Challenges of Electric Power Industry Restructuring for
Fuel Suppliers

The current movement to restructure U.S. electricity generation markets and make them more competitive may lead to changes in the financial risks and demands on the supply and transportation infrastructures for the fuels used in electricity generation. This report examines the potential impacts of restructuring of the U.S. electric power industry on the markets for electricity generation fuels--coal, nuclear, natural gas, petroleum, and renewable energy.

Included in this report are a brief review of electric power industry restructuring already in progress at the Federal and State levels, detailed discussions of the major qualitative issues for each of the major fuel supply markets, and a presentation of a range of possible quantitative results, based on the Energy Information Administration's (EIA) National Energy Modeling System (NEMS).

The following paragraphs summarize the discussions of issues related to the markets for coal, nuclear, natural gas, petroleum, and renewable fuels, followed by the quantitative analysis of electric power industry restructuring on fuel markets.

Coal

The U.S. coal and electric power industries are tightly linked: more than 87 percent of total domestic coal consumption is used for generation by utilities, and coal accounts for more than 56 percent of utility power generation. Thus, competitive electricity generation markets will have far-reaching implications for the coal industry. Power generators will attempt to pass on market risks to coal producers and carriers (primarily railroads) wherever they can. As a result, coal purchase contracts will likely become shorter in duration and lower in price. The traditionally stable coal market may absorb some of the volatility of electricity markets.

Electric power industry restructuring is expected to result in renewed pressure for cost cutting and consolidation in the coal industry, extending the trend of the past decade or more. Future gains in productivity will result from the computerization of administrative tasks and continuing improvements in production technology. Taking advantage of economic returns to scale will be another important component of the cost reduction effort. Small firms may be forced out of business, and large firms are likely to continue increasing in size through acquisitions and mergers. In addition, the trend toward shorter contract durations and an uncertain customer base will lead financial institutions to evaluate coal mines on a "balance sheet" basis rather than on the traditional project financing basis, increasing the pressure for industry consolidation.

Risk management will become an important new tool for coal producers. Coal futures markets, already being developed in some areas, will provide a mechanism for risk hedging and for price discovery. Risk reduction may also be accomplished by vertical integration, alliances with railroads or power producers, or the creation of multi-fuel conglomerates. Restructuring will change the business relationships among coal producers, railroads, and power generators, creating incentives for new alliances and the convergence of energy markets.

Emerging changes in the structure of the railroad industry may also affect the economics of both the coal and electric power industries. Transportation costs are a major component of the delivered price of coal to electricity generators, and over half of all coal consumed by them is delivered by rail. As the demand for low-sulfur western coal increases in the coming years, the importance of railroads will become even greater. The full effect on rail rates of the recent and ongoing consolidation of major railroads remains to be seen: the railroads may continue to lower rates as they achieve greater economies of scale, or they may be unwilling to lower rates once they establish their market power, as many coal shippers are concerned will be the case.

Nuclear Power

Nuclear power accounts for about 13 percent of current U.S. electricity generating capacity and about 19 percent of total electricity generation. As the States restructure electricity markets over the next few years, however, some nuclear power plants are expected to become uneconomical. Competitive electricity prices may be so low that nuclear power plant operators will not see enough income to enable them to recover the costs of operating and maintaining the plants and the costs of capital improvements, such as steam generator replacements. In the immediate future, some nuclear power units will be at risk of early retirement as a result of restructuring.

The additional inability of plant operators to cover a plant's full costs, including capital costs, under restructuring produces "stranded costs." The stranded cost recovery issue will not, however, be the major factor in retirement decisions. Ultimately, the long-term viability of nuclear power generation lies in the industry's ability to keep its operating costs competitive with new sources of generation. For nuclear plants, operating costs after deregulation will be driven mainly by plant size, age, capacity factors, and requirements for new capital improvements. Issues surrounding the recovery of future decommissioning costs remain to be resolved. In the long run, however, the market value for long-term firm capacity and for electricity in each region of the country will determine the value of nuclear power plants.

Average fuel costs make up only about one-fourth of the operating costs for nuclear power plants, but the competitive environment created by a restructured electric power industry will encourage nuclear power plant operators to reduce all operating costs, including the costs of purchasing and managing nuclear fuel. Moreover, if early retirements of nuclear power plants result from competition in electricity markets, the demand for nuclear fuel will be reduced. To compete, suppliers in the nuclear fuel industry will be forced to reduce prices or improve efficiency. In an industry that has already seen significant contraction during a decade of depressed prices, further consolidation is likely as companies seek to pool resources and spread risks.

Natural Gas

Natural gas, used for about 9 percent of electric utility generation, is primarily used during peak demand periods and is the preferred energy source for new generating capacity. The electric power and natural gas industries are both network industries, in which energy sources are connected to energy users through transmission and distribution networks. As the restructuring of electricity markets proceeds, the development of institutions, such as futures contract markets and electronic auction markets, could lead to greater integration of the electricity and natural gas industries and the emergence of competitive energy markets.

The availability of market information and public markets for natural gas and electricity will be a key to the development of an integrated energy market for those commodities. Price volatility for gas and electricity will spur the growth of futures markets and promote the efficient allocation of resources. Challenges for the natural gas industry include the development of shorter term contracts with standard terms and low transaction costs, improvements in deliverability and flexibility, and the synchronization of same-day nominations for deliveries of gas and electricity. Metering and measuring of gas flows throughout the industry are also likely to become more important as more frequent exchanges of energy take place among market participants.

Oil

Restructuring of the U.S. electric power industry should have little overall impact on crude-oil-derived fuels (distillate and residual). In 1996, for example, petroleum, which fueled 2.2 percent of electric utility generation, accounted for only 2.3 percent of the Nation's petroleum consumption. With the deregulation of electricity generation and the resulting incentive for power generators to lower fuel costs, the use of relatively expensive residual fuel oil for electricity production is likely to decline even further. As a result, petroleum refiners may be faced with a growing problem: how to dispose of "leftover" residual fuel and petroleum coke. Among other options, two possibilities are related to electricity markets: (1) selling petroleum coke to electricity generators for use as a fuel blending component, and (2) gasification at the refinery by using integrated gasification combined-cycle (IGCC) technology to produce steam for process heat and for electricity production.

Finally, electricity deregulation may provide oil companies with opportunities to expand synergistically into a related business. A number of oil companies have gained experience in electricity production as a means of exploiting their natural gas holdings in other countries, and they could become important players in the U.S. market as capacity needs grow in the future. Meanwhile, as economic considerations increasingly dictate when distillate fuel oil (and other fuels) will be purchased and at what price, electricity generators will be relieving the pressure on both available supply and the marginal price in the very volatile heating oil market that characterizes the Northeast during severe cold snaps.

Renewables

Because electricity generation from renewable sources (other than hydropower) generally is more expensive than power from conventional sources, unconstrained competition in electricity generation would likely result in a reduced role for renewable energy facilities. As a result, a variety of proposals under consideration by State legislatures and by the U.S. Congress include specific provisions to support the continued development and use of renewabl energy. Renewable portfolio standards and system benefits charges are among the programs being considered. Green marketing and pricing programs, already being implemented by electric utilities, may also provide a means to increase consumer demand for electricity from renewable fuels.

The role of renewable energy sources in competitive electricity markets will also depend on the cost and performance of the individual renewable fuels: biomass (primarily wood), geothermal, solar, and wind. In addition, because renewable energy generating facilities generally depend on the availability of energy resources at specific sites--often at sites remote from major electricity grids--transmission issues will affect the penetration of renewable fuels in the electricity generation market.

Quantitative Impacts on Fuel Markets

A quantitative analysis was conducted to determine the impacts that competitive electricity generation markets could have on fuel supply industries. To capture the uncertainty about the conditions under which a competitive electricity market will operate, EIA prepared a range of possible outcomes (i.e., analysis cases) based on different assumptions about key electricity and energy variables. Two full competition cases (assuming low and high fossil fuel consumption), in addition to a partial competition case (the reference case from EIA's Annual Energy Outlook 1998 (AEO)), were compared with a no competition case in order to illustrate the possible impacts of competition.

In all the cases, natural-gas-fired turbines and combined-cycle plants garner most of the market for new generating capacity when more competition was assumed. From 1996 to 2015, additions of coal-fired capacity are projected to range from about 20 gigawatts in the low fossil fuel case to 49 gigawatts in the no competition case, whereas additions of natural gas turbine and combined-cycle capacity range from about 256 gigawatts in the no competition case to 324 gigawatts in the high fossil fuel case. In all the cases, natural gas is projected to have an increasing share of electricity generation as demand levels grow (Figure ES1).

(Click Graph to view full size) Note: Data do not include nonutility generation for own use, cogeneration, or electricity imports. Renewable/other includes pumped storage hydroelectric. Source: Energy Information Administration, Office of Integrated Analysis and Forecasting, National Energy Modeling System runs nocomp.d010698a, aeo98b.d100197a, complo3.d031298b, and comphiD3.d031398b.

Unless required by Federal policies, the restructured electricity market is not projected to stimulate renewable energy technologies. Overall, the cases analyzed suggest that renewable resources will remain more costly than fossil fuel alternatives through 2015 and will penetrate electricity markets only to the extent compelled, such as by a renewable portfolio standard that mandates generation from renewable sources. If policies require increased use of renewable energy, the cases suggest that average electricity prices will increase slightly. Biomass, wind, and geothermal would be the most likely technology choices for expanded use of renewable energy.

In the competition cases examined, natural gas production is projected to range from 0.8 percent lower to 2.2 percent higher than in the no competition case in 2005 and from 0.3 percent to 6.0 percent higher in 2015. The projected average natural gas prices at the wellhead range from a low of $2.05 per thousand cubic feet in 2005 to a high of $2.61 per thousand cubic feet in 2015 (all prices expressed in real 1996 dollars). Overall, the results from all the cases suggest that restructuring in the electric power industry will stimulate demand for natural gas and that rising demand will lead to higher wellhead prices as the discovery process progresses from larger and more profitable fields to smaller, less economical ones. The projected price increases also reflect more production from higher-cost sources, such as offshore conventional recovery and onshore unconventional gas recovery from such sources as tight sands, Devonian shales, and coalbed methane. Electricity restructuring is not expected to have a significant impact on crude oil production because petroleum-based generation is a small share of overall electricity generation.

In the national coal market, two factors lead to significant changes: (1) the environmental regulations creating a national market for sulfur emissions credits, which encourages minimization of sulfur emissions and, thus, fuel sulfur content; and (2) the competitive electricity generation market, which rewards the minimization of generation fuel costs. The impacts of both changes are seen in the cases analyzed here. Across the cases, competition tends to favor the use of natural gas over coal for electricity generation because natural-gas-fired power plants are generally projected to be more economical than coal-fired plants. The exception is the high fossil case, which assumes higher demand for electricity than in the AEO reference case, no renewable portfolio standard, and continued operation of relatively higher-cost generating plants (up to 6 cents per kilowatthour). The cases vary in their projections of consumption shares for low-, medium-, and high-sulfur coals, regional production shares, and minemouth prices. Production of high-sulfur coal is relatively stable across the competition cases and declines by about 19 million tons in the low fossil case in 2010. In contrast, low-sulfur coal production is more volatile and increases by as much as 80 million tons in 2015 in the high fossil case due to increased demand for coal while requirements to limit sulfur dioxide emissions are tightening.

Total energy consumption for electricity generation is projected to grow from 1996 to 2015 in all the cases analyzed. Consumption levels increase for all fossil fuels and renewable sources, whereas consumption of nuclear electricity generation declines as a result of retirements and the lack of new construction. There is little variation in total energy consumption among the competition cases, except when higher demand levels are assumed. There are, however, variations in the levels of consumption of natural gas and coal across the cases, with natural gas tending to gain and coal to lose market share as the industry moves from a regulated to a competitive environment.

The average price of fuel used for electricity production in 2015 is projected to be about the same as in 1996 in all but the high fossil case (Table ES1). In the high fossil case, an increase of about 11 percent in the average price is projected because of higher natural gas prices resulting from assumed higher drilling costs for onshore production. Natural gas prices increase slightly in the other cases but are offset by an almost 30-percent decline in coal prices between 1996 and 2015.

Electricity prices are projected to decline from 1996 levels, even in the case of no competition, because of lower coal prices and modest additions of new capacity. In the competition cases, prices fall even further as a result of efficiency improvements in plant operations and fewer additions of capital-intensive coal plants. Prices in competitive markets are based on marginal costs, which tend to be lower than the current average embedded costs.

Contact:

Suraj Kanhouwa

suraj.kanhouwa@eia.doe.gov

Phone: (202) 287-1919

William Watson

wwatson@eia.doe.gov

Phone: (202) 287-1971