The future of electricity.

When one thinks of the industries that will undergo the most rapid change over the next five years, the computer, software, telecommunications, and health care industries immediately come to mind. However, the one industry that is likely to experience the most dramatic transformation is the once

sleepy electric utility industry. Over most of their history, electric utilities have operated as regulated monopoly suppliers of services. Now the electric utility industry stands as the last major remaining remnant of the regulated monopoly era. During the past fifteen to twenty years, deregulation has come to the oil, natural gas, banking, airline, trucking, telecommunication, and cable TV industries. The United States now stands on the threshold of a sweeping deregulation of the electric utility industry that will drastically reshape its structure, increase consumer choice, and lower costs. The net result of this restructuring will be fewer firms, less vertical integration, and a much lower cost structure.

This article provides an overview of the current state of electric utility regulation in the United States-and a look at how deregulation has reshaped the industry in other countries. The challenges associated with the transition to a competitive world are reviewed, with emphasis on the problem of stranded costs. A vision of the future of the electric utility industry is offered.

A BRIEF HISTORY OF ELECTRIC UTILITY REGULATION IN THE UNITED STATES

The most important federal statutes regulating the electric power industry, the Federal Power Act and the Public Utility Holding Company Act, were both enacted in 1935. Under the Federal Power Act, the Federal Energy Regulatory Commission (FERC) regulates the rates and conditions for the sale of wholesale power in interstate commerce. The FERC also regulates the interstate transmission of electricity. The Public Utility Holding Company Act gave the Securities and Exchange Commission broad authority to regulate interstate utility holding companies, including the issuance of securities by these companies and the purchase and sale of holding company assets. These two acts provide a vehicle for utility regulation that extends beyond the jurisdiction of state public utility commissions.

State public utility commissions regulate the generation and local distribution elements of regulated electric utilities. The traditional mode of regulation has been a cost recovery system, whereby a utility is permitted to set rates such that they will recover all prudently incurred costs, including a return of the capital invested in the firm and a return on the utility's invested capital. Once a regulatory commission establishes the full cost recovery level of revenues that an electric utility is entitled to collect, it then works to develop a rate structure for the pricing of utility services to the regulated company's various classes of customers.

The traditional regulatory process has been criticized for not providing adequate incentives for efficiency. For example, if the authorized return on capital is set too high, as typically was the case in the 1950s and 1960s, the utility had the incentive to overinvest in capital intensive plants, because the return component on this capital investment exceeds the cost of the capital employed.(1) In contrast, if allowed returns on capital are set less than the cost of capital, utilities will underinvest in physical plant choosing, instead the least capital intensive generating assets, even if they have significantly higher operating costs. In addition, utility commissions are not capable of judging the prudence of every operating expenditure made by a utility. In a cost reimbursement regulatory environment, operating efficiency surely suffers. For example, a common industry quip is that regulated utilities are the only companies that can increase shareholder profits by redecorating the CEO's office. Operating cost inefficiencies and capital investment incentives have become increasingly evident as utilities have begun the restructuring process in preparation for the new competitive world. In most cases large cost savings have been found.

Deregulation of the industry began slowly, with the passage of the Public Utility Regulatory Policies Act (PURPA) in 1978. One of the most important elements of PURPA was the creation of a new class of generators - so-called qualifying facilities - who are primarily cogenerators.(2) These qualifying facilities were guaranteed a utility market for all of the power they produced at a price equal to the avoided cost of the purchasing utility.(3) Most states now require competitive bidding by qualifying facilities that propose to contract for long-term supply relationships with a purchasing utility. In addition to the qualifying facility producers, other independent power producers emerged after 1978. The FERC permits these producers to charge market-based or negotiated rates (as opposed to cost-based rates), and thus are not constrained to earn a limited, prespecified return on shareholders' investment.

In 1992, Congress passed the National Energy Policy Act. This wide-ranging act introduced a new element of competition in the wholesale electric market and provided for open access to utility transmission lines. Under this act, a wholesale customer, such as a cooperative or a municipal utility, could purchase power from the lowest cost producer, and the surrounding utilities were required to send (wheel) this power over their transmission lines in exchange for a fee. This act opened the door to a competitive wholesale power market, encouraged the development of an active spot market in electricity, and led to the development of the power marketing industry.(4) The 1992 act, however, explicitly prohibited the FERC from regulating retail wheeling.(5) The regulation of retail competition was thus left to the state level, where, as we will see below, there has been a flurry of activity.

THE STRANDED COST PROBLEM

One of the most significant issues facing utility managers and investors as they look to the competitive future is the treatment of so-called stranded costs. Stranded costs are the fixed costs that have been approved for recovery under traditional regulation that are likely to be unrecoverable in a competitive market. These costs have been estimated by Moody's Investors Service to total between $50 billion and $300 billion over the next ten years, with a most likely figure totaling $135 billion.(6) This compares to total industry assets of $570 billion and total industry equity of $165 billion. Hence the treatment of stranded costs is a key element of concern in the process of deregulation.

The debate around the issue of stranded cost treatment has been spirited, although the FERC appears to have accepted the principles embodied in the "regulatory compact" arguments. Under the regulatory compact, state and local governments required electric utilities to provide reliable power to all customers in their service area. In exchange, the utility was permitted to earn a restricted, but presumably competitive, profit on those sales. To force utility investors to bear the burden of stranded costs that have arisen from government mandates to provide service to all customers would amount to the confiscation of investor property, according to the proponents of the regulatory compact argument.

To address the issue of stranded costs and open transmission access, the FERC issued Final Orders 888 and 889 on April 24, 1996. The primary elements of these landmark orders are:

1. Utility transmission networks will assume essentially a common carrier status, where equal access, rates, and service levels will be provided to all users on a nondiscriminatory basis. Utilities were ordered to file open-access transmission tariffs within sixty days of the order date.

2. An Open Access Same-Time Information System is established, providing pricing data for transmission use. Utility employees engaged in power marketing are prohibited from obtaining preferential access to this information.

3. Utilities are encouraged to unbundle transmission services or to establish Independent System Operators (ISOs). Under an ISO arrangement, the operation of the transmission network is turned over to an independent third party, who is charged with allocating transmission capacity and maintaining system security and reliability in a nondiscriminatory manner. At present, there is no requirement that utilities actually divest themselves of their ownership of transmission assets. Rather they must separate transmission and power marketing functions via strict standards of operating conduct.

4. Final Order 888 generally permits full recovery of stranded costs from departing wholesale customers. The stranded cost obligation of departing customers will be computed on the basis of an estimate of revenues lost from a departing customer.(7) Final Order 888 deals only with the recovery of stranded costs related to wholesale customers. These total approximately $10.4 billion. In contrast, the lion's share of stranded costs (over an additional $100 billion) will be related to customer choice at the retail level, where the FERC has ceded authority to state regulatory bodies.

How serious is the problem of retail stranded costs? In aggregate, stranded costs have been estimated by Moody's to be approximately 80 percent of the equity in electric utilities. However, the impact on individual companies is highly variable. For example, among companies located in the states of Arkansas, Kansas, Louisiana, Mississippi, Missouri, and Oklahoma, Moody's estimates of stranded costs as a percent of common equity range from 463 percent for New Orleans Public Service, 388 percent for Mississippi Power and Light, and 266 percent for Arkansas Power and Light to only 4 percent for Public Service of Oklahoma.

In addition to the sheer magnitude of stranded costs relative to the common equity of electric utilities, one can get a sense of the potential for cutthroat competition and losses related to retail wheeling by comparing the average industrial electric rates between utilities in the same region.(8) For example, as of July 1995, industrial rates in the Northeast ranged from 3.4 cents per kwh for Potomac Edison to 12.9 cents per kwh for Long Island Lighting. In the Southeast, rates ranged from 3.2 cents per kwh for Kentucky Power to 5.5 cents per kwh for Mississippi Power and Light. In the Southwest, rates ranged from 3.5 cents per kwh for Southwestern Public Service Company to 6.0 cents per kwh for Public Service Company of New Mexico. In the Far West, rates ranged from, 2.6 cents per kwh for Idaho Power to 7.6 cents per kwh for San Diego Gas and Electric.(9) In addition to these differentials among utility companies, even greater disparities can to observed when one considers rates charged by independent power producers.

State actions to invoke competition in the electric utility industry also have been extensive. A survey completed by the Edison Electric Institute in March 1996 indicated that forty-six states have active proceedings under consideration either in their legislatures or public utility commissions to consider retail wheeling. The California Public Utility Commission issued its final order on electric utility restructuring in December 1995. In May 1996, the Massachusetts Department of Public Utilities issued generic rules for restructuring the industry. A final detailed order is expected in September 1996. Individual utilities are expected to file restructuring plans in October 1996. In May 1996 the New York Public Service Commission also issued a final order in its large Competitive Opportunities case. This order sets the framework for the transition to competition.

Although these orders differ somewhat in their details, they share a number of common elements. In each case companies are encouraged to divest a portion or all of their generation assets. Transmission assets would be managed by an Independent System Operator. Ultimately it is believed that transmission assets would also be divested. Retail competition would begin in 1998 and be phased in for all customers over a period of approximately five years. Stranded costs would be recovered over a period of five to ten years by way of a nonbypassable charge. In some cases, the return on stranded assets prior to recovery is reduced. For example, in California the return on stranded generation assets is set at 10 percent below the imbedded cost of long-term debt to reflect the lower risk associated with the rapid recovery of these asset investments. In New York, the commission has indicated a preference for a sharing of stranded costs among ratepayers and utility investors.

The FERC stranded cost rulings and the state actions initiated thus far suggest something about the near-term future. However, regardless of how well intentioned federal and state efforts are to protect the stranded cost assets of today's utilities, the forces of politics and competition are likely to place great pressure on attempts by utilities to recover these costs. It is likely that aggressive legislators and/or utility regulators in several states will adopt less favorable mechanisms for the treatment of stranded costs as successive competitive restructuring rulings are approved in individual states. Areas with high stranded cost charges will find industrial recruitment difficult during the transition period. Companies served by utilities with high stranded costs will doubtlessly be very creative in finding ways to avoid these costs including threats of leaving the system. It will be politically difficult to collect these fees from every customer who leaves a system and/or to charge these fees to new customers on a system. Thus, the current optimistic tone of investment analysts regarding the recovery of stranded costs is likely to be muted over time as the realities of competition take hold.

MARKET RESPONSES TO DEREGULATION

As oil and natural gas prices were deregulated, the commodity markets responded by providing a contract vehicle that permits both hedgers and speculators to trade in the underlying commodity. Firms with a risk exposure to the price of oil or natural gas use these contracts to offset that risk. These contracts have been extremely popular. For example, daily crude oil and petroleum product futures contract trading volume amounts to approximately twenty days of U.S. consumption. In the case of natural gas, the average daily trading volume is about five days of U.S. consumption.(10) Derivatives trading (options) related to oil and gas substantially increases the volume of exchange-traded transactions.

As competitive pricing emerges in the electric power industry, a need has developed for similar risk management tools. In response, the New York Mercantile Exchange (NYMEX) initiated trading in electric power futures contracts on March 29, 1996. One contract sets delivery at the California/Oregon border and the other at the Palo Verde switching yard in Arizona. A third contract with East coast delivery is also being considered. Each contract is for the delivery of 736 mwh over a one-month period. Hedging will permit large industrial customers, municipal electric utilities, and cooperatives to reduce the risk of swings in their cost of power. Utilities themselves also can be expected to enter the commodity markets to hedge their fuel costs and their purchased power contract costs. Hedging is likely to become much more important for utility managers as they leave the safe confines of cost reimbursement regulation and must compete on price to gain or retain customers.

As the "paper power contracts" expand in volume, they are likely to become the industry benchmark prices for power sales. The creation of this national benchmark price, together with an open access transmission system is likely to hasten the day when wholesale power costs become much more level across the U.S.

A GLIMPSE INTO THE FUTURE FROM ABROAD

The potential future of the U.S. industry can, perhaps, be seen by looking at foreign countries that have recently deregulated their electric utility industries. These include Great Britain, New Zealand, Australia, Chile, Brazil, and Argentina. Argentina may be the most interesting example of the impact of deregulation because the results have been so dramatic.(11)

The Argentina process began in 1991. Today there is an independent, largely unregulated power generation industry. Each of the thirty or more generating companies sells the bulk of its power into an independent, nonprofit power pool. The power pool company sends electricity to the transmission grid, dispatching the cheapest power first. Thus wholesale power has become very much a commodity business. The power is carried by transmission companies that receive a regulated fee for the service they provide, much the way interstate natural gas pipelines in the United States now operate. The transmission companies deliver power to distribution companies and to large industrial users. These industrial users also are permitted to buy power directly from wholesalers.

The distribution companies provide power to their end users at rates that are capped by regulators. This rate-capping mechanism provides strong incentives for the distribution companies to reduce costs, because these cost reductions flow directly to the benefit of shareholders. The rate caps are scheduled to be reset every five to eight years, thus providing potential future benefits to consumers. Under the Argentina plan, wholesale power rates stabilized at about 40 percent below the prederegulation level, after a period of cutthroat competition that at one point drove wholesale rates to nearly zero.

THE AMERICAN FUTURE

It is clear that the electric utility industry will be quite different in the future than it has been for the past fifty years. Deregulation of this industry will not occur as one "big bang," as in Argentina, but rather as a series of significant regulatory explosions in the fifty states and in Washington, DC. Nevertheless, now that the competitive genie has been let out of the bottle, it will be very difficult to get it back in. The final result of these regulatory changes and a period of consolidation, rationalization, and restructuring is likely to look much like Argentina. Along the way, customers, investors, and regulators will be faced with some or all of the following trends:

Mergers Among Domestic Electric Utility Companies

Weak companies will become attractive targets for stronger companies. For example, during 1995 six major utility mergers were announced. In addition, PECO Energy made an unsuccessful hostile takeover bid for PP&L Resources. We are also beginning to see more interest by electric utility companies in buying natural gas companies, as is evident in the Texas Utilities/Ensearch proposal and the Puget Sound Power & Light/Washington Energy Company transaction. The motivations for these mergers are multifaceted, including:

1. Achieving the critical mass of size and financial strength to survive the new competitive order. Many companies believe that when the industry is disaggregated, companies that have reached a critical size will be well positioned to be among the smaller number of surviving entities;

2. Realizing economies of scale in the provision of services, such as power marketing, customer billing and service, transmission services, and developing an optimal fuel mix and generation cost mix;

3. Providing customers with full service energy service, including natural gas. Another reason for mergers between electric and gas companies is the fact that gas companies have more expertise in areas such as risk management and marketing, because they are much further along the competitive curve.

Spin-Offs of Various Components of Vertically Integrated Companies

As is evident in the California, New York and Massachusetts plans, there will be strong encouragement provided for electric utilities to spin off or otherwise separate their generation assets from their transmission and distribution assets. In vertically integrated companies, where a portion of the assets is regulated and a portion is unregulated, it is extremely difficult to make proper cost allocations between the individual units and to maintain true arm's-length independence between the units. Experience suggests that regulators are more likely to err on the side of ratepayers in the event of disputes. In this environment, vertically integrated companies may simply decide that it is not worth the effort the retain the old organizational form.

International Mergers

In an era when American utility companies are generating substantial cash flows, both from the recovery of stranded costs and from a reduction in capital expenditures for new generating facilities, many utilities have been looking for growth opportunities beyond their traditional markets. During the 1970s and 1980s, some utility managers sought growth via diversification into unrelated industries. With few exceptions, these efforts ended up in disaster for shareholders. Most utility managers were ill equipped to function in competitive businesses, which demanded sophisticated marketing skills, risk management skills, cost control skills, and the ability to move quickly to take advantage of new market opportunities.

This time many utilities are seeking investment opportunities in an industry they understand. For example, by the end of 1995, U.S. electric utilities and their subsidiaries had invested more than $7 billion in various elements of the Australian industry, including power stations and distribution companies. Similar investments have been made in Argentina and Great Britain. To be sure, not all of these investments have been well advised. Few of the investors in Argentine generating facilities foresaw the 40 percent reduction in wholesale electric prices that occurred after deregulation. Nevertheless, these companies are learning valuable lessons that may help them cope with deregulation in the United States.

Higher Risks and Lower Costs

One clear impact of the deregulation movement will be an increase in the business and investment risk of electric utilities. Investor-required returns in these companies will continue to rise relative to benchmark investment alternatives, reflecting the uncertainty associated with the recovery of stranded costs and the increased variability of future revenue streams.

Finally, utility customers can expect to experience a period of stable to declining costs of electric power. Large industrial and commercial power users are likely to be the early winners in the competitive era, but all customers will eventually be the beneficiaries of moderating costs of electric power, especially those customers who currently are served by high-cost utilities.

CONCLUSIONS

The final outcome of the deregulation process is likely to be a relatively small number of independent, wholesale power generation and marketing companies, selling power into the transmission grid on a very cost-competitive basis. Power generation will evolve into a commodity business driven by cost efficiency and reliability considerations. Pricing will be very competitive and margins will be slim. Some of these companies may be national in scope, while the majority are likely to retain a regional orientation.

In addition to the wholesale power generation companies, a small number of regional transmission companies are likely ultimately to develop out of the bones of the transitional independent system operators discussed above. These transmission companies will operate as regulated monopolies under the FERC, similar to interstate gas pipeline companies.

A larger number of local distribution companies (LDCs) are likely to survive the transition period. In many cases, it is likely that these LDCs will offer a full range of energy services to end-use customers, including electricity and natural gas. Customers will be provided with more complete and objective information about the relative costs of various energy alternatives, and the LDCs will encourage customers to use that mix of energy services that provides the best package of cost and service quality and reliability characteristics for a particular use. The regulation of these LDCs could take the form of rate caps, periodically adjusted downward, as in Argentina, or the LDCs may continue to be regulated on a rate of return basis, as has been true in natural gas.

Finally, some companies will remain as large, vertically integrated utilities, particularly in those states where regulators do not require or strongly encourage the disaggregation of the companies into their primary component parts.

End-use customers who want the hedge their power cost risks will be able to do so easily using the electricity futures contracts. Distribution companies will also be able to hedge their end-use power costs for customers who desire more long-term certainty in their power costs. Of course, the generation companies will be able to hedge both the cost and the revenue side of their business using these contracts.

The new competitive environment will create both winners and losers in the utility business. Those companies with low embedded costs, low marginal costs, low exposure to noncompetitive purchased power contracts, strong balance sheets, strong cash flow, cooperative regulatory bodies, and an aggressive management that is willing to look for opportunities associated with the competitive transition are likely to remain as successful long-term players in this industry. In contrast, smaller, financially weaker, and higher cost companies can expect to be taken over, dismantled or otherwise disappear from the electric utility map. The big winner from the deregulation process will be electric utility customers, who should reap the benefits of substantially lower costs of electric power over the next five to ten years.

FOOTNOTES

1 This source of inefficiency was first identified by Harvey Averch and Leland Johnson, "Behavior of the Firm under Regulatory Constraint," American Economic Review, 52 (1962): 10520-1069.

2 Cogeneration is "a process by which both electric energy and thermal energy (heat or steam) are produced simultaneously from a single common fuel source. The energy may be used by the facility to meet its own electrical requirements or may be sold to an electric utility." P.U.R. Glossary for Utility Management, Public Utilities Reports: Arlington, VA. 1992.

3 Avoided cost is the (marginal) cost the utility would incur to generate the power itself or purchase it from another supplier.

4 See Merrill Lynch, Electric Utilities Industry, June 24, 1996, pp. 26-27 for a further discussion of the impacts of the 1992 National Energy Policy Act.

5 Under retail wheeling, individual customers choose their electricity supplier in much the same way that telephone customers now can choose their long-distance carrier.

6 Moody's Investors Service, "Stranded Costs Will Threaten Credit Quality of U.S. Electrics," August 1995.

7 Revenues lost are defined as the average annual revenue stream from the departing generation customer over the three years prior to departure less the average transmission related revenues that the host would have recovered from the departing customer under its new wholesale transmission tariff less an estimate of the average annual revenues that the host can receive by selling the released capacity and associated energy based on a market analysis: or the average annual cost to the customer of replacement capacity and associated energy, based on the customer's contract commitment with its new suppliers times the length of the period of obligation.

8 It is commonly believed that retail wheeling will be implemented first for large industrial users who have more market power and more alternatives (including cogeneration).

9 Source: Merrill Lynch, Electric Utilities Industry, June 24, 1996, pp. 35-37.

10 Edward Krapels and Vito Stagliana, "Power in the Commodity Markets," Public Utilities Fortnightly, May 15, 1996, pp. 32-36.

11 A more detailed discussion of the Argentina deregulation process can be found in "Utility Deregulation in Argentina Presages Possible U.S. Upheaval," Wall Street Journal, June 19, 1996, p. A1. See also "Open Arms, Open Access, and the Outback," Public Utilities Fortnightly, June 15, 1996, pp. 32-36.

R. Charles Moyer is Integon Professor of Finance, Babcock Graduate School of Management, Wake Forest University, Winston-Salem, NC.