling suggests that EIA may be underrepresenting opportunities for future U.S. wind supply in scenarios that offer large demand for renewable sources. In the EIA analysis, a number of constraints are imposed on wind capacity growth. Wind technology capital costs can increase by as much as 200 percent as greater proportions of regional wind resources are consumed. To represent the costs of supply bottlenecks, wind power capital costs increase in any year when the annual rate of U.S. capacity growth in orders for new capacity exceeds current capacity by more than 20 percent. Total wind capacity in any region is also limited, permitting a maximum addition of 1,000 megawatts per region per forecast year and limiting intermittent generators’ (wind and solar photovoltaic) total regional share to no more than 10 percent of all electricity generation. These constraints serve to limit U.S. wind power growth in some cases. They do not affect U.S. wind power growth in EIA’s reference case forecasts; however, they overrestrict wind power growth under circumstances of greatly increased demand for renewables, such as in carbon reduction cases. Test results indicate that removing any one constraint may not greatly increase the results, so long as other constraints remain in force. According to Mr. Short, in concept EIA’s constraints on wind power are reasonable, but test runs and reexamination of the assumptions suggest that actual wind resources may be larger than assumed by EIA. More recent reexamination of wind resource data for the Pacific Northwest National Laboratory indicates that some excellent wind sites are not included in standard databases currently used by EIA. Additional analysis also suggests that EIA should consider allowing increased interregional electricity trade. As a result, future U.S. wind power supply responses may be underestimated in cases of high demand for renewable energy. |
