National Energy Modeling
System
Summary of the Annual Energy Outlook Conference 1998
(Annual Energy Outlook
1999 Conference will be held on March 1999.
Details will be available on our website
in December 17, 1998)
| This paper presents a summary of the National Energy Modeling System/Annual Energy Outlook conference held on March 30, 1998. The remarks for each speaker were summarized by the session moderators and are not intended to serve as transcripts of the sessions. The comments and opinions of speakers outside the Energy Information Administration (EIA) are their own and do not necessarily reflect the views of EIA. In some cases, speakers were chosen who have different views from those of EIA in order to have a wider range of opinions in the sessions. |
Introduction
Carbon Stabilization: The Road Beyond Kyoto
Unlocking Caspian Energy Reserves
Electricity Restructuring: The States of Play
Stimulating Renewables in a competitive Environment
Fathoming Offshore Oil and Gas
Electricity forecasting in a Competitive Market
Transportation Issues: Fuel Economy in a Carbon-Constrained World
On March 30, 1998, the Office of Integrated Analysis and Forecasting (OIAF), Energy Information Administration (EIA), hosted the sixth 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), the underlying model methodologies, and the results of the first Annual Energy Outlook developed using NEMS. Recent conferences have focussed less on specific projections and model developments and more on energy issues, key analytical assumptions, and their potential impacts on energy markets.
Keynote Address:
A Look at Our Past and Future
ISO New England, Inc.
ISO New England (ISO stands for “independent system operator”) is the successor to the New England Power Pool (NEPOOL) as the independent operator of the electric power transmission grid in New England. Along with California, ISO New England is at the vanguard of market-regulated, open access power transmission in the United States.
NEPOOL began operations in November 1971 as a group of investor-owned utilities with integrated regional dispatch, in which individual units were dispatched by central control in a unified least-cost merit order. Member utilities shared the resulting savings from lower generation reserve requirements and from lower generation costs induced by optimal dispatch and better load distribution. NEPOOL had three main objectives: assuring that bulk power is available to meet demand with acceptable levels of reliability, generating bulk power with maximum practical economy consistent with reliability, and benefit-sharing among NEPOOL members. These objectives were achieved by dispatching power as if by one company, in which utilities under-generated or over-generated in comparison with their loads, with surpluses and deficits netted and reconciled. Net users of power paid their avoided costs, providers received their actual costs, and the difference was divided among members.
The Federal Energy Regulatory Commission (FERC) was the prime mover in the shift to ISO New England, through Orders 888 and 889. Order 888 required open access transmission tariffs and the opening of NEPOOL membership to other interested parties. Order 889 required an Open Access Information System (OASIS) in which bids and offers of power services could be posted. In New England, most States and public utility commissions were also moving in the same direction as the FERC.
ISO New England’s missions are to ensure reliability, provide open transmission access at fair rates, and act as market power policeman. ISO New England is working with market participants and FERC to develop a market power monitoring plan; however, some mechanism is needed to impose sanctions on market participants if they either withhold resources or disobey instructions. It may be necessary, under unusual circumstances, for ISO New England to order generators to provide power in order to maintain system voltage.
ISO New England has written procedures for six forms of reliability markets and developed sophisticated software to implement trading. ISO New England is also consolidating dispatch control from four satellite bases into one, highly automated central dispatch center, in which dispatch control is accomplished by data communication. The main functional responsibilities are to manage dispatch in accordance with transmission, power, and reliability transactions generated by the markets, and to handle forecasting and billing for transmission services.
Several unresolved transition issues remain: If there is transmission congestion that imposes significant costs, who pays these costs and who collects them? Who pays for generator interconnect to the grid? Who is responsible for product labeling, such as the FERC request for “green power” contracting? What does ISO New England do when it detects the exercise of market power? How robust is the market clearing price? Who is responsible for absorbing externality costs, such as the costs of emissions? Finally, the regulatory need for power has been replaced with the belief that market prices will induce the construction of sufficient generation capacity; however, there is no one who can be ordered to build capacity if the new capacity is not constructed.
Carbon
Stabilization:
The Road Beyond Kyoto
Energy Information Administration
Energy Information Administration
The potential role of man-made carbon dioxide emissions on global warming and recent global warming trends have inspired a plethora of economic analyses of the costs of warming, carbon mitigation, and climate stabilization. The proposed protocol developed in Kyoto, Japan, in December 1997 sets country-specific greenhouse gas reduction targets for all Annex I countries, plus Russia and other states of the former Soviet Union, for the budget period 2008-2012. Key developing countries, including China, India, and Brazil, have announced that they will not abide by any greenhouse gas emissions limits. Most, if not all, projections show that global carbon emissions cannot be stabilized without the participation of key developing countries. Two hotly debated questions are: (a) Why should the U.S. accept severe greenhouse gas emissions targets when no agreement has been reached to restrict emissions from key developing countries? (b) What are the (transition and long-term) costs and benefits for the United States of complying with the Kyoto protocol? This session undertook to frame the issues related to the Kyoto protocol and to provide alternative perspectives on the costs and benefits of complying with the proposed treaty.
Framing
the Post-Kyoto Issues
Resources for the Future
The salient features of the Kyoto agreement are both ambitious and ambiguous. The carbon targets represent significant reductions below business as usual, although the targets are softened by the inclusion of multiple gases and sinks. Although technology optimists believe the agreement is a “free lunch,” some economists see doom. The truth lies in between, but the costs are still likely to be significant. To make targets affordable, the agreement provides for various forms of emissions trading within the so-called Annex I countries, but the agreement is seriously ambiguous on how these programs would operate. There is also significant ambiguity on the roles and responsibilities of developing countries, leaving further doubt on how Kyoto and longer-term goals would be realized; therefore, ratification by the United States is uncertain.
Climate change should be examined holistically. A decision framework should think comprehensively and socioeconomically about risks and damage costs; address adaptation; think comprehensively and realistically about control costs; think long-term; think internationally; and address distributional issues. Specifically, the policy should use well-designed economic incentives to limit greenhouse gas emissions; provide opportunities for credible emissions reductions everywhere; pursue opportunities for credible flexibility in the timing of emissions reduction; enhance prospects for technical progress to make stricter emissions limits more affordable; do more to promote effective adaptation; increase understanding of risks; clarify the clean development mechanism; and maximize transparency and opportunities for trading.
The Kyoto
Protocol:
A Tale of Two (Energy) Sectors
Office of Policy and International Affairs,
U.S. Department of Energy
The implications of the Kyoto protocol for the natural gas and electric sectors through 2010 are likely to be significant. Notwithstanding the pre-Kyoto conventional wisdom that the protocol itself would provide clear signposts, the outlook remains quite hazy even in a scenario that presumes its ratification. Policies that advance the interests of some parts of the natural gas industry can work against the interests of other industry elements, making it hard to assess “industry-wide” impacts. Until implementation strategies are more clearly delineated, it will be hard to reach any bottom lines regarding the sectoral implications of ratification.
The Department’s analyses of electricity restructuring have identified both emissions-increasing and emissions-reducing forces associated with the advent of competition. Examples of the latter include profit incentives for cost-effective efficiency improvements that lower fuel consumption per unit of generation at existing plants; increased market opportunities for efficient new merchant power plants with far better emissions characteristics than the conventional plants they displace; and opportunities for energy-efficiency services bundled with electricity to better meet customer needs. Policies explicitly designed to promote renewable energy or to fund energy-efficiency programs can provide further significant reductions in emissions. When all the relevant factors are considered, competition can be introduced into the electricity sector with confidence that we will “do no harm” to our interest in moving toward, rather than away from, the goals of the Kyoto protocol. While the long-term future of the electricity sector will be significantly impacted by the deliberations regarding the ratification and implementation of the Kyoto protocol, there is no convincing environmental rationale for delaying progress toward greater competition in electricity markets while we await that outcome.
Costs of the Kyoto
Agreement
Charles River Associates
The targets for greenhouse gas emissions set for the United States in the Kyoto agreement will be difficult and costly to achieve. Economic impacts on the United States from any policies sufficient to achieve the limits will be severe and lasting. A different approach could achieve the same climate goals at much lower cost.
The Kyoto agreement calls for the United States to limit its greenhouse gas emissions to 7 percent below 1990 levels by 2010. Based on the EIA forecast of emissions without additional policies, emissions will be 44 percent above the target by 2010. Reducing these emissions will require policies with the force of a carbon tax of $200 per ton or higher. Some Administration analyses estimate lower costs by assuming that new technologies will appear in the market in the next few years and that a global emissions trading system will be put in place. Unfortunately, the serious obstacles to an effective emissions trading system within the Annex I countries and the exclusion of developing countries from carbon emissions limits imply that while energy costs and costs of production will increase dramatically in the United States, they will fall in developing countries. There will be a significant shift of investment in energy-intensive sectors toward developing countries, causing carbon emissions from the developing countries to rise and frustrating the efforts of the industrial countries to lower global emissions.
A sensible long-term strategy for addressing climate change would focus on concentrations in the long term, not near-term emissions targets. It is possible to choose a long-term trajectory with less severe near-term emissions limits that would achieve the same concentration goals at far lower cost than the Kyoto agreement. By delaying emissions reductions until technology is ready and a mechanism for developing country participation is created, it is possible to reduce costs by 90 percent while achieving the same long-term results for the global climate. A more gradual approach would also make it possible to bring developing countries into an international emissions trading system after technologies are available to reduce emissions at low cost.
Kyoto Ratification:
A Money-Making
Agreement for the United States
International Project for Sustainable Energy Paths
Energy models today are seriously flawed in their ability to forecast revolutionary changes in consumer behavior, manufacturer behavior, and technological breakthroughs and costs. Consequently, all such models are likely to overestimate the costs and underestimate the benefits of adhering to the Kyoto protocol. Energy intensity changes in the United States as high as 5 percent per year have been experienced, and there is no good reason why intensity improvements of 3 to 4 percent per year could not be sustained over the long term when all revolutionary changes are fostered.
On the specific point of adjustment costs arising from standards, such costs can be small or large, depending on the manner in which standards are adopted, that is, voluntary versus mandated, timing, and performance versus prescriptive. In any event, adjustment costs are transient and may be dwarfed by net present value benefits in the later years. Adjustment costs may also trigger accelerated innovation that would not have occurred under status quo market structures with high transaction costs, where efficient technologies remain stuck in niche markets and may channel accelerated change into a new, nonincremental direction that otherwise might have been missed. The most efficient set of policies for the United States is a complementary mix of targeted regulatory, incentive, and crosscutting instruments.
Unlocking
Caspian Energy Reserves
Energy Information Administration
The Caspian region has emerged as one of the most highly prospective regions for oil and gas production in the world. Over the past several years, multinational oil companies have entered into joint venture arrangements to exploit this potential, pledging more than $60 billion in capital investment as of early 1998. Production from the region is currently limited, totaling less than 500,000 barrels a day; however, some people project production in excess of 2 million barrels a day within a decade and two to three times that level by 2020. This conference session undertook to review development issues for the region from three perspectives: What is known about the resource base? What are key elements of enterprise development strategies? What geopolitical issues affect levels of risk to regional development?
Exploration Potential of
the Caspian Region
U.S. Geological Survey
The Caspian regions can be described as a small ocean filled with sediment associated with the delta of three major rivers. In various areas surrounding the Caspian, oil and gas production has a long history; however, although the geology has favored offshore production, little has been accomplished so far. Moreover, only limited drilling and seismic study of the offshore areas have been completed thus far, and only a limited amount of onshore deep drilling has been completed. The drilling that has occurred has revealed several super giant oil and gas fields. Tengiz is the most famous, with reserves currently estimated to range between 6 and 15 billion barrels of oil in place. Three distinct geologic basins underlie the Caspian, which have the following conservative estimates for discoverable reserves: 25 billion barrels of oil and 150 trillion cubic feet of natural gas for the South Caspian basin; 4 to 5 billion barrels of oil for the Mid Caspian basin; and 75 billion barrels of oil for the Northern basin. The U.S. Geological Survey is expected to publish a new report on the region in about 12 to 18 months.
Business Development
in the Oil and
Gas Industry in the Caspian Region
Joel Busby,
Mobil Oil Kazakhstan, Inc.
Discovered reserves in the Caspian regions already total approximately 60 billion barrels of oil, 150 trillion cubic feet of natural gas, and several billion barrels of gas condensate. Reserves identified in Kazakhstan alone rival those for all of Western Europe. However, risks abound in attempting to deliver these reserves into world energy markets. The most formidable risk is transportation, since the Caspian is a landlocked region. Mobil is directly involved with one transportation initiative, a 900-mile pipeline through Russia to the Black Sea. At least three other pipeline systems are under consideration, but each poses economic and political difficulties. The shortest route, through Iran, is currently not viable because of U.S. sanctions policy. The U.S. Government currently supports the construction of a new pipeline with a terminus at Ceyhan, Turkey, an already established oil transshipment port; however, the pipeline would be two times longer than the Iranian route and would involve crossing borders of four countries that currently share varying degrees of mutual antagonism. From a political standpoint, the easiest route is one that would pipe Kazakh oil to China; however, if such a route were developed, it would require a pipeline 3,700 miles long—1,200 miles longer than the longest ever built.
The Great Gamble:
Strategic Politics
in the Caspian Basin
Geoffrey Kemp,
Nixon Center for Peace and Freedom
Because of political uncertainties and risks, current development initiatives in the Caspian region can be likened to a “great gamble.” Countries surrounding the Caspian are politically unstable and are subject to a range of internal and external conflicts. New chapters are yet to be written regarding struggles between Armenia and Azerbaijan, Russia and Chechnya, secessionists in Georgia, and Kurds in Turkey. Moreover, Iran’s role in the region and its relationship with the United States can have profound effects on profit opportunities associated with Caspian development. Recent signs of thawing in U.S.-Iranian relations could reduce Caspian regional development risks. In addition, it should be recognized that one of the great wild cards in future developments in the Caspian and, more generally, in the Middle East regions is the manner in which China and perhaps India may view their national interests in gaining access to those regions’ rich resource potential.
Electricity Restructuring: The States of Play
Moderator: Scott B. Sitzer,
Energy Information Administration
The restructuring of the U.S. electricity industry continues to be a widely debated energy issue at both the Federal and State levels. California, New York, and Massachusetts have been leaders in the move to competition; other States—especially those with relatively low electricity prices or access to low-cost resources such as hydropower—have hesitated to open their electricity markets to competition without greater assurance that there will be a measurable consumer benefit. The objective of this session was to provide an overview of the status of State activities with respect to electricity restructuring, from both general and specific points of view. By design, speakers were invited from States with high, average, and low prices of electricity, in order to frame the issues with which each group of States is grappling.
Writing the Rules for Tomorrow’s Future
Edison Electric Institute
U.S. electricity prices to industrial consumers, in contrast to those of Europe, Japan, and Canada, were essentially flat between 1984 and 1995, while those of our trading partners were rising. Our overall prices have fallen every year since 1982, the peak year for U.S. electricity prices. Increased competition in wholesale power markets has also helped prices to fall, with nearly 600 new marketers and exempt wholesale generators entering the market since passage of the Energy Policy Act of 1992. Nevertheless, the movement toward restructuring has continued strongly, especially from those States with prices higher than the national average. Between now and July 1, 2002, at least 16 States will have begun full competition for generation services at the retail level. The new competitors include representatives from a widely diverse set of industries, including current electricity and gas providers, energy producers, computer companies, and even such seemingly unrelated industries as health and legal services.
There are three important trends in the movement to competition: the structure of the industry, codes of conduct, and tax implications. Structural changes are widely divergent. Some, but not all, States are requiring full or functional unbundling of electricity services and diversity of generation assets. Independent service operators are being required by California, Illinois, New Jersey, and Vermont, while others are recommending or studying the issue. Separate power exchanges are being required by California and New Jersey. A number of States are establishing public benefits programs in the areas of energy efficiency, the environment, and minimum renewable generation—as high as 30 percent in California and Maine. Most States are allowing “prudent, legitimate, verifiable, and unmitigable” stranded costs, under certain conditions and with definite time and rate limits. Examples of stranded costs include power contracts and regulatory assets or commitments such as deferred expenses, some employee benefits, and nuclear decommissioning costs. Most stranded costs must be recovered over a period of 4 to 10 years.
Under competition, each participant has certain roles to play, collectively establishing a code of conduct. The role of the incumbent is to put maximum pressure on prices, to bring all of its efficiencies and economies to bear on the market, and to set the competitive market. The role of the government is to adopt policies that lead to benefits to consumers, not protection from competition for certain competitors. Policymakers must distinguish competitive advantage from market power: the former arises from the ability to produce lower-cost goods and services through efficiency and innovation, while the latter is the ability to restrict output and raise prices above competitive levels, generally from a monopolistic franchise.
The tax implications of restructuring could have negative impacts on city, State, and Federal revenues. New competitors may not pay the same taxes to governments that the former monopolists paid, because of issues related to location or ownership (such as municipal utilities that pay no taxes moving into new territory formerly restricted to investor-owned utilities). In addition, lower prices mean lower tax collections in those jurisdictions. Finding ways to mitigate this potential tax loss is a possible barrier to continued movement toward competition.
Restructuring in California— We’re on Our Way
Karen L. Griffin,
California Energy Commission
Restructuring in California begins on April 1, 1998. California has traditionally been a high-cost State for electricity, so it was a prime candidate to become one of the leaders in moving to competition. There was a perception that the regulatory process was not working well in the State, and large customers expressed a strong desire to have direct retail access to electricity services. California’s competitive processes include both an independent system operator (ISO), which performs transmission and system dispatch, and a power exchange, which matches customers with suppliers. All investor-owned utilities (IOUs) in the State are required to participate in the restructured system, including Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric; but the public utilities, which comprise 25 percent of the market, are not required to participate. Nevertheless, Los Angeles Water and Power, the largest public utility in the State, is participating in the new competitive structure.
IOUs have been required to divest themselves of their generating facilities, which will now be owned and operated by independent investors within a fully competitive framework. Transmission will be the responsibility of the ISO, and distribution will continue to be performed by utility distribution companies, regulated by the California Public Utility Commission. The new structure has created a number of surprises, including the challenge of retail unbundling, the creation of new businesses that have no direct involvement in physical electricity flow, and the need to coordinate information that was once internal to utilities across many diverse entities.
The transition period for restructuring runs through March 31, 2002, during which time rates for customers of IOUs are frozen at their June 1996 levels. Following this period, rates will go to competitive market levels. Also during this period, customers are required to pay a competitive transition charge to alleviate stranded costs for the affected utilities. As of this time, only about 39,000 customer accounts, or 0.5 percent, out of 10 million total have requested to switch electricity providers.
Early lessons learned from the California experience include: stranded costs must be dealt with; there must be sufficient time to create the competitive infrastructure, consumer expectations must be made realistic; and enormous legal and contractual upheaval must be expected.
Is It Broke?: Restructuring Encounters
Resistance in a Low-Cost, Public Power State
K. C. Golden,
Washington State Department of
Community Trade and Economic Development
The State of Washington has not yet formally restructured its electricity industry, in part because of fears that retail prices could rise in the Northwest under a competitive environment. An important question in the region is the purpose of restructuring, given its already low prices. Much of the State’s electricity is delivered by public utilities, which have a generally good reputation for price and service. There is fear that more choice in the marketplace for electricity would be confusing and harmful, rather than beneficial to consumers. Consumers are wary of sorting out choices in a deregulated environment, as they already have been forced to do with telecommunications, airlines, and even traditionally free-market products such as sneakers.
Washington started to think about restructuring as early as 1995, in large part because of the importance of the Bonneville Power Administration (BPA), which wholesales much of the electricity in the State, in addition to direct retailing to large customers. BPA found itself undercut in the wholesale marketplace by the competitive impacts of the Energy Policy Act of 1992 and reacted in a number of ways, including curtailing some residential benefits programs and signing long-term contracts with its direct customers that immunized those customers against paying for stranded costs for the Washington Public Power System’s nuclear units. Because of these actions, the region’s State governments undertook a “review” of BPA, looking toward what its role would be in the eventually competitive market. This review recommended a subscription system for BPA’s power output, separation of generation and transmission services, open retail competition by July 1998, a minimum standard for public benefits, use of renewable generation, and funding of conservation programs under full competition. To date, these recommendations have not yet been implemented.
As noted previously, much of Washington’s electricity is provided by public utilities, which are not subject to the State’s public utilities commission. Also, there has always been a certain amount of competition between public and private utilities, because there are no specific territory franchises in the State. One of the unique aspects of restructuring in Washington is that stranded costs essentially do not exist and that in fact there are benefits to be derived as prices move to market levels. One of the proposals is to allow large customers to move to market rates, while keeping small customers at the “regulated” level of prices. Because of the perceived risks of changing the current system, the legislature has not yet passed an enabling bill to restructure. Even without enabling legislation, however, competition “without rules” has already begun at the wholesale and large industrial consumer level, and there need to be rules to channel that competition as efficiently as possible.
Electricity Restructuring in Michigan
Michigan Public Service Commission
Electricity expenditures in Michigan are more than $6 billion annually, with the State consisting of two separate markets, one each for the Upper Peninsula and the Lower Peninsula. Market power issues have surfaced in Michigan, with its participation in a regional independent service operator being one of the major questions in the debate, particularly because of the need to serve the sparsely populated Upper Peninsula. The current restructuring plan is based on authority granted to the Michigan Public Service Commission and does not require legislation for the basics; however, additional legislative proposals remain under discussion and will be needed for securitization.
Michigan’s plan basically splits the generation market into two parts, one for full-service customers and one for direct-access customers. Competitive markets will be phased in over a 4-year period. There will be a rate freeze for full-service customers and no responsibility for “new” transition costs, but stranded costs will be collected through rates. Direct-access customers will be subject to a 0.5-cent-per-kilowatthour charge for transition and stranded costs. By 2002, all customers will have a choice of suppliers.
The main incumbent utilities in Michigan are Detroit Edison and Consumers Energy. Initial estimates of stranded costs are $2.5 billion for Detroit Edison and $1.8 billion for Consumers Energy, based on a market price estimate for generation of 2.9 cents per kilowatthour. The estimated unit cost for stranded cost recovery is about 1.2 cents per kilowatthour. Divestiture is not currently proposed in Michigan. Future challenges include resolution of court challenges, uncertainty about legislation, and the evolution of market processes.
Stimulating Renewables in a Competitive Environment
Energy Information Administration
Few energy markets are more uncertain or simultaneously both more hopeful and discouraging than markets for U.S. renewable energy technologies. Costs for some renewable energy technologies have fallen substantially since the 1980s, greatly narrowing the gap with fossil-fueled generation. Growing environmental concerns further heighten public attraction to clean renewable energy sources. At the same time, however, competing fossil-energy technologies, including those using coal and natural gas, have remained highly competitive by aggressively cutting costs. In addition, the whole technology map is overlaid with changing electricity markets, which are replacing regulated monopolies with freer electricity markets and, thereby, likely reducing protected opportunities for utility investments to advance renewables. This conference session identified and discussed factors and market forces affecting opportunities for renewables: How much will renewable energy technology costs decline and performances improve? What challenges confront renewables? What market changes might affect opportunities for renewable energy growth?
Analysis of Renewable Portfolio
Standard of S. 687
J. Alan Beamon,
Energy Information Administration
At the request of Senator James Jeffords of Vermont, EIA analyzed the provisions of Senate Bill 687, the Electric System Public Benefits Protection Act of 1997, calling for the creation of a renewable portfolio standard (RPS) and emissions caps for sulfur dioxide, nitrogen oxide, and carbon dioxide from electricity generation, among other provisions. The RPS set minimum increasing shares of total electricity generation required from qualifying renewables, including biomass and landfill gas, geothermal, solar, and wind, but excluding hydroelectric and incinerated municipal solid waste. Originally targeted at 20 percent by 2020, RPS shares begin at 2.5 percent in 2000 and increase to 10 percent in 2020. EIA also examined integrated cases including the RPS and emissions caps, limiting emissions from electricity generation by 2005 to 3,580,000 tons for sulfur dioxide, 1,914 million tons for carbon dioxide, and 1,660,000 tons for nitrogen oxides.
Figure 1. Electricity Prices in Alternative Cases, 1996-2020
Source: Energy Information Administration (EIA), Electric Power
Annual 1996,
Vol. 1, DOE/EIA-0348(96/1) (Washington, DC, august 1997); and EIA, AEO98
National Energy Modeling system, runs RPSBSREG.D120197A,
S687RHNU.D1204978B, and FLT1OREG.D120197B.
Compared to a reference case, the EIA analysis shows imposition of a 10-percent RPS leads to increased electricity generation from biomass and wind and reduced generation from coal and natural gas. Under the RPS, electricity prices by 2020 are 5 percent higher than in the reference case but remain 17 percent below 1996 historical prices in real dollars (Figure 1). Results including both the RPS and emissions caps yield even greater renewables penetration, increasing to 14 percent by 2020, with larger declines in coal and natural gas use and electricity prices 14 percent higher than in the reference case. All RPS conclusions are tempered by uncertainties about the availability of the renewable resources at the required scale and the rate of future cost declines for the renewable energy generating technologies.
Micro-Power: How Electric Industry Restructuring Could
Lead to Explosive Growth in Small-Scale Generating Technologies
Christopher Flavin,
Worldwatch Institute
Welcome changes in electricity generating technologies offer a dramatically changed U.S. electricity marketplace. Whereas today electricity consumers are generally restricted to purchases from massive, central-station generators operated by large electric utilities transmitting bulk power through transmission and distribution networks, in the near future purchases will increasingly favor small, end-user-located generating units meeting individual building or other consumer electricity needs, due to advances in small-scale generating technologies.
Photovoltaics, wind, and natural-gas-fired microturbines are among the most promising small-scale generating technologies. Technological improvements have significantly lowered costs for all three, in some cases becoming competitive with the delivered price of central-station power. Furthermore, each technology has valuable environmental advantages over traditional coal-fired generating stations. Finally, because these small-scale technologies are still relatively new, further technical advances and economies of scale should continue driving small-scale technology costs further into the competitive range.
Renewable Energy for the Future
Robert T. “Hap” Boyd,
Enron Wind Corporation
Markets for renewable energy electricity generating technologies are growing rapidly, both in the United States and in global markets. Markets are increasing and costs are declining. At the same time, all renewables face daunting challenges, not the least of which are their own costs and performance as well as continuing strong competition from traditional fossil-based technologies. In the United States, electricity market deregulation remains a challenge to renewable energy investment.
Each major renewable energy technology enjoys opportunities and faces unique challenges. Generation from biomass and waste, including forest and wood wastes and municipal solid waste, is nearly cost competitive and offers the further substantial benefit of significantly reducing U.S. waste volumes. Its prospects should improve as the values of nonpower benefits increase. Geothermal power, which is growing more rapidly outside the United States, needs substantial cost reductions in order to enjoy expansion at home; however, improvements in drilling and reservoir confirmation should help improve geothermal’s competitive position.
Photovoltaics (PV) appear to be offering great promise both domestically and abroad. PV applications are expanding, production continues to increase rapidly, module costs are dropping, and technological improvements are ongoing, both for on-grid applications and for off-grid individual use. PV also enjoys substantial public support. Nevertheless, especially for uses in the United States, PV remains very costly compared with other U.S. central-station generation sources.
Electric power using central station wind energy is also enjoying substantial expansion, especially so outside the United States. International growth, including in Europe and India, remains strong, triggered in part by generally higher electricity prices and also by greater public support for nonfossil alternatives. As wind turbine sizes approach a limit of around 750 kilowatts, additional cost-reducing efficiencies should appear. Wind technologies should succeed where there are concerns about fossil fuels and where electricity prices are higher than in the United States. Deregulation of U.S. electricity markets and stiff competition, however, remain serious concerns to wind-power development.
Fathoming Offshore Oil and Gas
Energy Information Administration
The deepwater offshore Gulf of Mexico is becoming an increasingly important source of oil and gas supply. During the 1990s the number of deepwater fields with proven reserves has increased by more than 50 percent. In 1996, the deepwater area of the Gulf outer continental shelf contributed 17 percent of total U.S. oil production and 6 percent of total gas production—up from less than 2 percent in 1985. In October 1997 deepwater drilling was at an all-time high, a record 31 rigs. The objectives of this session were to present a new deepwater offshore oil and gas supply submodule for NEMS and to discuss the resources, technology, and costs involved in finding and producing offshore oil and gas.
Improved NEMS Deepwater Gulf of Mexico
Oil and Gas Supply Submodule
Michael L. Godec,
ICF Kaiser International, Inc.
The previous NEMS offshore submodule was an aggregated econometric representation. The problems with an econometric approach to such a frontier area are the scarcity of historical data and the rapid changes in technology. The new submodule is a disaggregated, field-level representation, based on a set of price/supply curves generated from field size, water depth, gas/oil ratio, economics, drilling technology, and other information. In this submodule deep water is defined as depths greater then 200 meters. Data for 97 deepwater discoveries were collected from the Minerals Management Service (MMS), publications, and private sources. The resulting resource estimates are quite close to those of MMS, although the model is capable of representing alternative views of the size and characteristics of deepwater resources. In addition to price, drilling capacity is a major driver in the new model.
Estimating Undiscovered Hydrocarbon Resources—
A Probabilistic Methodology
Minerals Management Service
MMS estimates undiscovered oil and gas resources with a “play-based” methodology that captures the range of geologic uncertainties. A “play” is a group of pools present in a geologically homogenous unit having similar petrophysical and geochemical characteristics. Prior drilling data, analogous geologic structures, and geophysical data are among the factors considered in established, frontier, and conceptual plays. A standardized discovery process methodology is used in assessing established plays, while a subjective methodology is used to assess the less certain frontier and conceptual plays. The discovery process model is defined by a formal mathematical equation. In the subjective methodology, data on porosity and thickness of the geologic formations are used to create prospect distributions, which are aggregated into pool distributions. These are sampled to create resource estimates. All estimates are inherently subjective, because they are based on a geologist’s assumptions.
Offshore Drilling Technology
Diamond Offshore Drilling, Inc.
Water depths for offshore drilling began to drop rapidly in the 1970s and are expected to reach 8,000 feet later this year. Offshore drilling rigs have evolved from a land-type rig through submersibles, jackups, conventionally moored semisubmersibles, dynamically moored semisubmersibles, and drilling ships.
Utilization and day rates for offshore rigs have increased significantly over the past 10 years, partly because of advanced technology, including three-dimensional seismic, directional drilling, multilateral completion, and subsea completion. Horizontal drilling has allowed producers to extend their drill bits up to 7.5 miles from their rigs. Multilateral completion allows one well bore to tap several reservoirs; this technology is expected to mature within the next 5 years. Subsea completions allow wells to be tied by pipeline to producing platforms up to 20 miles away. The next important technological advance is expected to be multiphase pumping of oil, gas, and water in pipelines on the sea floor.
Electricity Forecasting in a Competitive Market
Moderator: Robert T. Eynon,
Energy Information Administration
Restructuring of electricity markets is expected to significantly alter the number and kinds of market participants. This in turn will lead to a variety of new products and services that are not known now. As a result, there are a number of challenging analytic issues that need to be addressed. The purpose of this session was to explore the methods available to assess potential outcomes. The issues to be considered include: How will transmission services be priced? How will ancillary services such as voltage stability be provided? Are services such as reactive power important, and will they affect markets? Will players with market power have an impact on prices? Will investors have incentives to bring on new capacity when it is needed, and how will the reliability of electricity services be affected?
Common Pitfalls and Unresolved Issues
in Power Market Price Forecasting
Philip Q Hanser, Brattle/IRI
Issues that determine market outcomes are sensitive to the period of the analysis. For example, weather is an important determinant for short-term considerations, while cost and performance of new generating capacity, economic growth, and environmental regulations become important for longer-term forecasts. There are several pitfalls that analysts need to be aware of when addressing restructuring issues, including the implicit or explicit pricing of generating capacity, the timing and need for new capacity, the mix of capacity, the efficiency of electric generation, and the installed cost of capacity. The price of natural gas is also crucial because it will be the fuel source of the marginal generation unit for many periods of the year.
Policy issues that need to be confronted include determination of whether reserve margins will be set administratively or by the marketplace. Environmental regulations could result in some generating types being no longer economically viable for the marketplace. Changes in cost of production for some generating sources will have no impact on electricity prices if those generation sources are infra-marginal providers. Therefore, competitive markets may have less price variability compared with regulated markets. Available transmission capacity is time sensitive, and, as a result, bidders need to be aware of the premiums necessary to lock in transmission services a month ahead versus an hour ahead. Recovery of capacity costs will occur for all generators whose variable costs of production are below the cost of the marginal source, which is likely to be a gas-fired combustion turbine. When evaluating the value of capacity, it is important not to double count cost recovery associated with capacity payments, ancillary services, etc. Capacity expansion decisions should be based on current market prices. The rapid penetration of natural gas in electricity production suggests that the infrastructure for gas delivery might lag the required need. Because of differences in load shapes, retail price premiums will differ for end users.
Analysts should focus on addressing the correct questions rather than pursuing extreme precision for market determinants. For example, given the wide variation in the projected prices for natural gas, it is better to understand what the impacts of gas prices are than to pursue a precise gas price projection.
A View from the Trenches, Revisited
David J. DeAngelo, PP&L, Inc.
In order to effectively assist in the decisionmaking for strategies to respond to competitive markets, analysts need to rely on economic theory, especially microeconomics. Analysts need to be used and useful in their organizations and should seek out potential users and work interactively with them to meet their needs. Care should be given to problem definition, modeling and forecasting, interpretation of results, and the formulation of strategies. The effects on resource markets need to be addressed in light of restructuring activities. New providers are entering the marketplace and need to be considered. Mergers are also changing the characteristics of electricity markets and will have impacts on other players.
The Impact of the Transmission System
on Electricity Markets—
A Simulation-Based Approach
Thomas J. Overbye, University of Illinois
Electrical transmission networks will have an impact on electricity markets in a competitive environment. Transmission system operations are complicated by the physical laws of nature, which result in a change in flow everywhere in the system when a change is introduced at a single bus in the network. As a result, it is not possible to control the flow of power directly on the system because electrons do not obey contract paths. Operators need to assure stability of the transmission network in order to prevent blackouts. Transmission operators monitor area control error, which addresses proper loading on tie lines, and provide both real and reactive power in response to customer demands. Real power needs are driven by resistive loads, and reactive power needs are determined by magnetic devices such as motors. Reactive power has losses in delivery that are 10 times greater than those for real power, and generating sources need to be provided close to where the demands are located. Costs for transmission services are invariant for increasing levels of load up to the point where constraints on line limits are reached. Policies for transmission planning in restructured electricity markets are currently ill-defined. The financing of transmission lines is particularly problematic. Issues related to power flows beyond the jurisdiction of a given independent system operator have yet to be addressed.
Transportation Issues:
Fuel Economy in a Carbon-Constrained World
Energy Information Administration
Low fuel prices combined with rising income levels have led to flat or slightly declining new light-duty vehicle (LDV) fuel economy over the past few years. Consumers have shifted their preferences toward larger vehicles with higher performance levels and toward light trucks, especially sport utility vehicles. Consumers are also willing to trade fuel economy for safety, a major marketing point for sport utility vehicles. Foreign competition, in markets with fuel prices three to four times higher than domestic prices, has been cited as a reason for domestic manufacturers to develop advanced technologies. In addition, environmental issues are used to justify policies favorable to alternative-fuel vehicles (AFVs) and advanced technologies; however, conventional vehicles have reduced their vehicle emissions, creating an additional challenge for AFVs. AFVs have been encouraged by a variety of policies; however, it is important to ask whether public policy is the route to higher fuel economy.
Kyoto Dreams vs. Market Realities: Prospect for
Big Boost in LDV Fuel Economy
Steve Plotkin, Argonne National Laboratory
We are currently at the brink of a revolutionary technological breakthrough in fuel economy as compared to the past, which had a more incremental approach to fuel efficiency. The most promising technologies are hybrids, fuel cells, lightweight materials, direct injection technology, advanced aerodynamics, and continuously variable transmissions. Even if these technologies were available today at cost-effective prices, significant market penetration would take time because of the slow turnover in the vehicle stock.
The market reality is that fuel economy is not valued, and AFVs must compete against gasoline vehicles with improved emissions. Consumers are currently willing to trade fuel economy for acceleration, structural stiffness, interior space, and luxury equipment such as 4-wheel drive. Safety and emission equipment also tends to work against fuel economy improvements. If consumers were willing to accept 1984 weight and performance levels today, new car fuel economy would be 4 to 5 miles per gallon higher than it now is. The consumer shift from cars toward light trucks is another trend that has reduced fuel economy.
U.S. market conditions will not provide much incentive for higher fuel economy. Although the goals of the Partnership for a New Generation of Vehicles are laudable, achieving vehicle costs similar to gasoline vehicles is not likely. EIA should have scenarios such as technological optimism and technological pessimism in combination with fuel price changes. Although the Annual Energy Outlook 1998 shows the share of light trucks as nearly 46 percent of light-duty vehicles sales, a share in excess of 50 percent by the turn of the century should be considered.
Forecasting Fuel Economy: Do We Need a
New Methodology?
David Greene,
Oak Ridge National Laboratory
Prices and economic growth will have less effect on fuel economy, and the status of technology will likely play a greater role in bringing higher fuel economy to the market. Although EIA has included high and low technology cases, the range in fuel economy is only 2 miles per gallon and should be widened. Fuel economy technologies have penetrated the market, but the NEMS fuel economy module is optimistic in assuming that any technology that can improve fuel economy will penetrate.
NEMS was used in the Five-Lab Study by the national laboratories as the best fuel economy model available; however, NEMS optimizes tradeoffs, assuming perfect markets with perfect information and rational decisionmaking (although a tradeoff between fuel economy and performance is included). The technological potential is huge, but fuel economy markets are not perfect and will not optimize. Consumers look at cost, reliability, and safety then try to satisfy other attributes, including fuel savings. Fuel savings are highly uncertain, due to uncertainties in on-road fuel economy and fuel costs. The value of fuel savings to the consumer is constant over a wide range of fuel economy improvement. Combining that with manufacturer risk, the end result is sluggish fuel economy improvement.
The impetus for improving fuel economy comes from public goods, such as energy security and environmental and sustainability issues, not from market forces. Technology change is the key, but, because technology change is difficult to predict, fuel economy is difficult to forecast. Future policies could have more of an impact on fuel economy than prices and economic factors, but they are uncertain. EIA should include scenarios with different possible future policies.
The Challenge of Restricting Consumption of
Low-Cost, Plentiful Energy
Roberta Nichols, Alternative Fuels Consultant
Technology is the easy part; however, making technologies affordable and bringing them to the market are the real challenges. The greenhouse gas issue has inherent problems as an impetus to fuel economy improvements, because it is a long-term issue with no immediate consequences, gradual change is hard to measure, global cooperation is required, and the knowledge level is uncertain. Customers will need incentives to change, because current fuel prices are leading to increased vehicle-miles traveled, larger vehicles, and higher consumption. U.S. safety regulations also lead to heavier cars. Also, there are diminishing returns to fuel economy improvement with higher levels of fuel economy.
Reformulated gasoline and diesel fuel have reduced the incentive to shift to AFVs in order to improve air quality. A lack of infrastructure remains problematic for some AFVs, such as those using natural gas, which could play a major role but are limited to commercial fleets because of the lack of a refueling infrastructure. Global warming issues will increase interest in biomass fuels and other new energy sources. Among the advanced technologies, fuel cells have the greatest potential for fuel economy improvement. Fuel cells currently can use methanol, hydrogen, or gasoline. Methanol is the best hydrogen carrier because of its high fuel density relative to hydrogen storage. Methanol can also be made from any organic material and costs less than ethanol. Hydrogen has a limited range and lacks a refueling infrastructure. The gasoline reformer has many problems that need improvement, such as cost and complexity of design and operation.
The challenge is to overcome customers’ risk aversion, compete against low gasoline prices, and address the problems of advanced technology vehicles, such as higher vehicle costs, expensive or nonexistent infrastructures, uncertain resale values, and unproven reliability. Premature introduction of advanced technologies could be deadly. Market incentives are needed, not mandates, because manufacturers can only sell what consumers want. For now we can utilize more fuel-efficient diesel engines, pursue the goals of the Partnership for a New Generation of Vehicles, develop fuel cell technology, continue production of AFVs, and disseminate factual information that will assist consumers in making informed choices.
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