ROCKY MOUNTAIN MINERAL LAW INSTITUTE. Chapter 1 IMPACT OF THE RESTRUCTURING OF THE ELECTRIC POWER INDUSTRY ON OIL, GAS, COAL,

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1 Reprinted with permission of the author. ROCKY MOUNTAIN MINERAL LAW INSTITUTE Chapter 1 IMPACT OF THE RESTRUCTURING OF THE ELECTRIC POWER INDUSTRY ON OIL, GAS, COAL, AND OTHER MINERAL PRODUCERS Judith M. Matlock Davis, Graham & Stubbs LLP Denver, Colorado Synopsis ' 1.01 Introduction ' 1.02 Background on Electricity Generation and Delivery ' 1.03 Background on Utility Dispatch ' 1.04 Traditional Structure of the Industry ' 1.05 Federal Regulation of the Electric Power Industry ' 1.06 State Regulation of the Electric Power Industry ' 1.07 Development of Supply and Demand for

2 Competition [1] Stability in the 1960s [2] Development of Demand for Competitive Supply Alternatives in the 1970s [a] Economic Changes [b] Technological Changes in Generation [c] Technological and Other Changes in Transmission [3] Need for Transmission Access or Wheeling ' 1.08 Federal Legislative and Regulatory Actions Which Encouraged Competition [1] Public Utility Regulatory Policies Act 1978 (PURPA) [a] Encouraging Non-Utility Generato [b] Transmission Access Under PURP [2] FERC Efforts to Encourage Competiti and Transmission Access [3] The Energy Policy Act of 1992 ' 1.09 Problems with the Traditional Structure ' 1.10 Restructuring the Industry [1] Order No. 888-Restructuring at the Wholesale Level 1-2 [2] Restructuring at the State Level [3] Federal Legislation Regarding Retail Wheeling

3 ' 1.11 Stranded Costs [1] Definition [2] Stranded Cost Issues [3] Order No. 888 Approach to Stranded Costs ' 1.12 The Restructured Electric Industry ' 1.13 Impact of Restructuring on Mineral Producers as Major Consumers of Electric Power ' 1.14 Significance of the Electric Generation Market to Mineral Producers as Fuel Suppliers [1] Overall [2] Significance of Electricity Generation to Coal Producers [3] Significance of Electricity Generation to Gas Producers [4] Significance of Electricity Generation to Oil Producers ' 1.15 Anticipated Impacts of Electric Industry Restructuring on Fossil Fuel Producers [1] The Bottom Line for Fuel Producers [2] Impact of Excess Generating Capacity [3] Capacity Additions [4] The Environmental Factor ' 1.16 Coal Producer Impacts and Responses [1] Changes in Contracts [2] Stranded Costs [3] Consolidations, Vertical Integration, and Coal By Wire

4 [4] Technology ' 1.17 Gas Producer Impacts and Responses [1] Competition From Industry [2] Competition From Electricity [3] Stranded Costs [4] Gas By Wire [5] Small Independent Producers ' 1.18 Conclusions ' 1.01 Introduction The electric power industry is being restructured to give consumers access to competitively priced power. While transmission and distribution of electric power remain a natural monopoly, sufficient competition among the generation sector has developed. Accordingly, on March 4, 1997, the Federal Energy Regulatory Commission issued Order No to restructure the wholesale power market to enable wholesale customers to realize the benefits of such competition. State legislators and public utility commissions in the majority of the states are considering giving retail customers similar access to competitively priced power, and some states already have legislation and regulations in place. Bills were introduced but not passed in the 104th Congress and have been introduced and are pending in the 105th Congress to fix a date by which the states must act on retail access. Whether or not federal legislation is passed, it is considered by most commentators simply a matter of time before all of the states will act to allow retail customer access. Mineral producers are impacted by this restructuring of the electric power industry in two ways. First, mineral producers are significant users of electric power. They, like most industrial customers, have an economic stake in having access to the cheaper power supplies that restructuring promises. Second, coal, natural gas, and oil producers are providers of fuel to electric power generators. As their fuel purchasers are subjected to competition, these mineral producers will experience cost and other pressures in order to retain, and perhaps increase, their share of the electric power generation market. The purpose of this paper is to provide a brief overview of the restructuring of the electric power industry and then to discuss the anticipated impacts for mineral producers, both as consumers of power and as suppliers of generation fuel. ' 1.02 Background on Electricity Generation and Delivery

5 In simplified terms, electricity is generated by the rotation of a magnet inside a coil of wire. 2 The magnet is turned by a turbine. For the majority of electricity generated in the United States, the turbines are turned by steam which is produced from water heated by the burning of fossil fuels. The average efficiency for central-station, fossil fuel generation in the United States has remained fairly constant since 1970 at 30%. 3 This means that approximately 70% of the heating value (BTU content) of the fossil fuels is not used but is lost as reject heat. New combined-cycle plants can achieve fuel efficiencies of up to 60% by using the reject heat in the electric generation process. When combined with a cogeneration process where additional reject heat is captured and put to use for heating, cooling, or process purposes, fuel efficiencies of up to 90% may be realized. 4 The size of generation stations is measured in kilowatts (KW) or megawatts (MW). Production of power is measured in kilowatt hours (kwh) which is defined as the amount of electricity produced by running a generator that is one kilowatt in size for one hour. 5 From the generating plants, electricity is transmitted long distance over high voltage transmission lines. Typical voltages for long distance transmission are in the range of 115 kv to 765 kv. Substations reduce the voltage for subtransmission. Subtransmission voltages are in the range of 34.5 kv to l14 kv. Some large industrial customers take delivery at these voltages. However, for most customers, voltages are further reduced for distribution to consumers at between 2.4 kv and 34.5 kv. 6 Throughout the transmission and distribution process, power is lost, much of it by resistance heating of the lines and transformers. The United States is divided into three interconnection areas. The Western Interconnect encompasses the Western two-thirds of Montana, all of Wyoming,.a small portion of Southwestern South Dakota, all of Colorado, most of New Mexico, and all of the states west of these states. The ERCOT interconnection area encompasses most of Texas. Everything not in the Western Interconnect or ERCOT is in the Eastern Interconnect. In each interconnection area, all of the generators and synchronous motors are spinning at the same speed and are in the same point in their rotation at any given point in time. There is only very limited transmission of power between interconnection areas. ' 1.03 Background on Utility Dispatch Each electric-consuming appliance or piece of machinery requires a certain quantity of generated and delivered electricity to operate. The required quantity is measured in watts, thousands of watts (M or millions of watts (mw). For example, a 60-watt light bulb requires 60 watts of power delivered to the socket to produce light. 7 The amount of energy actually consumed by a customer is measured in thousands of watt-hours or kilowatt hours (kwh). It is a function of how long power is consumed by each electric appliance or machine. A 60-watt bulb turned on for one hour would consume 0.06 kwh of electricity (60 watt-hours

6 divided by 1000). 8 Most customers do not operate their electricity-consuming appliances or machinery at full capacity 24 hours a day. Instead, their demand for power varies based upon time of day and other factors such as startup of motors. A customer's demand for electricity over time is known as its load profile. Since electricity cannot be stored, each utility can and must project the aggregate load profile of its customers so that it is ready to supply electricity on demand. Each utility determines the aggregate expected load profile of its customers throughout the day, based primarily on historical data. It plans the operation of its generating plants and its power purchases based upon this data and monitors actual system load in order to make adjustments. As load increases, the utility decides whether to purchase power or throttle up a generating source based primarily on incremental cost, i.e., which source would provide the next megawatthour at the lowest cost. This is because, at least prior to restructuring of the industry, the capital cost of each facility and all other fixed costs were recoverable in rates no matter how the facility was operated. However, not all dispatch decisions are made on this basis. Market, technical, and political forces also affect dispatch decisions. For example, gas-fired internal combustion generators can be brought on line very quickly and, therefore, are well-suited to handle peak loads even though they may be more expensive to run on an incremental cost basis. Another exception to economic dispatch involves power that utilities are obligated to purchase from qualifying facilities under the Public Utility Regulatory Policies Act of These purchases must be made regardless of incremental costs. In the restructured industry, dispatch decisions will be based upon market forces rather than the centralized decision-making described above. 10 ' 1.04 Traditional Structure of the Industry Although the electric industry began as a competitive industry in the late 1880s, by the 1920s, it had become dominated by natural monopolies which were vertically integrated (i.e., they generated, transmitted, and distributed most of the electric power consumed in this country). Consumers purchased and received a "bundled" product, delivered power. It is this traditional structure which is now being restructured. The purpose of the restructuring proposals is to "unbundle" or separate generation from transmission and distribution and to require utilities to give sellers and purchasers of generated power access to the transmission and distribution grids. The transmission and distribution of power on a stand alone basis is known as "wheeling." ' 1.05 Federal Regulation of the Electric Power Industry In response to the concentration of economic and political power in public utilities and the absence of

7 antitrust enforcement, Congress passed the Federal Power Act of (FPA). The FPA applies to: (1) Transmission of electric energy in interstate commerce, 12 (2) Sale of electric energy at wholesale (i.e., for resale) in interstate commerce, 13 (3) Facilities used for such transmission or sale, and (4) Any person who owns or operates facilities used for such transmission or sale. Such persons are defined in the FPA as "public utilities." 14 The FPA does not apply to the United States, a State or any political subdivision of a State, any agency, authority, or instrumentality of the foregoing, and any corporation wholly owned by the foregoing. 15 The FPA also does not apply to rural power cooperatives under the supervision of the Rural Electrification Administration (REA). 16 The Federal Power Commission was originally charged with enforcing the FPA. Today, the Federal Energy Regulatory Commission (FERC) is the agency responsible for enforcing the FPA. ' 1.06 State Regulation of the Electric Power Industry State public utility or public service commissions are responsible for regulating transmission of electric energy in intrastate commerce, distribution of electric energy to consumers, and the sale of electric energy to retail customers. The jurisdiction of these state agencies includes the siting of generation and transmission facilities (including FERC-jurisdictional transmission facilities); the vast majority of generation asset costs; retail service territories; local service issues including reliability of local service; administration of integrated resource planning and utility buy-side and demand-side decisions including DSM (demand side management); utility generation and resource portfolios, and non-bypassable distribution or retail stranded cost charges. 17 The companies subject to the jurisdiction of state commissions are also known as "public utilities." ' 1.07 Development of Supply and Demand for Competition [1] Stability in the 1960s The 1960s were characterized by (1) substantial increases in scale economies which encouraged large, vertically integrated utility companies, (2) technological improvements, and (3) only moderate increases in input prices. The result was price stability and an absence of pressure on regulatory commissions to change the industry structure. 18 [2] Development of Demand for Competitive Supply Alternatives in the 1970s

8 From the late 1960s through the 1970s, economic and technological changes, as well as changes in the transmission sector of the industry, gave rise to a demand for competitive power supplies, made possible the development of alternative supplies, and created a demand for transmission access to bring supply and demand together. [a] Economic Changes The economic changes included rapid inflation, higher nominal interest rates, conservation, and economic downturns which left many utilities with excessive generating capacity. Nuclear and other capital-intensive baseload facilities under construction based upon projected increases in demand were over budget and behind schedule, due in part to increased environmental regulation, at a time when the demand for the generating capacity to be supplied by such facilities did not materialize. The result was higher electricity rates. For residential customers, rates between 1970 and 1985 tripled in nominal terms, which was a 25% increase adjusted for inflation. During the same period, rates for industrial customers quadrupled in nominal terms, which was an 86% increase adjusted for inflation. 19 Some industrial customers constructed their own generating facilities to reduce power costs. Their "bypass" of the electric utilities resulted in rate increases for remaining customers. These economic changes created pressure on regulators to investigate the prudency of utility decisions to build generating plants. Such investigations resulted in a reduction in earnings for utility shareholders as nuclear plants were written off 20 and rate increases to reflect the effects of inflation were delayed. Utilities became reluctant to commit capital to long-term2l construction decisions involving large scale generating plants. [b] Technological Changes in Generation At the same time, technological changes occurred in generation and transmission. The economies of scale embraced in the 1960s were no longer being achieved. The industry discovered that larger generation units needed greater maintenance and experienced longer downtime. As a result, the price of each incremental unit of electric power exceeded average cost. Smaller size units became cost effective. Combined cycle units (generally using natural gas) offered the advantages of lower capital costs, increased reliability, and relatively minimal environmental impacts. Conventional steam units using circulating fluidized bed boilers and fueled by coal or other conventional fuels were also found to be more efficient and less 21 polluting generating resources. [c] Technological and Other Changes in Transmission Finally, there were changes in the transmission sector. Technological advances made it economic to transmit electric power over long distances at higher voltages. This made it feasible for utilities with lower cost generation sources to reach previously isolated systems where customers were captive to higher cost generation.

9 Additionally, there were increased coordinated operations, and utilities reduced their reserve margins. The result was that substantial amounts of electricity moved between regions 23 and between utilities in the same region. [3] Need for Transmission Access or Wheeling The missing link for further development of competition in power generation was the lack of transmission access. Except under the limited circumstances set forth in section 202(a) and (b) of the Federal Power Act of 1935, public utilities were not' required to wheel electric energy. Some utilities provided transmission access as a result of litigation 24 or through Nuclear Regulatory Commission license conditions and voluntary preference power transmission arrangements associated with federal power marketing agencies. 25 However, the general lack of transmission access remained a critical impediment to the development of competition. Die need for transmission access was addressed by Congress in the Public Utility Regulatory Policies Act (PURPA) in 1978 and the Energy Policy Act (EPAct) in 1992 and by the Commission's aggressive interpretation of those statutes to encourage/compel transmission access in certain circumstances. ' 1.08 Federal Legislative and Regulatory Actions Which Encouraged Competition [1] Public Utility Regulatory Policies Act of 1978 (PURPA) [a] Encouraging Non-Utility Generators In 1978, Congress enacted the Public Utility Regulatory Policies Act (PURPA). 26 This Act was enacted as part of a legislative package which also included the Natural Gas Policy Act of 1978 and other legislation, all of which was designed to combat the nationwide energy crisis which developed in the mid-1970s. Section 210 of PURPA required FERC, in conjunction with state regulatory authorities, to promulgate rules to require electric utilities to offer to (1) sell electric energy to qualifying cogeneration facilities 27 and qualifying small power production facilities, 28 and (2) purchase electric energy from such facilities. The purpose of these provisions was to increase the use of these sources of energy and thereby reduce the demand for traditional fossil fuels. TI-ie facilities which could take advantage of this PURPA provision came to be known as qualifying facilities or QFs. The rules promulgated by the Commission as required by PURPA created a market for QF power and gave QFs access to backup power from such utilities. The result was that from 1989 through 1993, the number of qualifying facilities grew from 576 to 1200, and installed QF capacity increased from 27,429 megawatts to 47,774 megawatts. 29 FERC concluded in Order No. 888 that, "[t]he rapid expansion and performance of the QF industry demonstrated that traditional, vertically integrated public utilities need not be the only sources of reliable power." 30

10 PURPA imposed technological, size, and ownership limitations on QFs. 31 Non-traditional power producers who could not meet the QF criteria built new capacity without the PURPA benefit of mandatory purchase requirements or backup electricity rights. These new power producers included independent power producers (often single-asset generation companies with no transmission or distribution facilities) and affiliated power producers (i.e., power producers affiliated with electric utilities but owning assets not included in utility rate base). The number of non-traditional power producers, other than QFs, grew froin 249 facilities in 1989 to 634 facilities in 1993 and installed capacity increased from 9,216 megawatts to 13,004 megawatts during the same time period. 32 Further growth was restricted by the requirements of the Public Utility Holding Company Act 33 which inhibited new entities from entering the generating business. Further growth was also restricted by the need for transmission access to be able to compete in electricity markets. [b] Transmission Access Under PURPA Congress attempted to address the need for transmission access in PURPA, which added sections to the FPA. Section authorizes the Commission to issue an order requiring the physical connection of any cogeneration facility, any small power production facility, or the transmission facilities of any electric utility with the facilities of an applicant. Applicants may be any electric Utility,31 federal power marketing agency," geothermal power producer (including a producer which is not an electric utility), qualifying cogenerator, or qualifying small power producer. Section allowed FERC to order wheeling by an electric utility upon the application of any electric utility or federal power marketing agency. However, as originally enacted under PURPA, there were numerous restrictions on the Commission's ability to order such wheeling. For example, there was a requirement that the Commission determine that such order would reasonably preserve existing competitive relationships. Accordingly, section 211 was not an effective means for obtaining transmission access. [2] FERC Efforts to Encourage Competition and Transmission Access FERC encouraged voluntary open access transmission by authorizing blanket approval, on a case-bycase basis under section 205 of the FPA, of market-based rates for generation services. Sellers of generation services who desired market-based rates, and their affiliates, had to lack market power or mitigate any market power. In determining whether market power existed, FERC considered whether the seller or its affiliates owned or controlled transmission facilities in the service area and, therefore, could foreclose other generators from competing. If so, FERC would allow the transmission facility owner to file open access tariffs (point-to-point transmission) as a means of mitigating market power. 38 FERC also started using its authority to approve mergers or consolidations under section 203 of the FPA to require companies to file open access tariffs (point-to-point) to mitigate the anti-competitive effects of the merger or consolidation. 39 Finally, FERC allowed investor owned utilities (IOUs) to sell at market-based rates only if they opened

11 their transmission system to competitors. 40 [3] The Energy Policy Act of 1992 Congress again responded to the demand for competitive power and transmission access by enacting Tittle VII of the Energy Policy Act of 1992 (EPAct). 41 This statute was intended to promote greater competition in bulk power markets by encouraging new generation entrants and by expanding the Commission's jurisdiction to approve wheeling applications. In section 711 of EPAct, Congress amended the Public Utility Holding Company Act of (PUHCA) to exempt certain generators from PUHCA. These generators were defined as exempt wholesale generators (EWGs). 43 This provision of EPAct removed a barrier to the further growth of independent power producers and affiliated power producers. In section 721 of EPAct, Congress amended section 211 of the FPA in several respects. As amended, the Commission has authority to order a transmitting utility 44 to provide transmission services (including any enlargement of transmission capacity necessary to provide such services) to any (1) electric utility, (2) federal power marketing agency, or (3) any other person generating electric energy for sale for resale, Congress removed the requirement that the Commission determine that a section 211 order would reasonably preserve existing competitive relationships. However, Congress also added a new subsection (h) to section 212 of the FPA to expressly prohibit FERC from requiring transmission directly to an ultimate consumer or to an entity who would resell to an ultimate consumer. Congress excluded certain entities such as political subdivisions of a state and public utilities having a duty to serve under state or local law. As a result of this prohibition, a retail customer cannot take advantage of Order No. 888 by creating an entity to purchase and resell power to it. Although such a transaction is technically a wholesale sale, i.e., a sale for resale, it would constitute a sham wholesale transaction under section 212(h). ' 1.09 Problems with the Traditional Structure In Order No. 888, the Commission found that (1) new generating capacity could be built and operated at prices substantially lower than many utilities' embedded costs of generation '45 (2) non-traditional generators were taking advantage of this opportunity to compete and had increased their share of total U.S. electricity generation from 4% in 1985 to 10% in and (3) consumers were demanding access to lower cost supplies available in other regions of the United States and access to the newer, lower cost generation resources. 47 However, notwithstanding federal efforts to promote transmission access, at the time the Notice of Proposed Rulemaking was issued which led to FERC Order No. 888, only 21 public utilities had any form of open access transmission. 48 FERC found that the electric industry remained dominated by vertically integrated utilities that, as owners or controllers of transmission services, could exclude generation competitors from the market, thereby favoring the transmission owner's own generation. This occurred through outright denial of transmission access or through access that was discriminatory

12 as to rates, terms, or conditions of service. 49 FERC also found that, although it had issued orders requiring wheeling in 12 of the 14 section 211 cases it had acted on, because of the significant time delays involved under section 211, section 211 applicants were still at a severe disadvantage compared to the owners of the transmission system. FERC concluded that, "based on the mounting competitive pressures in the industry and rapidly evolving markets,... section 211 alone is not enough to eliminate undue discrimination." 50 FERC's conclusion regarding the structure of the electric industry was that, in the absence of nondiscriminatory open access tariffs, the development of fully competitive bulk power markets could not occur, and consumers would be deprived of the benefits that would be expected from such a competitive market. 51 ' 1.10 Restructuring the Industry [1] Order No. 888-Restructuring at the Wholesale Level Order No. 888 restructures the electric power industry at the wholesale level. Specifically, Order No. 888 requires all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce: (1) Open Access Tariff Requirement. To offer non-discriminatory open access transmission and ancillary services to wholesale sellers and purchasers of electric energy in interstate commerce. 52 (2) Functional Unbundling. To separate (unbundle) its use of its own transmission system for the purpose of engaging in wholesale sales and purchases of electric energy from other activities and transmission services (including ancillary services) and to take transmission services for its wholesale sales and purchases under the filed transmission tariff of general applicability. This requirement is to ensure comparability. (3) Information Access. To develop and maintain a same-time information system that will give existing and potential transmission users the same access to transmission information that the public utility enjoys. (4) Non-Discriminatory Open Access Tariff Provisions. To file open access non-discriminatory transmission tariffs that contain minimum terms and conditions of nondiscriminatory service. The tariff must be the open access pro forma tariff attached as Appendix D to the Final Rule (the "Pro Forma Tariff') or such other open access tariff as may be approved by the Commission consistent with Order No [2] Restructuring at the State Level The lack of FERC jurisdiction to order retail wheeling is fueling the demand for restructuring on the state level to give consumers access to competitively-priced power. Under the traditional state

13 regulatory structure, competition is not available because (i) state public utilities laws give state utilities exclusive service territories in which they are free from competition by other state public utilities, and (ii) state definitions of what constitutes public utility activity discourage non-traditional power generators from directly serving retail customers because of the fear of becoming a public utility. The status of retail wheeling efforts varies significantly from state to state. 54 Some state legislatures or public utility commissions have already ordered retail wheeling by a date certain. California was the first state to do so starting with the adoption of a state commission policy decision in In the Western United States, regulations or legislation requiring retail wheeling have now also been adopted in Arizona, 56 Montana, 57 and Nevada. 58 Other states are in the process of studying retail wheeling even though legislative efforts have, to date, not been successful. In the West, such states include Colorado, 59 Idaho, 60 Kansas, 61 Nebraska, 62 New Mexico, 63 Utah, 64 Texas, 65 and Wyoming. 66 In some states, utilities have Proposed voluntary retail wheeling programs including utilities in Idaho 67 and Washington. 68 [3] Federal Legislation Regarding Retail Wheeling Federal legislation regarding retail wheeling was first introduced in 1996 before the 104th Congress but such legislation was not enacted. Several bills have already been introduced in the 1997 Congress. On February 10, 1997, Representative Schaefer (D-CO) introduced HR 655 which sets December 15, 2000, as the date by which states may either "elect" to establish retail electric service choice in accordance with the Act or be subject to FERC implementation. On April 8, 1997, Representative DeLay (R-TX) introduced a bill with a more aggressive timetable. HR 1230 provides that each person has the right to purchase electric service from any electric service provider, notwithstanding any other law, and proposes an effective date of January 1, On June 19, 1997, Senator Markey (D-MA) introduced HR 1960 which does not establish a deadline for retail customer choice. Instead, it proposes a "carrot and stick" approach to encouraging states, under pressure from their public utilities, to adopt the standards and requirements of competition set forth in the Bill. State public utilities receiving certificates of compliance with these standards and requirements from their state regulatory authorities will be exempt from certain sections of the Public Utility Holding Company Act of 1935"" and from the provisions of section 210 of the Public Utility Regulatory Policies Act of An electricity caucus has also been created to generate support for legislation to bring competition to the electricity industry. Whether or not any of these bills are passed, the threat that Congress might act is increasing the pressure on states to provide retail wheeling on their own terms before Congress does it for them. 71 ' 1.11 Stranded Costs

14 [1] Definition One of the major issues in the restructuring of the electric industry is what to do with stranded costs. Stranded costs are unrecovered costs incurred by regulated utilities in reliance upon the pre-open access regulatory scheme. Under that scheme, utilities had an obligation to serve the public in exchange for which they were allowed to recover their prudently incurred costs and given an opportunity to earn a reasonable rate of return on certain investments. In the restructured electric industry, utilities will have to compete with each other and with non-utility generators to sell power. In order to be able to compete effectively, utilities may no longer be able to recover their full costs for power purchases from qualifying facilities under PURPA; investment in generation plants, particularly nuclear plants; other regulatory assets; and their own work force. There is no consensus on the size of the stranded cost issue although two third-partty estimates referenced in Order No. 888 exceeded $100 billion. 72 The challenge is to solve the stranded cost issue without discouraging the development of a free market for electric power. The treatment of stranded costs affects the ability of consumers to take advantage of direct access and may affect the playing field between coal and gas-fired generation. It also raises concerns for the environmental community which fears that allowing full stranded cost recovery will enable utilities to continue to operate older, dirtier plants which would shut down absent such recovery. [2] Stranded Cost Issues The first issue regarding stranded costs is whether they should be recoverable at all. From the utilities' perspective, all costs which satisfied the prudency test when originally included in rate base should be recoverable. The argument is that the utilities relied on the existing regulatory scheme in incurring such costs and, therefore, should be protected from underrecovery of such costs in a competitive environment. Opponents, on the other hand, argue that utilities should not be entitled to recover their stranded costs because utility investors have already been adequately compensated by the returns on investment allowed under the existing regulatory scheme. 73 Additionally, there is a concern that allowing stranded cost recovery will discourage customers from taking advantage of retail wheeling. This would delay the transition to competition and, in the process, possibly damage the development of competition or at least cause distortions in the market for power while stranded costs are being recovered. If a state decides that stranded costs should be recoverable at all, additional issues are: how to define stranded costs, whether mitigation should be required, which customers should be required to pay for stranded costs," and how stranded costs should be recovered. [3] Order No. 888 Approach to Stranded Costs

15 Order No. 888 allows public utilities to recover wholesale stranded costs from departing customers by direct assignment as an exit fee or through a surcharge on transmission. The Order defines wholesale stranded costs as any legitimate, prudent, and verifiable costs incurred by a public utility or transmitting utility to provide service to a customer that subsequently becomes, in whole or in part, an unbundled wholesale transmission services customer of such utility. However, such costs are recoverable only if the utility can show that it had a reasonable expectation that it would continue to serve the customer after expiration of its existing requirements contract with that customer. Additionally, stranded costs only include those costs which are stranded as a result of the customer's departure from the utility's generation system by using the utility's open access transmission. Costs associated with loss of sales customers due to the normal risks of competition, such as selfgeneration, cogeneration, or industrial plant closure, are not stranded costs. 75 ' 1.12 The Restructured Electric Industry In the restructured electric industry, electric utilities and non-utility generators (NUGs) will compete to sell electricity. They will market their product directly and through power marketers and brokers, the new middlemen of the power industry. Not all of these players will be allowed to charge market-based rates. For those engaging in wholesale transactions (sale for resale), an application must be filed with FERC for authority to charge marketbased rates. 76 State commissions will decide whether market-based rates may be charged for retail sales. Electric utilities are merging with each other and with other types of energy suppliers to increase their generation fuel-purchasing leverage and their plant utilization efficiency and to enable them to more effectively compete. Electric restructuring is also leading to convergence of the gas and electric sectors. Companies with interests straddling both forms of energy are being created. Since 1995, mergers have been announced between Washington Energy and Puget Sound P&L; ENSERCH Corp. and Texas Utilities; United Cities Gas and Atmos Energy; Portland General and Enron Corp.; NorAm Energy and Houston Industries; Pacific Enterprises and Enova Corp.; PanEnergy Corp. and Duke Power Co.; and Valero Natural Gas and PG&E. 77 In anticipation of electric industry restructuring, in March 1996, the New York Mercantile Exchange (Nymex) launched the California-Oregon Border and Palo Verde electricity futures and options contracts. These contracts are a price discovery tool and allow buyers and sellers to hedge price risks. Consumers can now consult The Wall Street Journal on a daily basis to obtain firm and non-firm prices at these locations. ' 1.13 Impact of Restructuring on Mineral Producers as Major Consumers of Electric Power According to the 1992 Census of Minerals Industries published by the Commerce Department, in 1992, the mineral industries purchased approximately 77,063 million kwh of electricity at a cost of $3,838,800. This represents a very small percentage of the estimated $200 billion per year electric market.

16 However, from the perspective of mineral producers as consumers, electricity is a significant percentage of a mining establishment's total costs--although the actual percentage varies significantly by mineral and by mining establishment. In 1997, the Independent Petroleum Association of America surveyed its membership. That survey showed that electricity represents 9.5% of an average producer's operating costs, 78 although for stripper wells it can be as much as 90% of production costs. 79 FERC Order No. 888 only applies to the wholesale power market. Retail wheeling is required before consumers can shop r their own power supplies. Until retail wheeling is available n a voluntary or mandatory basis, mineral producers that are large consumers of power have to resort to the traditional means to reduce their power costs: (i) self-generation or cogeneration; 80 (ii) municipalization; 81 (iii) exerting competitive leverage by threatening loss of load through curtailment of production, shut down of a facility, or relocation of a facility in order to negotiate a discount; or (iv) filing antitrust actions. 82 Additionally, mineral producers and other industrial customers may be able to negotiate a retail wheeling deferral agreement in which they obtain a discount today in exchange for extending the term of their existing contract. Such agreements should cover retail wheeling issues such as any future liability for stranded costs and the future ownership of the historical transmission capacity which the utility has used to service the customer. 83 Negotiations for a retail wheeling deferral agreement should o take into account the significant role that mineral producers play in load management. For example, mineral producers that run their operations twenty-four hours a day provide a stable base load which is the easiest and cheapest load to serve. Mineral producers that have the ability to be flexible in their operations may be able to help a power supplier manage its load, such as by operating during off-peak hours. Producers should recognize the advantages they can offer and use these as negotiation points to secure better power contracts. 84 While waiting for retail wheeling, some mineral producers may find it economic to convert lease production to electricity for lease operations. Depending upon the language of the lease, it may be possible to do so without incurring royalty obligations. 85 Mineral producers should participate in wholesale wheeling proceedings which might impact the future viability of retail wheeling. For example, independent system operator proposals for the wholesale wheeling environment may predetermine issues critical to retail customers such as ownership of transmission capacity. 86 Mineral producers should also participate in retail wheeling proposals in their states, including public utility commission or legislative studies and other investigations. Their interests are not adequately represented by other stakeholders. This is particularly true for mineral producers that are also generation fuel suppliers. ' 1.14 Significance of the Electric Generation Market to Mineral Producers as Fuel Suppliers

17 [1] Overall The electric power market is often described as a $200 billion market. This is not the size of the component of that market which will open up to competition as restructuring progresses. Research Data Institute reports that of the $200 billion a year in utility revenue generation, 62% is for generation services, the area in which competition will be allowed in the restructured industry. 87 This still makes this component larger than the $100 billion long-distance telephone market over which AT&T, MCI, and Sprint have been fighting for years or the $70 billion local telephone market which these telecommunication giants are attempting to enter. On a national basis, in 1994, coal accounted for approximately 52.09% of total electricity production, although it was only 17.24% of nonutility production. Natural gas accounted for 14.47% of total production but was of nonutility production. Petroleum accounted for approximately 3.26% of total production and was 4.40% of nonutility production. Nuclear, hydroelectric, and renewables accounted for the balance of electricity production. 88 Of course, this mix can vary widely by region. For example, in the six-state region of Arizona, Colorado, Nevada, New Mexico, Utah, and Wyoming, coal accounts for 72% of the electric generation market with the balance being nuclear (10%), imported energy (7%), hydro (5%), natural gas (4%), and energy efficiedcy and renewables (1%). 89 In contrast, in the Pacific Northwest, hydro accounts for approximately 65% of the electric generation market. [2] Significance of Electricity Generation to Coal Producers The electric generation market is of critical concern to coal producers. On a national basis, electric utilities are responsible for about 87% of coal use. 90 In the six-state region described above, electric utilities use about 94% of all the coal burned for industrial processes. 91 The Rocky Mountain region accounts for approximately 1/4th of the nation's coal production. Twentyfour of the fifty largest coal mines in the country are located in the Rocky Mountain region. 92 Western coal tends to have a low sulfur content, making it attractive for environmental reasons. However, it also tends to have a lower heat content as compared to Appalachian or midwestern coal. [3] Significance of Electricity Generation to Gas Producers The electric generation market only accounts for about 15% of the markets for natural gas. 93 The largest market for natural gas is in the industrial sector in which natural gas supplies one-third of energy needs. The remaining markets for natural gas are commercial and home heating uses. However, electricity generation is the only market for natural gas that is expected to experience any significant growth for the next ten to fifteen years. Opening up generation to competition will allow nonutility generators to compete with utilities in the sale of power. Natural gas is the primary fuel for nonutility generators.

18 The greatest expected impact for natural gas of electric industry restructuring will be through the addition of new gas-fired capacity as the demand for electricity grows. By some estimates, gas consumption to generate electricity may double in the next 15 years and could account for as much as 25% of the end-use market for natural gas by the year The annual energy outlook of the Energy Information Administration (EIA) is even more optimistic. The EIA's most recent projection is that natural gas will capture 31% of the electric generation market by According to this forecast of U.S. utilities, 263 of 440 plant additions will be natural-gas fired and 13 will be coal-fired. The balance will be powered by Oil 96 (87), hydroelectricity (65), and a combination of geothermal, biomass, solar, and wind (11). According to the survey, the small number of coal-fired units is attributable to concerns about the environmental impact of coal plants, long construction lead times, and the availability of economical gas. The survey predicts that by the last year of the forecast, the levalized costs for gas-fired combinedcycle capacity will be 14.2% lower than for coal. 97 [4] Significance of Electricity Generation to Oil Producers Residual fuel oil was, in the late 1960s, the fuel of choice for generating stations near the Atlantic Coast because it was cheaper and cleaner than coal. However, with the oil embargo' of 1974 and the OPEC price increase, oil became the most expensive fuel for power generation and also became a fuel with high supply-security risks. Oil is also subject to environmental laws which keep it from being a cost-competitive fuel. Accordingly, oil-fired capacity is not expected to increase as a result of electric industry restructuring. 98 However, a recent article in Oil & Gas Journal reported that there is potential growth in the use of lowvalue residual petroleum products, such as petroleum coke, tar, or vacuum resids, in power production. 99 According to this report, there has been a shift by industry towards low-sulfur, lighter refined products. As a result, refiners must either invest in expensive technology to convert heavy residuals to lighter products or sell such products at a discount. In 1994, the average price of petroleum coke delivered to power stations larger than 50 mw was $21/ton. On a thermal basis, this was 50% of the cost of coal and 30% of the cost of fuel oil. As a result of such discounting, coke use for power generation has been increasing at the rate of 80,000 tons per year since With electricity industry restructuring, refiners now have the option of entering the electricity generating market as a means of disposing of heavy refining residuals. There are now more than 80 refinerybased power generation projects in the United States. 100 While the growth in this market is not expected to offset the overall decline in oil-fired power generation, competition from refiners will be a factor in the restructured electric industry. ' 1.15 Anticipated Impacts of Electric Industry Restructuring on Fossil Fuel Producers [1] The Bottom Line for Fuel Producers

19 The goal of restructuring is to achieve a fully developed competitive generation market. The largest operating cost component of electricity is the cost of fuel (as much as 80% of power production costs). 101 Customers are not expected to be loyal. One survey showed that most would switch providers for as little as a 5% savings on their electricity bill. 102 Therefore, in order to be competitive, generators will demand lower fuel costs. For coal producers, keeping the coal-units which they supply cost-competitive will be essential in order to have a market for their coal. For gas producers, the costcompetitiveness of gas-fired units will be the key factor in the growth of natural gas as a generating fuel. [2] Impact of Excess Generating Capacity Coal and gas analysts agree that there is currently excess generating capacity and that restructuring will, in the short run, result in greater utilization of that capacity rather than construction of new capacity. 103 This will favor coal consumption in the short run because the vast majority of the excess capacity is at coal-fired plants. It is estimated that the level of excess capacity is between 25% and 28%. Coal-fired generation facilities operated at a 62% capacity factor in The National Coal Council estimates that an increase to a 70% capacity factor would mean an increase in the use of coal of over 100 million tons per year. 104 Some predictions are that in the restructured environment, many coal plants will be run at as high as a 90% capacity factor. Additionally, competition will promote the more efficient use of existing capacity because of the large capital costs associated with building new capacity. For example, better coordination between coal suppliers, transporters, and users could smooth out the supply cycle and allow for reduced inventories thereby reducing coal costs. 105 Accordingly, there is a concern by the gas community that, absent a change in environmental regulations, gas may actually lose consumption in the short term under restructuring because of the marginal cost advantage of existing coal-fired plants. 106 Competition will occur on a marginal cost basis because the capital costs of existing facilities are already sunk. 107 According to Utility Data Institute's 1995 power plant database, total operating, maintenance, and fuel expenses for utility-owned, coal-fired facilities were $18.78 per megawatt-hour, compared to an average of $19.23 for nuclear plants, $26.79 for gas-fired plants, and $37.70 for oilfired plants. 108 Of these expenses, by far the largest component is fuel cost. On a marginal cost basis, the delivered price of coal is usually cheaper than the delivered price of natural gas. Current delivered gas prices to power plants are in the $2.20 to $2.60 range as compared to delivered coal prices averaging $1.40 to $1.50 with a range of from less than $1.00 to $ Newer, more efficient combined-cycle gas units with thermal efficiencies above 50% (compared to 30-35% for conventional units) can be cheaper on a marginal cost basis because of that efficiency even when the delivered gas price is 55 to 65 cents per MMBtu above the delivered price of coal. 110 However, current gas prices relative to coal exceed this

20 differential. Accordingly, because of the current capacity bubble and the advantage of coal on a marginal cost basis, it is expected that the availability of transmission access in the restructured electric industry will allow the owners of coal generating facilities to flood the market with cheap power. The only coal units which are expected to be at risk in the restructured environment will be older, higher-cost units with poor boiler efficiencies and higher operation and maintenance costs. A study prepared by the Electric Power Research Institute concluded that even if combined-cycle gas units were dispatched ahead of coal-fired units in all parts of the country except where coal is available at substantially below the national average, there would only be a moderate increase in power industry gas consumption--less than 100 bcf a year. 111 Of course, some of the existing excess capacity is located at gas-fired plants. Also, because there is very limited transmission capability between the Western, Eastern, and ERCOT Interconnects, the demand for gas for power fuel generation may vary by region. For example, much of the excess coal capacity is in the interior portions of the United States, located in the Eastern Interconnect. Coal units in these regions can wheel power to the Northeast; coal units in the Western Interconnect in general cannot. In regions where natural gas is very competitive, such as in the Pacific Northwest where cheap Canadian gas is available, coal may not be able to compete as effectively. Transportation rates for coal are another factor which will affect coal utilization. Additionally, as competition reduces electricity prices in the highest-cost regions today, such as the Northeast, this may fuel more rapid demand growth than currently anticipated and could increase the need for new capacity at a faster rate than expected. As discussed in the next section, natural gas is expected to have an advantage over coal for capacity additions. Other regional differences in demand for new capacity may also occur. For example, in the Pacific Northwest, the future of hydropower is being re-evaluated in hydro relicensing proceedings. This is because Columbia River salmon and other fish species have now been placed on the endangered species list despite $3 billion spent to address the impact of dams on these species. Proposals being considered are removal or drain down of certain key hydroelectric dams on the Columbia and Snake Rivers with resulting loss of generating power. Both of these options would create a demand for replacement power from imported sources or from newly-constructed generation plants. Finally, there will be situations where new gas-fired capacity will be built in the short term notwithstanding the capacity bubble overall. For example, in October 1994, Williams Field Services Group announced that it would build a $44 million, 60-megawatt electric and steam generation facility to complement its Milagro natural gas treating plant near Farmington, New Mexico. 112 The facility was described by Williams as the first "merchant plant" of its type in the nation. Louis Dreyfus Electric Power, Inc. signed a long-term agreement with Williams to purchase the electricity from the facility. [3] Capacity Additions