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The impending restructuring of the electric utility industry: causes and consequences.

THE DECADE of the 1980s witnessed a rapid deregulation of many industries, including trucking, airlines, and telecommunications. The economic rationale for regulation was never well established in the trucking and airline industries. Changes in technology rendered earlier rationales for regulation of the telecommunications industry inoperative. The benefits to consumers from deregulation in these industries have been extensive. For example, distribution costs as a share of GNP have dropped 33 percent since 1981, after the passage of the Motor Carrier Act.(1) Nevertheless, the process of moving from a regulated to a deregulated marketplace has been painful for many market participants.

Deregulation of the natural gas industry occurred somewhat later than deregulation of transportation and telecommunications but gained momentum in the late 1980s and early 1990s. Movement toward deregulation of electric utilities has been even slower. However, the passage of the Energy Policy Act of 1992 signals the end of the electric utility industry as we now know it. The final impact on the industry will be at least as great as deregulation of the interstate natural gas industry has been.(2)

A BRIEF OVERVIEW OF NATURAL GAS REGULATION(3)

Prior to the passage of the Natural Gas Policy Act of 1978, interstate natural gas industry regulation was similar to public utility regulation. The Natural Gas Act of 1938 directed the Federal Power Commission (FPC) to establish "just and reasonable" rates for pipelines and natural gas producers who sold natural gas in the interstate market. This form of regulation created problems during the late 1960s and early 1970s as the demand for natural gas increased. The price of "interstate gas" was held at artificially low levels by the FPC. At the same time, the price of natural gas sold in intrastate markets was not regulated, and it rose in line with increased demand. The net effect was an interstate gas policy that encouraged consumption, but discouraged producers from committing gas to the low-price interstate market.

In 1978 the Natural Gas Policy Act (NGPA) was passed. NGPA established a complicated system for eliminating the dual natural gas market. All gas, both interstate and intrastate, was included under new federal price controls. Various categories of gas were defined, and maximum prices for all gas in a category was set. One objective of this pricing policy was to provide incentives for the discovery of new gas, which could be sold at "premium" prices. Interstate pipelines, eager to rectify their supply shortfalls, made commitments to buy much of this so-called "new" gas. These new gas purchase contracts often included "take-or-pay" provisions, under which a firm agreed to pay for a significant portion of the contracted amount of gas at a price equal to the maximum NGPA price, whether or not the gas was needed by the pipeline's customers. As the incentives for new gas discovery bore fruit and the impact of the recession in the early 1980s reduced demand, significant surpluses developed in the marketplace and prices fell dramatically.

In 1985, the Federal Energy Regulatory Commission (FERC), successor to the FPC, issued Order No. 436 (later modified as Order Nos. 500-H and 500-I), which, in effect required pipelines to become open-access providers of transportation services for producers and users of natural gas. This completely reversed the role played by interstate pipelines, from merchants of gas that was delivered through their pipelines to the transportation of gas owned by others. For example, in 1984, 92 percent of the gas transported by pipelines was "their own" gas, and only 8 percent of pipeline throughput represented the transportation of gas owned by others.(4) By early 1992, the pipelines' role had been reversed, with "transportation gas" representing 79 percent of throughput.(5) Interstate pipelines that had contracted for substantial portions of their merchant gas in the form of high-priced, take-or-pay contracts found themselves in a crisis when gas prices declined and gas users (large industrial customers and local distribution companies) lined up their own lower-cost sources of supply. Many pipelines faced staggering take-or-pay liabilities from uneconomic gas supply contracts. By October 31, 1990, interstate pipelines had paid $9.1 billion to producers to settle take-or-pay obligations. The Department of Energy estimates that only $5.4 billion of this amount is eligible for recovery from pipeline customers under FERC regulations, leaving $3.7 billion in unrecovered payment (losses).(6) Unrecoverable take-or-pay obligations were the primary cause for the Chapter 11 bankruptcy declaration by Columbia Gas in July 1991. Current rules under consideration by the FERC would completely eliminate the merchant function of natural gas pipeline companies.

THE HISTORY OF ELECTRIC UTILITY DEREGULATION

The pace of deregulation of electric utilities has been much slower than in other, formerly regulated industries, in spite of substantial evidence that the declining cost rationale for its regulated monopoly status ceased to be operative in the early 1970s. Until recently, the electric utility industry has functioned almost exclusively as a regulated monopoly providing generation, transmission, and distribution services.(7)

The first, albeit small, step toward deregulation was taken with the passage of the Public Utility Regulatory Policy Act of 1978 (PURPA). PURPA defined a group of small, essentially unregulated "Qualifying Facility" (QF)(8) producers that were permitted to sell power to public utilities at a rate no higher than the "full avoided cost" of power that would otherwise be purchased or produced elsewhere (regardless of the QFs' cost of producing this power). These QFs provided competition to electric utilities for their own internally produced power. QFs have had a significant impact on the generation mix in many parts of the country(9), but their overall impact has been limited by their inability to demand transmission services (wheeling) outside the service area of their host (local) utility.

Subtitle A of Title VII of the 1992 Energy Policy Act (Act) amends the Public Utility Holding Company Act and creates a new class of generators called exempt wholesale generators (EWG). These EWGs may sell the power they produce either to their host utility or to utilities at distant locations, by wheeling (transporting) the power over the transmission lines that connect to the wholesale customer. EWGs can be independently owned, or owned by electric utilities or their holding companies. Permitting existing electric utilities to own EWGs was designed to provide for experienced management and strong financing for the EWG industry.

Subtitle B of Section VII of the Act amends the Federal Power Act by permitting "any electric utility, Federal power marketing agency, or any other person generating electrical energy for sale for resale" to apply to the Federal Energy Regulatory Commission (FERC) for a wheeling order. Compulsory wheeling under the Act must be done at "rates, charges, terms, and conditions which permit the recovery by such |transmitting~ utility of all the cots incurred in connection with the transmission services, including, but not limited to, an appropriate share, if any, of legitimate, verifiable, and economic costs, including taking into account any benefits to the transmission system of providing the transmission service, and the costs of any enlargement of transmission facilities."

The Act restricts mandatory transmission access to sales-for-resale (wholesale transactions). Retail wheeling, associated with sales to final customers, is explicitly excluded from the mandatory wheeling requirements of the Act. Thus, at the present time the Act increases competition only in the wholesale generation market.

The increase in competition for wholesale generating TABULAR DATA OMITTED capacity has important implications for QFs and integrated utility companies. QFs will face new competitors who can supply power from outside the traditional service area in which the QF is located. Cost effectiveness will become increasingly important for QFs. Integrated utilities will face an expanded array of generation source options as new EWGs make their resources available. Economic efficiency increasingly will determine who builds generating plants and where they are located. Furthermore, the increased availability of low-cost capacity will force utility companies and their regulators to address questions of inefficiencies that have arisen under cost-plus regulation. Questions of system reliability also must be addressed. Increased wholesale wheeling will raise difficult questions regarding the pricing and allocation of scarce transmission capacity.(10)

THE THREAT OF RETAIL WHEELING

The threat of retail wheeling (transportation of power from EWGs and other producers to final users) is far more important to the future structure of the industry than wholesale wheeling under the Act. Retail wheeling legislation is under consideration in at least four states: California, Michigan, New Mexico and Texas. For example, mandatory retail wheeling legislation was considered in the New Mexico legislature during 1993. The issue arose in the context of a franchise dispute between the City of Albuquerque and the Public Service Company of New Mexico (PNM). The city attempted to purchase power from an alternative supplier, but was unable to do so because PNM refused to transmit the power over its transmission lines. The 1993 bill was tabled for study but will be reintroduced in the legislature in 1995. Bill Eglington, executive vice president of PNM expects retail wheeling in the near future. "Soon, we'll start calling customers what they really are: shoppers."(11) Other utility executives agree. D.D. Hock, Chairman and CEO of Public Service Company of Colorado says, "I am also convinced that retail wheeling with be a near-term reality."(12) The issue of retail wheeling has emerged at the top of the lobbying agenda of many large electric consumers.

There is very little difference, in practice, between retail wheeling and wholesale wheeling. If a large industrial customer in one service territory demands retail wheeling as a condition of keeping a plant open in the state, that customer likely will be granted this authority by state regulators and legislators who will be concerned about the possible loss of jobs if the plant should close. Many experts believe that extensive retail wheeling is only two to three years away.(13) The speed with which open-access spread through the natural gas transmission industry is instructive for the electric utility industry.

IMPLICATIONS OF RETAIL WHEELING

An indication of the potential impact of a competitive electric utility industry can be obtained by considering differences in current rates between utilities. Table 1 lists the twenty utilities with the highest cost per kwh and the twenty utilities with the lowest cost power kwh for residential customers as of August 1992. The differences shown in Table 1 are dramatic. For example, Long Island Lighting's cost per kwh is nearly four times the cost per kwh for Washington Water Power. Even at the bottom of the list, the cost per kwh for Bangor Hydro-Electric is nearly twice the cost per kwh for twentieth-ranked Mississippi Power. This table suggests that high cost operators are likely to face substantial competitive pressures.

In a competitive power market, rate differences should be reduced to a level reflecting only the marginal cost differences of producing additional increments of power and the cost associated with its transmission from one location to another. Table 1 provides only a rough estimate of the potential competitive pressures that will arise in a deregulated industry. It is unrealistic to compare the rates charged by Long Island Lighting with those charged by Washington Water Power. First, Washington Water Power's cost of providing increments of power is likely to be significantly higher than their imbedded cost-plus rate. Also, it is not economically feasible to transmit power from Washington State to New York, even if surplus, low-cost power were available from Washington.

Table 2 provides a somewhat more realistic look at the potential impacts of retail wheeling. This table contains data on comparable rates between two firms that operate in adjacent or nearby territories. In these instances, wheeling is much easier and the potential competitive impact would be very large. This selection of representative pairs of companies indicates that rate differentials between adjacent utilities in excess of 50 percent are not uncommon. Differentials of this magnitude are likely to create very strong demands for retail wheeling, especially from large industrial customers.
Table 2
Selected Residential Rate Differences for Contiguous or Closely
Proximate Electric Utilities(1)

Company Residential Rates Percent
Pair (cents per kwh) Difference

Iowa Electric Light & Power 13.4
Interstate Power 7.1 89

Long Island Lighting 16.4
Pennsylvania Power and Light 9.0 82

Cleveland Electric 13.5
Cincinnati Gas & Electric 7.5 80

Mississippi Power and Light 11.0
Mississippi Power 6.4 72

Philadelphia Electric 14.8
Pennsylvania Power and Light 9.0 64

El Paso Electric 11.1
Southwestern Public Service 7.0 59

Interstate Power 8.5
Minnesota Power 5.4 57

Baltimore Gas and Electric 10.3
Potomac Edison 6.7 54

Arkansas Power and Light 11.5
Southwestern Electric 7.5 53

Union Electric 10.3
St. Joseph Light and Power 6.8 51

Northern Indiana Public Service 10.5
PSI Energy 7.6 38

Commonwealth Edison 12.4
Central Illinois Public Service 9.2 36

Commonwealth Electric 13.8
Massachusetts Electric 10.3 34

Bangor Hydro-Electric 12.2
Maine Public Service 9.9 23

1 Source: Residential Electric Bills: Summer 1992, Washington,
DC; National Association of Regulatory Utility Commissioners,
April 23, 1993, based on 500 kwh during August, 1992.


Another indication of the potential competitive impact of retail wheeling can be obtained by comparing the marginal cost of capacity additions from EWGs with the average cost charged by regulated utilities. Studness estimates that a new, 150 MW combined-cycle, gas unit can be built today with the capacity to deliver power at approximately 3.5 cents/kwh, which is equivalent to a residential rate of 6 cents/kwh. If competition forces a capping of rates at 7 cents/kwh, 37 percent of a sample of eighty utilities would have had a negative return on equity in 1992. Of these utilities, 20 percent would not have earned enough to cover their fixed charges -- raising the possibility of bankruptcy.(14)

CONCLUSIONS

The denial of retail wheeling is the last barrier protecting the monopoly power of utility companies against market tests of their relative efficiency. When this barrier is breached, market forces will determine electric utility prices rather than cost-plus ratemaking. Once industrial customers break the monopoly hold of regulated, integrated utilities, most likely using economic development arguments, the move toward nationwide retail wheeling will be very rapid. This movement may have severe economic consequences on the industry and will raise many difficult questions for both managers and regulators.

When retail wheeling becomes a reality, the potential exists of creating large amounts of excess generating capacity in those utility territories served by high-cost producers. This excess capacity may be viewed as the economic equivalent of "take-or-pay" contracts. Regulators are unlikely to permit utility firms to pass these costs on to a utility's remaining (predominantly residential and small commercial) customers. Without the ability to recover the cost of underutilized assets, significant writeoffs are possible, much like the writeoffs that faced pipelines with take-or-pay liabilities and the writeoffs that swept the electric utility industry in the 1980s in the form of prudency reviews. Alternatively, high-cost utilities may cut rates to preserve their market share. However, if a utility's assets will no longer support the precompetitive earnings stream, writedowns of assets will be required.

High cost utilities will face dramatic challenges that may cost some of them their independence. Either consolidations or bankruptcies will be the outcome for those high-cost producers that cannot quickly restructure into lower cost suppliers of services. Today's investors and analysts need to pay much closer attention to the future competitive position of various utilities and look past the appearance of financial health that may exist today under the protection of cost-plus regulation.

Finally, deregulation also will force a consideration of the proper pricing of various utility services -- especially transmission. In some instances, firms may find it easier to spin off this part of their business into separate, independent enterprises that operate very much like natural gas pipelines. There do not appear to be any technological reasons why this cannot be accomplished.

1 See footnotes at end of text.

FOOTNOTES

1 Source: Cass Logistics, Inc., as reported in the Wall Street Journal, "Deregulation Delivers the Goods," June 29, 1993, p. A19.

2 A good discussion of the parallels between deregulation of electric utilities and deregulation in the telecommunications industry is presented in Robert J. Graniere, "Deja Vu: The Electric Industry's Gyrations are Giving Some Telecommunications Experts that Old Familiar Feeling," Public Utilities Fortnightly, June 15, 1993, pp. 26-30.

3 A more complete review of the history of natural gas regulation and deregulation can be found in Donald F. Santa, Jr. and Particia J. Beneke, "Federal Natural Gas Policy and the Energy Policy Act of 1992," Energy Law Journal, vol. 14, no. 1, 1993, pp. 1-49.

4 Intestate Natural Gas Association of America, "Issue Analysis: Carriage Through the First Half of 1991," Table A-1, 1991.

5 Energy Information Administration, Natural Gas Monthly, Table 15, February 1992.

6 Mary Carlsonet, et. al., "Take-or-Pay Settlements," Natural Gas Monthly, January 1991, pp. 1-9.

7 Some communities, such as Lubbock, Texas, have offered competitive alternatives to electric customers, but these examples of competition at the distribution level are clearly exceptions. A good discussion of competition among utilities at the distribution level is contained in Walter J. Primeaux, Jr., "Competition Between Electric Utilities," in John C. Moorhouse, Electric Power: Deregulation and the Public Interest, San Francisco: Pacific Research Institute for Public Policy, 1986, pp. 399-423.

8 Qualifying facility electricity can be generated from hydro power, wind, solar, geothermal, cogeneration, biomass, or waste product combustion.

9 For example, 9 percent of Southern California Edison's energy came from QFs in 1987. They project that 25 percent of their energy will come from these sources by 1995. (Source: B.J. Ewers, Jr., "Should We Break Regulation," Public Utilities Fortnightly, January 1, 1993, p. 12).

10 A discussion of these issues can be found in Ashley C. Brown, "Electricity After the Energy Policy Act of 1992: The Regulatory Agenda," The Electricity Journal, January/February, 1993, pp. 33-43.

11 Leah Beth Ward, "Utilities Brace for a Buyer's Market in Electricity," New York Times, May 9, 1993, p. 10.

12 A good summary of utility CEO attitudes toward restructuring is in "Regenerating an Industry: The 1993 Electric Executives Forum," Public Utilities Fortnightly, June 1, 1993, pp. 26-63.

13 For example, see the discussion by Charles M. Studness, "Competition and Utility Financial Risks," Public Utilities Fortnightly, July 1, 1993, pp. 31-32.

14 Ibid., p. 31.
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Title Annotation:Applied Economics
Author:Moyer, R. Charles
Publication:Business Economics
Article Type:Industry Overview
Date:Oct 1, 1993
Words:3064
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