Introduction

Many products are derived from crude oil, and they serve many different markets. The transportation sector is the largest market for petroleum fuels (66.2 percent of petroleum consumed in 1997), followed by the industrial sector (25.5 percent of petroleum consumed), the residential sector (6.0 percent), and the utility sector (2.3 percent). Of the fuels produced from crude oil, distillate fuel oil, residual fuel, and petroleum coke are most likely to be affected by electricity deregulation. Overall, however, there should be little impact on crude-oil-derived fuels.

Figure 18. Utility Consumption of Fossil Fuels, 1965-1996 (Click graph to view full size)

• Utilities having more flexibility and stronger economic incentives to use the most economical fuels.
• Oil companies having more options for dealing with their low-valued fuels, such as high-sulfur residual fuel and petroleum coke.

Utility Use of Crude-Oil-Derived Fuels

Once the utility industry is past the transition from a regulated to a deregulated industry, competition should increase. Fuel adjustment clauses will disappear, and utilities will be under more pressure to find ways of reducing their operating costs. Fuel costs, which represent more than 75 percent of production costs for fossil-fueled generating units, are a major target for cost efficiency improvements.

Utility Fuel Costs

Utilities' use of fossil fuels has changed over the years as economics and regulations among the fuels have changed. In general, coal has been the cheapest fossil fuel on a Btu basis and the major fossil fuel used by utilities. The utility sector is also the largest end-user for coal. Coal is burned in generating units serving base load. Petroleum in the form of two products, residual fuel oil and petroleum coke, is also used to serve base load, although petroleum coke comprises very little of the utility petroleum fuel being used (5.0 percent in 1997).

Figure 19. End Uses of Residual Fuel Oil, 1965-1996 (Click graph to view full size)

After the crude oil price increases of 1979-1980, utility use of residual fuel plummeted. Although consumption showed some strength again after crude oil prices declined in 1986, utility consumption fell during the 1990s as residual fuel lost ground to other fuels, such as natural gas. The Powerplant and Industrial Fuel Use Act of 1978 discouraged use of natural gas, even though residual fuel prices outstripped natural gas prices. Natural gas use declined slightly while the Fuel Use Act was in force, but the Fuel Use Act was repealed in 1987.

Figure 20. U.S. Fossil Fuel Consumption, 1965-1996 (Click graph to view full size)

Petroleum coke comprises a small part of utility fuel consumption, but increasing coke production, resulting from increasing residual fuel conversion and falling prices, is making this product attractive to some utilities. Supply is adequate for substantial utility growth. Utilities used only about 19.2 thousand barrels of petroleum coke per day in 1997, but 306 thousand barrels per day were exported, most of which were green coke (fuel-grade coke). The price of green coke¹³⁹ is reported to have fallen from as high as $50 per ton (nominal freight-on-board U.S. Gulf Coast) in the early 1980s to $6 per ton in 1996. The average delivered cost of petroleum coke to utilities in 1996 was 78.2 cents per million Btu, compared with the average delivered price of coal at 128.9 cents per million Btu.¹⁴⁰ Although coke's fuel properties are different from those of coal, it is being blended with coal in some facilities without the requirement of substantial equipment modifications.

One other factor affecting the price of residual fuel and petroleum coke relative to other fuels that is not evident in the aggregate figures is the environmental quality of the fuels. Utilities use little high-sulfur residual fuel oil. Generally, the share of residual fuel oil receipts containing more than 1 percent sulfur has remained less than one-third (32.5 percent in 1985, 29.0 percent in 1990, 27.8 percent in 1995, and 33.0 percent in 1996).¹⁴¹ Because utility residual fuel use, including that of high-sulfur residual fuel, has been exhibiting a downward trend, and there is a general move to reduce sulfur in all fuels, the market for high-sulfur products is shrinking. The markets for fuels with low environmental quality are disappearing internationally as well as domestically, leaving refiners with products that are more difficult to sell at a profitable price.

Utility Actions To Reduce Fuel Costs Affecting Petroleum Fuels

The strategies employed by utilities to reduce fuel costs that could affect petroleum-based fuels include:

• Repowering old, underutilized, fossil-fuel plants
• Increasing fuel flexibility by installing technologies that allow for burning multiple types of fuel or by blending fuels, such as petroleum coke with coal, when it is economical
• Revisiting contracting and inventory policies to take the best advantage of market opportunities while balancing market risk.

Repowering

As utilities look ahead to increased competition, they are scrutinizing their old, underutilized facilities for cost improvements. Many old plants are not cost competitive on a marginal basis and therefore are run only at low capacity utilization. Utilities are determining what is the best cost strategy: continuing to run as is, refurbishing, retiring, or repowering. In the case of oil-fueled units, retiring or repowering would further reduce the demand for residual fuel.

Repowering involves replacing all or part of the steam supply system in a plant with a new steam supply system  that  is  usually technologically different. Other portions of the plant are then refurbished and reused. The purpose behind repowering is to increase plant capacity at a competitive cost and to improve heat rate, thereby improving total plant efficiency while reducing emissions. For example, old coal-, oil-, or gas-fired boilers are candidates for replacement with efficient gas turbines and new heat-recovery steam generators in a combined-cycle system. The Electric Power Research Institute (EPRI) reports that, to date, gas repowering has been used heavily in areas where gas and oil are used for intermediate and baseload generators, such as California, Florida, and the mid-Atlantic States.¹⁴² In 1996, these areas accounted for more than 56 percent of the petroleum fuel burned in steam turbine prime movers.¹⁴³ Most of the petroleum used was residual fuel oil.

Of the 263 thousand barrels per day of residual fuel oil consumed by utilities in 1996, about 127 thousand barrels per day was used in units that began commercial operation more than 25 years ago, including units that use residual fuel as an alternative fuel. The figure provides an upper bound on residual (fuel oil) demand that might disappear as a result of repowering or retiring. This potential "at risk" demand represents 15 percent of the total residual fuel consumption in 1996 in all sectors (848 thousand barrels per day). Although changes from repowering and retiring units would not occur quickly, electricity deregulation is likely to hasten the changes. The substantial amount of "at risk" utility residual fuel (oil) use reinforces the continuation of a diminishing market for this product.

Increasing Fuel Use Flexibility

Another means of saving on fuel costs is to make use of technologies that can burn multiple fuels, such as gasification units. Use of such technologies by utilities will serve only to depress the use of residual fuel as long as its price remains at a premium relative to the prices of other fossil fuels.

Fuel blending, however, is providing opportunities for petroleum coke, which can be more economical than coal. Utilities with pulverized coal plants or gasification units can make use of petroleum coke blended with coal. Florida utilities, which are located close to the major coke-producing refineries on the Gulf Coast, have been showing interest in burning coke blends. Tampa Electric Company has completed test burns and is soliciting fuel-grade petroleum coke to use in a 20-percent blend with coal in its Big Bend Units 3 and 4. Seminole Electric Cooperative received approval to burn coke blends of up to 30 percent in its generating station and began using some petroleum coke in 1997. Florida Power Corporation is also exploring the possibility of burning small blends of coke (5 percent) in its Crystal River Units 1 and 2. Florida Power feels that, even at that low blend percentage, it could save more than $1 million a year; however, the company is running into permitting problems over concerns that the coke is high in sulfur content and the Crystal River units do not have scrubbers. Outside Florida, coke blending is being used in other plants, including American Electric Power plants in Ohio and plants owned by Northern Indiana Public Service Company.¹⁴⁴

Fuel Purchasing and Inventory Policies

As deregulation proceeds, utilities will be looking at their purchasing and inventory policies as a means of managing fuel-cost risk. The spur of competition is reasonably expected to result in the more economical use of inventories, with benefits for the electricity consumer. In addition, these managerial developments may benefit distillate fuel oil markets, especially in the Northeast. With the supply-demand balance under stress during peak winter months, fuel purchasing and inventory policies have encouraged some utilities to buy more than needed immediately and at uneconomical prices. What has concerned other users of distillate fuel, particularly the many residential users of heating oil, is how much utilities want to buy during such periods and what prices they are willing to pay for the last barrel. The consequences for available supply and marginal prices affect the entire heating fuel market.

Utilities generally rely on distillate fuel to meet peak demand, competing with distributors supplying the residential and small commercial heating fuel markets at the same time. With interruptible natural gas contracts, the utilities must buy more distillate fuel during peak periods in lieu of curtailed natural gas. During the regulatory period, the inventory policies of some utilities have encouraged or even required purchases in excess of the immediate need to generate electricity to maintain minimum stock levels or at least slow down the net stock draw.

How much utilities are willing to pay for distillate fuel has been influenced by fuel adjustment clauses that allow utilities to pass fuel costs through to consumers without a full rate hearing. This has reduced the financial risk to utilities of bidding at high prices during peak demand periods, regardless of near-term weather and market prospects. Utilities also have more latitude than heating oil dealers to bid higher prices for distillate fuel, since the price of distillate represents a small part of the overall cost of generating electricity. Hence, end-use consumers of electricity are less affected by increases in the price of distillate than are heating oil customers.

Only the minimum stocking requirement and fuel adjustment clauses are expected to change given deregulation, but those changes should be sufficient for utility actions to change. In a deregulated environment, utilities will want to optimize how they buy and stock distillate fuel, using futures markets and financial devices for hedging and minimizing cost without jeopardizing their ability to meet customer needs.

Figure 21. Prices of No. 2 Heating Oil, Winter, 1989-1990 (Click graph to view full size)

Options for Refiners

Refiners have already been taking advantage of the beginning of deregulation brought about by the Public Utility Regulatory Policies Act of 1978 (PURPA). Refineries are heavy users of electricity and steam, and they have already built many cogeneration facilities, some of which sell power to the grid. As described below, many oil companies are entering the power generation business as a result of their experience in building and running power generation units in other parts of the world as outlets for natural gas production.

Deregulation is also providing refiners with more options to deal with evolving heavy fuel and waste disposal problems. Refiners are producing more residual fuel and petroleum coke with high sulfur and high metals contents, but the market for these products is diminishing as environmental restrictions increase.

A Growing Dilemma

From a refiner's perspective, residual fuel is a "leftover." Refineries are run with a focus on the higher valued products, such as gasoline and distillate. Residual fuel oil in 1997 represented only about 5.4 percent of crude oil input to refiners, down from 7.1 percent in 1990, and from 12.0 percent at its share peak in 1977. Residual fuel is what is left after the higher valued products are removed from crude oil. The shrinking market for residual fuel, its low value, and an increasingly heavy crude oil slate¹⁴⁷ have caused refiners to install upgrading equipment that converts residual material to higher valued products. One such conversion process leaves refiners with petroleum coke. As more residual fuel is upgraded by using cokers, more petroleum coke is produced, some of which is used as fuel.

A large part of the diminishing market for residual fuel derives from the fact that the environmental qualities of residual fuel have been deteriorating as a result of the changing slate of crude oils being processed by refiners. Refiners have been using more high-sulfur crude oil and more crude oil with high heavy metal content. Most of the sulfur, metals, and inert material found in the crude oil are not removed as the oil is processed, but are concentrated in the residual fuel oil. Coking has been a standard process used to convert residual fuel with high sulfur and heavy metals content; however, coking further concentrates the sulfur and metals into the petroleum coke.

Metals content can be an even greater problem than sulfur content. Burning either residual fuel or coke containing high sulfur in a boiler can be handled with standard emissions control devices, but heavy metals content can result in hazardous airborne pollution and high-metal-content ash, which can become a disposal problem. In the future, high-sulfur, high- metals residual fuel and coke may even become "wastes" to be disposed of rather than fuels to be sold. Deregulation, however, is presenting more alternatives for the oil industry to dispose of such materials, as discussed below.

As the demand for low environmental quality fuels diminishes, refiners will have a harder time selling these products profitably. As the use of new, clean coal technologies for power generation grows, the market for low-quality fuels will expand, since many new technologies can burn dirty fuels safely. In the meantime, even export markets are disappearing as countries worldwide add more environmental restrictions to fuel combustion, including transportation use of residual fuels (bunker fuels). One source indicates that the "market for high-sulfur, high-metals coke has constricted to the point where some U.S. refiners are faced with negative netbacks on their coke production."¹⁴⁸

Options for Handling Low-Quality Residual Fuel and Petroleum Coke

To deal with high-sulfur, high-metals residual fuel oil or petroleum coke, refiners have the following options:

• Converting the residual fuel to other products through processes such as coking, catalytic hydrotreating, and hydrocracking
• Selling some or all of the residual fuel or fuel-grade coke they produce to utilities or others who can burn the fuel cleanly using air emission control systems
• Gasifying the fuel and removing the sulfur and metals before using the synthetic gas to create steam, liquid fuels, chemical products, and/or electricity.

Installing conversion equipment to reduce or eliminate the volume of residual fuel is expensive and still may not solve the refiners' dilemma of getting rid of high-sulfur, high-metals fuel. When coking is used to convert the residual fuel, the sulfur and metals are concentrated in the petroleum coke. Refiners look at their unique circumstances to determine whether conversion and upgrading investments are worthwhile, including a refinery's ability to treat the products resulting from the residual fuel conversion.

The paragraphs above on "Increasing Fuel Use Flexibility" discussed how the second option of selling the fuel to those that can burn it cleanly is providing opportunities for the petroleum coke market. As long as transportation costs do not remove the current price advantage that coke has over coal, high-sulfur coke can be burned economically with coal, particularly in plants already equipped with scrubbers. Although high-sulfur residual fuel also can be burned in plants with scrubbers, other fuels are more economical.

The third option for refiners eliminates the production of residual fuel oil or petroleum coke, presents some of the more interesting long-term solutions, and is an option that has been directly affected by deregulation. Refiners faced with a growing problem of getting rid of high-sulfur, high-metals residual fuel and coke along with waste disposal problems from other processes are looking more closely at gasification, a process in which electricity is one of the products. Before PURPA, refiners' choices to burn fuel and generate electricity were limited. Units had to be sized to produce only as much electricity as was needed internally. PURPA removed that restriction, requiring utilities to buy excess power from generators that met certain efficiency criteria, which refinery cogeneration facilities would generally meet. After PURPA, refiners could build units that generated electricity in excess of their own needs both to plan for future expansion and to earn extra revenue. The ability to size units for selling power to the grid adds another dimension to the economics of gasification that could not be considered prior to PURPA.

The Gasification Option

Gasification is a process that converts a variety of hydrocarbon feedstocks, such as coal or residual fuel, to a clean synthetic gas that can then be converted to other products, such as chemicals, electricity, industrial gases, or fuels. Figure 22 shows a process in which feedstocks are gasified and the sulfur is removed from the resultant gas product. Hydrogen is removed from the desulfurized synthetic gas for other applications. Some of the gas then is burned directly to create electricity and heat for further process use, and the remaining gas can be converted to chemicals. The steam from the heat recovery steam generator can be fed to a steam turbine instead of being directed to process use, which would create a combined cycle after the gasification unit instead of just a combustion turbine as shown. The configuration with a steam turbine added is called an integrated gasification combined-cycle unit (IGCC).

Figure 22. Illustrative Schematic of a Gasification Power System (Click graph to view full size)

Refiners probably are one of the best markets for gasification technology because of their ability to use the various products that can be produced and their need to dispose of materials that can be used as feedstock in gasification units. The refinery gasification application has been referred to as a "trigeneration system" that produces  steam,  power,  and  synthesis  gas, which, in turn, can be used to produce hydrogen and/or chemicals, such as ammonia.¹⁵⁰ Gasification economics are driven by the following factors:

• The capital costs of the facility, including the need for an air separation plant to produce oxygen
• The trend toward heavier, and, in some cases, higher metal content, crude oils that result in high-sulfur, high-metals residual fuel or coke, which are facing more environmental restrictions
• The need to dispose of a variety of wastes
• The cost savings realized from the ability to produce some needed products in the refinery, such as hydrogen, industrial gas, steam, and electricity
• The revenue from producing additional products, such as ammonia, methanol, fertilizer, and excess electricity for sale to the grid.

Although the economics of gasification are specific to each plant, some general information is available. Fluor Daniels has indicated that the costs for a heavy-oil-based IGCC unit might be from $950 to $1,100 per kilowatt of generating capacity, compared with costs for a coal-based IGCC that might run from $1,300 to $1,500 per kilowatt.

Environmental factors play a large part in driving the latest interest in refinery gasification. The fuel for the gasification units is likely to be high-sulfur, high-metals residual fuel or coke, along with waste streams, such as off-spec chemicals, waste oils, sludge settled from refinery process water streams, and tower bottoms from phenol production units. At the Texaco El Dorado Refinery gasification facility, the U.S. Environmental Protection Agency (EPA) has authorized "exemption from hazardous waste permitting requirements and other hazardous waste regulatory requirements."¹⁵¹ With the gasification unit being exempt from Resource Conservation and Recovery Act requirements, the EPA has distinguished between burning hazardous wastes in an incinerator and gasifying them to produce other products. This means that a refinery using gasification does not have to incur expenses for disposal of the hazardous waste and probably reduces long-term liabilities associated with storing and disposing of hazardous wastes.¹⁵²

Gasification is beginning in the refinery industry without any government subsidies to use the new technology. Two refineries using gasification to create power and other products are the Texaco El Dorado refinery in Kansas, which started up its gasification project in the summer of 1996, and the large Shell Pernis refinery in The Netherlands, which started operating in 1997. Other combination refinery and power projects are being proposed worldwide, such as in Japan and Europe. Two projects in Italy have already secured financing and should soon begin construction.¹⁵³

In summary, the ability of refiners to participate in the electricity generation business outside their own facilities has opened the door to the resolution of other issues. First, refineries are prime cogeneration markets because of their own steam and power needs. Furthermore, technologies such as gasification can resolve other refinery problems, and the economics are being driven by factors other than those associated with traditional cogeneration, including the need to dispose of waste and the ability to produce useful products besides electricity and steam.

Oil Companies as Electricity Generators

The impact of deregulation is probably affecting only a few crude-oil-based fuels, but it is providing oil companies with the opportunity for expanding synergistically into a related business. Oil companies have been moving into the electricity generation business for years. Within the United States, many refineries and oil field operations use cogeneration units. Many of the units that have been built since PURPA was enacted sell power to the grid as well as satisfying a facility's own needs. In 1996, the refining sector had 2,322 megawatts of capacity in operation, on standby, or under construction.¹⁵⁴ (Utilities reported 145,129 megawatts of petroleum- and gas-fired capability in 1996.¹⁵⁵)

Most recently, offshore opportunities are providing oil companies more experience with electricity generation. In many parts of the world with large natural gas reserves, power generation is the most economical use of the gas. It was a natural extension for the oil companies participating in developing those gas reserves to move into power generation to create a market for the gas production.

Royal Dutch Shell Group, Unocal, Mobil, and ARCO are exploring moves into power generation to make use of their unused gas discoveries.¹⁵⁶, ¹⁵⁷ Exxon, which has been in the electricity generation business internationally for years, is moving into China through several joint ventures.¹⁵⁸ Texaco has indicated its intent to be as big in power generation as it is in gas production. Coastal Power, a subsidiary of Coastal, develops power projects, and Coastal Electric Services Company is involved in marketing power. Amoco also has a subsidiary set up to market power, although Amoco has not indicated any intention to go into the merchant electricity generation business.¹⁵⁹ This offshore activity implies that, with deregulation, the oil industry will be an important electric power player in the United States as capacity needs grow in the future.

Summary

Deregulation will serve to hasten the decline of an already disappearing market for residual fuel oil. Increasing competition is causing utilities to scrutinize their fuel costs ever more closely, and residual fuel is not competitive in today's markets. In addition, larger shares of residual fuel and petroleum coke with high sulfur and heavy metals content are being produced as a result of the changing slate of crude oil inputs to refineries; however, environmental restrictions are shrinking the potential markets for these fuels. Refiners may be faced with handling these products at a cost as hazardous wastes rather than as fuels.

As utilities increase their search for cheaper fuel options, fuel blending of petroleum coke has surfaced as an economical route in some cases. Petroleum coke prices currently are highly competitive with coal prices in some regions, such as Florida, which is near the large coke-producing refineries on the Gulf Coast. In these areas, coke is being blended with coal either in quantities small enough not to violate environmental restrictions or in plants that have adequate pollution control devices and waste handling to deal with the low-quality coke.

While deregulation, on the one hand, is hurting refiners by hastening the demise of the residual fuel market, it also is expanding opportunities for dealing with poor-quality fuels and wastes. Refiners are beginning to look to gasification as a means of using high-sulfur, high-metals residual fuel and coke, along with a number of refinery waste streams, as feedstocks to produce synthetic gas, which could then be used to produce power, steam, and a variety of chemicals (such as hydrogen and ammonia) of use to refineries. PURPA and subsequent legislation have increased the flexibility of sizing such units to make the most of a facility's economic situation. In addition, a recent EPA ruling on a Texas refinery allows the facility to treat the waste streams being used as gasification feedstocks as fuels rather than as hazardous wastes. The associated cost savings and potential liability reduction add positively to the economics of production. With wastes and high-sulfur, high-metals fuels as gasifier feedstocks, the feedstock costs for gasification projects might even become a negative cost. That is, it would cost the refinery more to dispose of the fuels by some other means.

In utilities' search for more economical fuel strategies, distillate fuel prices might be affected by deregulation, but whether for better or worse is unclear. Utilities are and will continue looking at their inventory and fuel purchasing policies as deregulation removes fuel adjustment clauses and eliminates requirements for minimum inventory levels. Distillate is used largely as a peaking fuel along with natural gas. Natural gas contracts to utilities and large industries are generally interruptible during times of large peak needs so that residential natural gas users will have adequate supplies. Utilities then rely more heavily on distillate fuel oil and even propane. Because they buy in large quantities, if utilities enter the market when supplies are tight and prices are rising, they can drive prices even higher. When evaluating the number of times that this may have occurred historically, compared with the carrying costs of extra inventory, some utilities may find it economical to carry less inventory and buy more distillate during times of market stress if necessary. Others may find it cost effective to carry more inventory to keep from having to pay market stress prices.

Finally, the petroleum industry has for some time played a role in domestic electricity markets as a result of its own cogeneration activities. The industry also has a growing role in the international power generation business. The increasing involvement of petroleum companies in power generation implies a potentially strong role for this energy industry in U.S. electricity markets in the future.

Endnotes

139. Different kinds of petroleum coke are produced and used in different markets. Green coke is the form of coke used as fuel. Some green coke is calcined (pyrolized above 2600 F) to remove the volatile materials and create a high carbon-to-hydrogen ratio material that can be used in producing graphite and carbon electrodes and anodes. Most of the coke consumed in the United States is used for anode manufacture. Less than 10 percent of the fuel-quality green coke produced domestically is burned as fuel domestically. In 1997, utility use of petroleum coke represented only 5.1 percent of total petroleum coke demand. Green coke is generally calcined or exported.

140. Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants 1996, DOE/EIA-0191 (Washington, DC, May 1997), Table 31.

141. Energy Information Administration, Cost and Quality of Fuels for Electric Utility Plants 1996, DOE/EIA-0191(Washington, DC, May 1997), Table 10.

142. T. Moore, "Repowering as a Competitive Strategy," EPRI Journal, Vol. 20, No. 5 (September/October 1995).

143. Energy Information Administration, Electric Power Annual 1996,Volume 1, DOE/EIA-3048(96)/1 (Washington, DC, August 1997), Table 16.

144. C. Jones, "Fuel Management," Power (January/February 1997), p. 25.

145. Energy Information Administration, An Analysis of Heating Fuel Market Behavior 1989-1990, SR/OG/90-01 (Washington, DC, June 1990).

146. Competitive economics may dictate distillate fuel inventory levels for the long term that some utilities may regard as inadequate when faced with peak electricity demand. While a few utilities may seek to bid prices high enough to meet their needs, the impact their smaller volumes are likely to have on the overall supply-demand balance in the Northeast should be less than what has occurred historically.

147. Heavy crude oils contain a higher percentage of high boiling point material, or "bottoms," than do light crude oils.

148. D.L. Heaven, "Gasification Converts a Variety of Problem Feedstocks and Wastes," Oil and Gas Journal (May 27, 1996), pp. 49-54.

149. D.L. Heaven, "Gasification Converts a Variety of Problem Feedstocks and Wastes," Oil and Gas Journal (May 27, 1996), pp. 49-54.

150. D.R. Simbeck, R.L. Dickenson, and A.D. Karp, "Markets for Gasification Technologies in the New World of Competitive Energy," Keynote presentation given at EPRI Gasification Conference (San Francisco, CA, October 1996), p. 4.

151. F.C. Jahnke, J.S. Falsetti, and R.F. Wilson, "Coke Gasification Costs, Economics and Commercial Applications," Paper No. AM-96-54, National Petroleum Refiners Association Annual Meeting (1996), p. 10.

152. W.E. Preston, "Texaco Gasification Power Systems, Status of Projects," Paper given at the EPRI Gasification Conference (San Francisco, CA, October 1996), p. 6.

153. D.R. Simbeck, R.L. Dickenson, and A.D. Karp, "Markets for Gasification Technologies in the New World of Competitive Energy," Keynote presentation given at EPRI Gasification Conference (October 1996, San Francisco, CA), p. 7.

154. Energy Information Administration, Form EIA-867, "Annual Nonutility Power Producer Report."

155. Energy Information Administration, Electric Power Annual 1996, Volume I, DOE/EIA-0348(96)/1 (Washington, DC, August 1997), Table 6.

156. "Shell Targets Electric Power for Unused Gas," Oil and Gas Journal (February 3, 1997), pp. 27-28.

157. "Asia's Electric Gas Prices," World Gas Intelligence (August 9, 1996), p. 1.

158. "Exxon Seeks Power Project in China," Electric World (May 1997), pp. 12 and 14.

159. "US Gas Firms Weigh Need to Enter Power Business," World Gas Intelligence (December 13, 1996), p. 8.