THREE
Issues in Public Utility Regulation

Richard J. Gilbert

I. INTRODUCTION

Although the roots of public utility regulation are buried in the political economy of the struggle for control of power, a main economic benefit of regulation has been, until recently, to provide a stable environment for investment in large-scale facilities. Regulation has the characteristic of an implicit contract between the regulated firm and its ratepayers (see Goldberg, 1976). The terms of this contract have provided insurance for the regulated firm against changes in factor costs and demands. The firm had the obligation to build new facilities to meet demand; in return for this responsibility, ratepayers implicitly agreed to guarantee the firm a reasonable rate of profit.

Until the mid-1960s investment in ever larger facilities made economic sense as each increment in scale brought lower costs of production. According to Kendrick and Grossman (1980), from the postwar period until the mid-1960s, public utilities (electric, gas, and water) showed the highest rate of total factor productivity growth of any two-digit Standard Industrial Classification code industry surveyed by the Department of Commerce. The average rate was 4.9%/year compared with 2.0%/year for all private domestic business and 2.5%/year for manufacturing overall.^[1]

From 1966 to 1976 electric and gas utilities scored an average productivity loss of 0.2%/year, while productivity increased an average of 1.4% for all business. Also during this period and through the decade of the 1970s, a number of factors worked against what had been the uncon-

[1] See Kendrick and Grossman (1980) for productivity growth estimates.

tested argument that larger plants were better plants. Inflation and environmental concerns weighed heavily against large-scale facilities. Some of the problems with the new plants were purely technical. The largest plants were not performing at expected capacity utilization rates. Other reasons were economic. Increases in construction costs and in the costs of financing pushed up sharply the capital costs of new technologies, while fuel costs soared.

The record of total factor productivity in the electric power industry has been determined largely by technological advances, demand growth, and resource prices and availability; however, regulatory incentives have also played an important role.

In practice, ratemaking has not generally followed the rate-of-return model. Rate-of-return regulation requires an evidential hearing. In the golden years of electric utilities, when costs were declining, requests for rate hearings were few. Rates of return earned by utilities sometimes exceeded the rates that would have been determined if the utilities were closely regulated, but prices were stable and the initiative for a rate hearing was often absent (Joskow, 1973). In those days many rate hearings were initiated by utilities to lower rates as a reflection of improved operating economics. Regulatory lag with declining costs worked in favor of the utilities and encouraged risk taking in new investments. Utilities had the option of requesting a rate hearing, so rate-of-return regulation provided a safety net for utility earnings, while regulatory lag made higher earnings a possibility. Utility managers had an incentive to invest in the most cost-effective technologies, because lower costs were reflected in higher earnings.

The situation changed drastically in the late 1960s as higher costs led utilities to request frequent and substantial price increases. Regulatory lag and the concerted opposition of ratepayers to further price increases acted in this period to lower earned rates of return (Joskow, 1974). The regulatory process discouraged new investment, and utilities concentrated their efforts on ensuring that revenues would be available to compensate past expenditures.

Although determination of allowed rates of return continued as a main issue in regulatory proceedings, a focus of recent policy has been on the regulation of the rate base. Major issues in the determination of the rate base are (1) allowance for funds used during construction (AFUDC) and (2) prudence. AFUDC is a holding fund for accumulated interest on expenditures for a plant that is not yet operational. The need for an AFUDC account is predicated on the policy that earnings should not be allowed for equipment that is not "used or useful." When a plant becomes operational, both the investment costs and the interest costs are included in the company's rate base. But until that event, AFUDC is a form of deferred gratification for the utility.

In the days when nominal interest rates were under 10% and the average time required to build a new plant was under five years, the opportunity cost of funds used for construction of new facilities was a small expense. But with double-digit interest rates and double-digit lead times for new construction, this item has become a major component of the costs of new plants. For example, of the $5.7 billion spent on units 1 and 2 of the Diablo Canyon nuclear power plant, approximately $2.0 billion, or about 35%, is in the AFUDC category (Chapter 7).

Increasingly, regulators have been questioning the propriety of expenditures and have been holding management to "prudence" accounting before costs can be entered into the rate base. The combination of regulatory lag, rate base accounting conventions and prudence requirements caused some utilities to be unable to earn rates of return sufficient to cover the cost of capital for new facilities (despite apparently adequate "allowed" rates of return), while many others faced the risk that future revenues would not fully compensate past and anticipated future expenditures.

The result was a regulatory incentive package that discouraged investment in baseload facilities and encouraged conservation programs to help avoid new investments. For much of the past decade such a policy made sense. The marginal cost of new investment exceeded the average price of electricity, which is. based on the average cost of existing production facilities. To the extent that consumers react to current average prices (see Chapter 2), they underinvested in conservation and therefore encouraging conservation made sense. A regulatory policy that discouraged new investment also made sense in an environment where demand growth was expected to slow and reserve margins were swelled by recent completions of large baseload plants, as occurred in recent years in California (Chapter 4).

However, the incentives created by the restrictive regulatory policies of the recent past will not serve the needs of the next decade. As John Quigley argues in Chapter 8, some operative conservation programs are questionable on economic grounds with the present cost structure of the industry. A long-term solution to electric power needs will require additional investment in baseload facilities. How can regulators convince utility managers that it is in the interest of their stockholders to absorb the risks of investing in new baseload plants?

The regulatory disincentives of the recent past have been most severe for large investment projects with long lead times. Although the most obvious problems, such as the failure to compound interest allowances for funds used for construction, have largely been alleviated, many disincentives remain that make large-scale investments unattractive for regulated utilities. The regulatory contract in effect during the past two decades could be summarized as "break even if it works, lose money if it

does not." The prudence doctrine, as it has been applied in many regulatory controversies, is an example of this implicit contract. Needless to say, the expected return from uncertain, long lead time projects under this implicit regulatory contract is not very enticing.

The regulatory challenge in the public utility sector is to provide an environment that allows firms to correctly weigh the risks of alternative new plants and to select the most cost-effective technology, whether that be nuclear power, coal, wind, solar, cogeneration, or conservation. There are two components to this challenge. One is to provide producers with an incentive structure that encourages efficient risk taking. The other is to encourage an industrial structure in the electric power industry that is most conducive to the attainment of technological efficiency.

II. CONCENTRATION OF POWER AND THE BENEFITS OF MERGERS

The market structure of the electric power industry is little changed from the structure that existed in 1935, when Congress passed the Public Utility Holding Act. Concerned by mergers and the creation of holding companies in the stock market of the 1920s, Congress effectively impeded capital restructuring in the electric power industry with the passage of this act. Although mergers have played a major role in shaping the nation's industrial structure and that of utilities in telecommunications that were not directly targeted by the Public Utility Act, the electric power industry has been (until quite recently) almost untouched by merger in the postwar period.

A common justification for the regulation of public utilities is their status as natural monopolies, and potential abuse of monopoly power is one argument in favor of an antimerger policy for electric utilities. The natural monopoly argument is not generally accepted, but even if it were valid, a closer examination shows that it does not justify a merger prohibition.

Monopoly power in electricity is local, arising primarily from economies of density in distribution networks. Horizontal merger neither increases nor decreases the extent of this source of monopoly power, which in any case is regulated by local public utility commissions. Although merger waves have triggered concern about excessive economic (and political) concentration in our economy, the isolation of the electric power industry from merger activity has not been without cost for this industry and consumers. Utilities have market power in their local distribution networks, but in electric power generation they are a relatively unconcentrated group. In 1980 the four largest electric power companies accounted for about 17% of the electric power sales of all class A

and B investor-owned public utilities.^[2] At about the same period of time, some typical four-firm concentration ratios for capital intensive industries are 28% for petroleum refining, 42% for blast furnaces and steel mills, 85% for flat glass, 31% for cement, 84% for turbines and turbine generator sets, and 92% for motor vehicles. S Of a total of 114 industries defined by the Census of Manufacturing under the headings of "Petroleum and Coal Products," "Primary Metals," "Machinery except Electrical" and "Electric and Electronic Equipment," only 14 had four-firm concentration ratios in 1982 that were equal power utilities. These industries typically involved specialized products (e.g., "industrial patterns") or products that covered a wide range of applications (e.g., "blowers and fans").

Concentration ratios are only a weak indication of the role of firm size in markets. These ratios do not account for the magnitude of transportation costs that might inhibit competition by geographically separated firms, and they are sensitive to arbitrary classifications of industry products. Nonetheless, an inspection of typical concentration ratios leads to the conclusion that the electric power industry is exceptional in the extent of its industry fragmentation, and this is particularly striking given the importance of scale economies in this industry. This observation has been made by others, including Primeaux (1975), Weiss (1975) and Joskow and Schmalensee (1984), and it is central to proposals advocating restructuring and deregulation of electric power generation.

An indicator of efficient firm size is the relation of firm assets to the size of their new investments. A rule of thumb is that the capacity of a minimum efficient-scale unit operating plant should be no more than about 20% of a firm's installed capacity before the unit is built. In the electric power industry a unit refers to a turbine-generator combination. It differs from a plant, which may contain more than one unit. If the unit size exceeds 20% of a firm's installed capacity, planned and forced outages will impose problems of reliability for the firm's supply system, and unless demand growth is very high or the unit displaces existing capacity, capacity utilization may be unacceptably low.

Table 3.1 shows the relation of utility size to the size of "pioneering" generating units over the past three decades. The table shows the percentage of firms for which the pioneering unit size is less than the indicated fraction of the total generating capacity of the firm.

Until recently, larger unit sizes resulted in lower average costs of producing power, and therefore the largest planned units were indicative of the frontier of generation technology. In Table 3.1, the pioneering unit

[2] The source for the electric power share is the U.S. Department of Energy (1980). This share would be smaller if the electric power market were defined to include all producers of electricity in addition to class A and B investor-owned utilities.

[3] . Concentration indices are from the 1982 Census of Manufacturing.

size is calculated as the average of the largest 25% of all units that began operation in the four, five and six years following the indicated date. This figure is representative of the largest plants in the planning and construction phase for each date. For example, the average of the largest 25% of units commencing operation in 1979, 1980, and 1981 is 769.5 MW, which is the pioneering unit size indicated for 1975 in Table 3.1.

The universe of electric power generating firms in Table 3.1 is taken to be the total for each year of all class A and B utilities that produced their own power. Table 3.1 shows that only a very small subset of all class A and B utilities could pass the 20% test for a new capacity addition. In 1955 the pioneering unit size was about 325 MW. In that year, only three firms had a total generating capacity in excess-of 3,250 MW, which would make the pioneering unit size equal to 10% or less of the size of the firm. Nine firms had a capacity in excess of 1,675 MW and therefore could pass the 20% test. This was less than 4% of all class A and B electric power utilities.

The 20% test was met by only a small percentage of the electric utility industry over the period 1955 to 1980. Growth in utility systems and a decline in the sizes of new units being built increased the fraction of the industry that could meet the 20% test to about 18% by 1980, but this is still only a small fraction. Only about 62% of the electric power firms in the industry in 1980 had a total generating capacity less than the size of a pioneering unit.

Actual experience in private industry with the relationship between firm size and the magnitude of investment projects provides a test of the "20% rule" and offers a benchmark for the evaluation of efficient electric power utility size. This comparison is necessarily imperfect. Circumstances differ greatly from one industry to another. A function of utility regulation is to provide financial stability for new investment, and thus utilities might be expected to be more inclined to undertake large projects. Nonetheless, experience in unregulated markets should provide an indication of how market forces influence firm size and this should be at least a guide for efficient market structure in the electric power industry.

Table 3.2 is a summary of the results of a survey of investment projects in different industries. In the petroleum industry, the largest project identified in the survey was a grass-roots, integrated petrochemical complex.^[4]

Consistent with the prevailing refinery situation, no such projects were listed as currently under construction. However, if one were built, its estimated cost for 250,000 barrels/day capacity would be in the range

[4] One might include the Alaska pipeline, but that was a joint venture that was not typical of major investments by individual firms in the industry.

of $1.5 to $2.0 billion (1983 dollars). Upgrading an existing refinery is both more likely and considerably less expensive (Bowen, 1983). This is a very large undertaking, but even the high end of the cost estimate represents less than 10% of the total assets of the largest oil companies. Investment projects surveyed that were actually under way typically represented no more than a few percent of the assets of the firm responsible for the project (Cantrell, 1983; The Petroleum Encyclopedia, 1983).

Trade reports on the aluminum extraction and refining industry indicated investment projects as large as $2.5 billion (1983 dollars), but the largest project actually undergoing construction was $1.5 billion (the $2.5 billion project was deferred at the time of the survey). The $1.5 billion project was a refinery/smelter constructed as a joint venture with Alcoa and Shell Brazil, a subsidiary of Royal Dutch Shell (Engineering and Mining Journal, 1983). The combined assets of the two companies were about $37 billion in 1983, so that the project represented about 4% of the partners' total assets.

The largest projects in the manufacture of iron and steel products are grass roots fully integrated steel complexes. Only about a dozen of these complexes have been built worldwide since 1950, and only two in the United States. The cost could be as high as $3 billion, which would be about 30% of the assets of U.S. Steel. More common are investments in facilities such as oxygen furnaces and coke ovens, which cost up to about $200 million, or no more than 10% of the assets of a moderate-sized steelmaker (Miller, 1977).

In the automobile industry, the launching of an all new platform for a new vehicle can cost upwards of $1 billion. Chrysler estimated that a new line of front wheel drive vehicles would cost the company $1.2 billion (Lambert, 1979) in 1981 dollars and budgeted a similar amount in 1983 for the development of its minivan (Lapham, 1982).

The cost of a large baseload coal or nuclear plant investment can exceed the pre-investment assets of the larger electric power companies. This magnitude of risk exposure, as measured by the ratio of investment to firm size, is not typical in private industry. Although Table 3.2 shows some investments in the private sector that reach as high as 75% of firm assets, these pertain to unusual circumstances. In the case of iron and steel the figure is for a project that was neither planned nor attempted in the industry for many years. The 40% figure in the aluminum industry was for a project undertaken by a partnership of two firms whose total assets were about 25 times the project size.

The surveys summarized in Table 3.2 are only anecdotal and no doubt cases exist in which private firms have undertaken investment programs that are large both in absolute terms and as a fraction of the size of the firm. Nonetheless, the results summarized in the table

generally support the 20% rule of thumb. They also illustrate the extent to which risk-taking in the electric power industry, as measured by the relation of project to firm size, is unusual relative to the unregulated sector of the economy. Although surveys indicated that in the unregulated sector the largest projects were generally undertaken by the largest firms, there were many instances in the electric power industry in which large baseload generating plants were constructed by relatively small firms. Thus Table 3.2, which concentrates on the larger firms in the industries surveyed, probably understates the extent of risk exposure in the electric power industry.

One way that electric power utilities have escaped the 20% rule-of-thumb limitation is to form joint ventures for investment in new facilities. A nuclear plant may have several partners. Although joint ventures are not uncommon in private industry and provide institutional vehicles for sharing the risks associated with a major new investment program, they also introduce a host of other problems that stem from the coexistence of partners, each with different objectives, management approaches, and legal constraints.

A case in point is the Fitchburg Gas & Electric Company. Fitchburg Gas & Electric is a part owner (0.9% of unit 1) of the Seabrook nuclear power plant. Headquartered in Canton, Maine, the company has about 200 employees, total assets of $86 million, and revenues of about $50 million/year. Seabrook is well known as one of the most problem-plagued nuclear facilities in the nation. Begun with a cost estimate of several hundred million dollars, more than $5 billion has been spent on unit I alone, and though now completed, it is uncertain whether it will ever be operated.

Seabrook is a joint venture among several utility companies, including Fitchburg Gas & Electric. Although Fitchburg owns less than 1% of the Seabrook plant, its share amounts to a liability of about $50 million, or more than one-half of its assets. Clearly, partnering did not succeed in reducing the risks to Fitchburg Gas & Electric to an acceptable level. Moreover, the spreading of risks that is the objective of joint venture also prevents one of its greatest hazards. With many partners, the temptation is great to abandon a project that appears to be in trouble, leaving the burden of coast overruns to the remaining partners. This limited loyalty can add to the problems of financing and managing a large joint venture.

III. REGULATORY INCENTIVES AND DISINCENTIVES FOR INVESTMENT

The participation of utilities in investment projects that are much larger than would be considered reasonable by the 20% rule and the existence

of complex joint ventures are consequences of the regulatory conventions that have dominated the evolution of this industry. Regulatory practice in the past has provided protection to utilities by ensuring that revenues would be adequate to cover costs. This allowed utilities to take risks and exploit economies of new investments, even if these risks were very large relative to the standards of private industry. This implicit regulatory contract worked effectively in times of stable technology and declining costs, when mistakes rarely produced instances of rate shock for customers, and when predictable reserve margins made capacity planning a comparatively simple task.

Rate-of-return regulation is a version of cost-plus contracting. The standard regulatory formula generates a return to the utility that is directly proportional to the utility's incurred costs. Operating costs are compensated on an essentially one-for-one basis. Capital costs are compensated by permitting annual charges equal to the allowed rate-of-return on total assets. There are many differences in regulatory procedures and many complications in the ratemaking process (see Chapters 2, 4, and 5) but the essential fact is that rate-of-return regulation is a cost-based approach to ratemaking.

Allowing revenues in proportion to costs is hardly conducive to efficient operations, and with skyrocketing costs for new construction programs it is not surprising that regulators have begun to scrutinize the record of utility performance. Prudence is an old concept in regulatory law that provides for inclusion in the rate base only those expenditures that represent acceptable managerial judgment, but with the large cost overruns encountered in recent years the prudence doctrine has taken on new life.

The appeal of the prudence doctrine is that management should be held responsible to exercise good judgment, and ratepayers should not be penalized for imprudent behavior. Of course, the determination of behavior that is imprudent is not easy. Also, the recent vigorous application of the prudence doctrine can be criticized as a change in the rules of the game. If prudence was not an issue at the time that the expenditures were made, application of the prudence doctrine cannot be justified by its incentive effects on those expenditures. The efficiency consequences can apply only to future expenditures.

The determination of imprudent behavior is always difficult, but the stimulus to search out imprudence increases with the size of the rate shock following the completion of a new plant. Mistakes are not a new phenomenon, but they were easier to forgive in times when prices were stable. Until recently, completed plants typically were entered into the rate base at full cost without an audit of management performance. Despite the obvious merits of pruning out imprudent behavior, the current vigor with which management is held responsible for prudent

performance represents a change in the structure of the implicit regulatory contract.

Some form of prudence accountability should be present in any efficient regulatory framework. A free market has its own prudence doctrine, because the costs of imprudent investments are borne directly by the investor. The current trend in the application of the prudence doctrine has two serious flaws. The first is that while negligence is punished, there is no provision for rewarding outstanding management performance. The prudence cry has been a reaction to price movements; it has not been applied as a true gauge of management performance, and its methods include a stick, but no carrot.

The second major flaw in the application of the prudence doctrine is that it punishes stockholders directly and management only indirectly. A typical application of the prudence concept is to disallow certain costs from inclusion in the rate base. This means that the firm cannot earn revenues on these costs and the market value of the firm is correspondingly reduced. The direct burden of this action falls on the shareholders of the company.^[5] Managers suffer to the extent that their well-being is correlated with the market value of the firm. However, the ownership of shares by utility managers is very small, and managerial salaries in the utility industry are not usually directly affected by application of prudence. Thus the shareholders feel the pain of prudence in their pocketbooks, while managers take it on the ego.

To the extent that management can be held accountable for company performance, management should share in the fruits of their activities. This means paying for clear mistakes and receiving tangible rewards for superior performance. A managerial incentive package would not be costly to ratepayers because managerial salaries are a small fraction of total expenses. But the incentive effects of such a strategy could bring sizable rewards over the longer term to both ratepayers and shareholders.

Regulatory reform in the public utility sector is essential not only to improve the incentives for efficient operations, but also to exploit the potential gains from restructuring in this industry. Merger activity can reduce the size of new investments as a fraction of firm size and in this way mergers can improve the statistics of risk exposure in public utilities. But an improvement in this statistic is unlikely to bring real gain to ratepayers and shareholders unless it is combined with measures that reward efficient behavior. For example, current regulatory practice compensates utilities in proportion to the size of the "used and useful" rate base. It does not reward utilities for minimizing cost or for seeking out

[5] An indirect burden falls on ratepayers because lower earnings increase the company's cost of capital.

the most cost-effective supplies, unless rate regulation is adapted to respond to such behavior. Under traditional regulatory practices (and depending on allowed rates of return and the extent of capacity utilization), utilities could have an incentive to merge for the purpose of expanding the size of the rate base. If regulation does not adapt to encourage efficient behavior, and particularly if no new investments are planned for several years, there is little reason to expect productivity gains from such a merger. But if restructuring of the industry is combined with regulatory reforms that provide incentives for efficient management, there is cause to expect that structural change will be motivated by desires to improve operating efficiencies and that these changes will eventually impact positively on ratepayers and shareholders.

IV. A PROPOSAL FOR REFORM

The Public Utility Regulatory Policies Act of 1978 (PURPA) was a watershed event for the regulation of electric power. PURPA allows independent, unregulated producers to enter the electric power business, and the consequences can be dramatic. Drawing a parallel to telecommunications, the deregulation movement in that industry began when the Federal Communications Commission approved the entry of an independent carrier into the regulated private-line business. It was then only a matter of time until entry into regulated general long-distance services was allowed. What had started as a ripple in the industry turned into a major current of change with the entry and expansion of new independent carriers.

PURPA limits entry to cogenerators and to small power production facilities using certain "soft" technologies with a capacity of less than 80 megawatts (MW).^[6] Also, qualifying facilities can sell power only for resale.^[7] Despite these limitations, independent power producers in some states have responded vigorously to the prospects of selling electric

[6] According to PURPA, a cogeneration facility is "a facility which produces—(i) electric energy, and (ii) steam or forms of useful energy (such as heat) which are used for industrial, commercial, heating, or cooling purposes." A small power production facility is "a facility which (i) produces electric energy solely by the use, as a primary energy source, of biomass, waste, renewable resources, or any combination thereof; and (ii) has a power production capacity which, together with any other facilities located at the same site . . ., does not exceed 80 megawatts" (Public Utility Regulatory Policies Act, 1978, STAT. 3134-5).

[7] . Qualifying facilities must meet requirements respecting minimum size, fuel use, fuel efficiency, and other conditions established by the Federal Energy Regulatory Commission, and must be "owned by a person not primarily engaged in the generation or sale of electric power (other than electric power solely from qualifying facilities or small power production facilities)" (Public Utility Regulatory Policies Act, 1978, STAT. 3135).

power. The figures shown in Tables 3.3 and 3.4 aggregate the cogeneration and small power production for the service areas of PG&E, SCE, and SDG&E. They indicate a staggering potential contribution to the electric power production capacity of California. The California Energy Commission estimates that the dependable electricity production capacity of the state, excluding small power producers, self-generation, and imports, is approximately 46,000 MW, of which about 38,000 MW are in the PG&E, SCE and SDG&E service areas (California Energy Commission, 1989). The total on-line and potential cogeneration and small power production capacity indicated in Table 3.3 is almost 50% of the dependable capacity in PG&E, SCE, and SDG&E service areas. It is almost ten times the capacity of the Diablo Canyon nuclear power plant (2,190 MW for both units).

Much of the capacity indicated in Table 3.3 is potential, not actual. Of the total of 18,000 MW of actual and planned capacity, 1,664 MW were on line at the end of 1984. Although only a small fraction of the total, this is still a significant contribution to the electric power capacity of the state. Furthermore, Table 3.4 shows rapid growth in the amount of online cogeneration and small power production. Actual capacity more than doubled in the two years from the end of 1984 until the end of 1986. By the third quarter of 1989, the amount of on-line power doubled again. By the third quarter of 1989, outstanding project commitments (which are the total of projects on line, in progress, and projects with signed letters of agreements), represent yet another doubling of actual capacity.

The response of cogenerators and small power producers to the window of opportunity created by the Public Utility Regulatory Policies Act of 1978 was nothing short of phenomenal. Of course a major factor in the growth of independent power production in California was the result of the attractive terms of Standard Offer No. 4, which guaranteed long-term purchase prices that are much higher than the near-term marginal cost of electricity. Standard Offer No. 4 has since been suspended by the CPUC, but many of the projects summarized in Tables 3.3 and 3.4 have the benefit of Standard Offer No. 4 or similar contracts that offer high long-term purchase prices.

The phenomenal rate of growth of cogeneration and small power producers in California is unlikely to be sustained when long-term purchased contracts such as Standard Offer No. 4 are replaced with contracts that offer less favorable terms. The incentives for independent power production will be less attractive, and the pool of favorable sites for independent power has been diminished by the growth that has occurred. Nonetheless, the experience with independent power in Califor-

nia summarized in Tables 3.3 and 3.4 is a clear indication that independent power production can make a large contribution to electric power needs, at least in the state of California. The advent of PURPA has been a major reform of utility regulation, which, despite its limitations, has the potential for significant change in the structure of the electric power business.

Deregulation is an economist's motherhood and apple pie, but PURPA, as it is currently implemented, introduces as many problems as it solves. The size and technology restrictions aggravate the current regulatory bias against large-scale facilities. The challenge of regulation is to provide a climate that encourages investment in the most cost-effective alternatives. The current regulatory environment does not do that and PURPA does not help.

Another PURPA problem is the restriction of power only for resale. Qualifying facilities (QFs in the PURPA vernacular) do not compete in the general market for electric power. They compete only with a utility's "avoided cost"—an elusive concept that is transformed into reality after an arcane calculation by a regulatory commission. Furthermore, regulatory restrictions limit the involvement of utilities in qualifying technologies, so that competition in the PURPA territory is even more limited.

The current approach toward contracting for qualifying facilities imposes regulatory risks on both the QFs and the utilities. The QFs have to forecast avoided costs, unless they can enter into long-term contracts at set prices. With long-term contracts at fixed prices, utilities and rate-payers have to assume the risk that the future value of the PURPA energy will be different from its contractual cost and that the resulting amount of power produced will be more or less than is desired.

With only short-run or spot prices for avoided costs, QFs have to face the risk that future prices may not be sufficient to cover capital costs, and this uncertainty may make capital more difficult to obtain. QF proponents can argue that regulation is asymmetric in this situation, because regulation at least nominally reimburses costs incurred by public utilities and provides some protection from risk, while short-run pricing for QFs does not provide equivalent insurance.

The PURPA regulatory process imposes different risks on utilities. Utilities do not have the option of taking a risky contract that would allow them to earn above-normal profits (as well as losses) from new investments. Also, regulatory risks fall on the utility whenever it guarantees a rate structure to a QF, whether the rate structure is long-term or spot. The utility must recover these revenues in a regulatory process that experience has shown is not without risk. Having agreed to contracts with QFs, the utility is a residual claimant to earnings that are left

over after the QFs are paid. The natural response for utilities to this situation is to pursue a yet more cautious investment policy—one that minimizes the amount of capital at risk.

Thus the effect of PURPA may be to further increase the bias against large investment projects. Also, with utilities barred from cogeneration projects and with no incentive to build large plants, we may find regulated utilities more in the position of being energy brokers for independent power producers, with their own investments reduced to quite limited programs.

Despite its limitations, PURPA brings a major regulatory innovation to the electric power industry with significant opportunities for positive reform. The avoided cost pricing methodology advanced in PURPA is a powerful alternative to the existing rate-of-return approach to public utility regulation. Rate-of-return regulation is essentially unworkable. When it is applied to the letter, it creates sharp differences between the technology choices favored by stockholders and the choices that either minimize customer revenues or maximize productive efficiency. Simply stated, whenever the allowed rate-of-return exceeds the cost of capital, stockholders should favor the most capital-intensive technology because this maximizes the profits of the firm. When the allowed rate-of-return is less than the cost of capital, stockholders favor the least capital-intensive technology if growth must occur, and they would prefer not to invest at all if that were an acceptable outcome (see Chao, Gilbert, and Peck, 1984).

Rate-of-return regulation provides little in the way of incentives to hold down costs. Also, rate base regulation is more risky for projects with long lead times and large capital expenditures, and hence rate-of-return regulation discourages investment in these types of technologies. If utility managers could be convinced that future regulatory policy would allow generous earnings relative to the cost of capital and that future expenditures would be guaranteed to be included in the rate base with no penalties, the bias against large projects would turn completely around to a stimulus for investment in such projects. But it is difficult to see how regulatory commissions can convince utility managers that the problems of regulatory risk with respect to large, long lead time projects will be solved and that the regulatory insurance policy so reliable years ago will be reinstated. Without such a commitment, it is likely that rate-of-return regulation will continue to include a bias against large investment programs for some time to come.

An extension of the avoided-cost methodology introduced by PURPA allows a mechanism for reform of public utility regulation in a way that would not discriminate against projects of different sizes. This proposal is a modification of the recommendation given by David Roe (1985), who

suggests that (short-run) avoided-cost pricing replace rate base regulation for regulated utilities, as well as being available to independent power producers under PURPA. The advantage of this proposal is that short-run avoided cost, if computed properly, is a measure of system marginal cost, which is the true value of another unit of power on the electric power system.^[8] A criticism of short-run avoided-cost pricing is that the variability and unpredictability of future rates frustrates generation planning and makes it difficult to raise capital for new projects. The following proposal is an attempt to deal with this problem, while preserving the efficiency advantages of Roe's proposal.

Short-run avoided-cost pricing is desirable because of the difficulty, mentioned above, that a fixed-price offer may bring either too much or too little generation relative to the needs of consumers. A fixed price that is too high will result in too large reserve margins, and with excess capacity the system marginal cost is likely to be below the fixed price. The converse may occur if fixed prices are too low.

However, efficient production requires only the equality of prices and marginal costs for those generation decisions that are on the margin. Fixed prices are not inconsistent with the attainment of economic efficiency if it is possible to produce more or less power and receive a price equal to the short-run system marginal cost.

To see how this may be accomplished, suppose a firm (public utility or otherwise) is considering a project which will add a production capacity of K megawatts with a cost structure

where q is actual output in megawatts, b is the capital cost per unit of capacity, and v is the variable cost per unit of actual output.If short-run pricing prevails, future prices will depend on demand and supply conditions and will be uncertain at the time the new plant is under consideration. The plant should operate only if the price exceeds its variable cost, v. If the future price at time t is P(t), the plant will earn net revenues of P(t)- v for every megawatt it produces when P(t) exceeds v, and it will stand idle whenever P(t) is less than v. The plant will be built only if expected net present value revenues, adjusted for risk, exceed the capital costs (including all financing costs). Price risk can be removed by offering a guaranteed price P _g (t). The firm then will produce whenever P_g (t)> v;however, this is inefficient if the system marginal cost is less than v .

This difficulty can be corrected with the following scheme. The regulatory commission allows the firm to sell a fraction, a, of its production

[8] If avoided cost is to be an accurate measure of marginal cost, it must include provisions for valuing reliability and peak versus off-peak production, among other factors.

capacity at the guaranteed price P_g (t). The remaining capacity, (1-a )K, is available for purchase at the spot price P(t ), which is set equal to the short-run system marginal cost. The firm should sell this power only if P(t)> v: hence the firm operates efficiently with respect to production in excess of the contracted amount a K.

In addition, the firm is offered the following bargain. If for any reason the purchaser does not want to buy all of the contracted power aK (assuming that it is available), then the firm will be offered a price P_o (t) as a payment for not producing. The firm need not accept the offer. However, if P_o (t) is set equal to the difference between the guarantee price P_g (t) and the system short-run marginal cost P(t ), a profit-maximizing firm would accept the offer only if it were economically efficient to do so from the standpoint of total system costs. To see this, note that if the firm chooses to produce, it receives the guaranteed price P _g (t) and earns P _g (t) -v /megawatt. If it accepts the bargain and stands idle, it receives P_g (t) -P(t) for each megawatt that it does not produce when q(t) is less than aK. Accepting the bargain is a good deal for the firm if P_g (t) - P(t)> P_g(t) v, or if vP(t ), but this is exactly the condition under which the firm should not produce, because the firm's short-run marginal cost exceeds the system's short-run marginal cost.^[9]

This proposal of a combined guaranteed price for a contracted amount of production, along with a spot price for either increases or decreases in production, has several advantages.

•     The offer assures the investor guaranteed revenues equal to P_g (t)a K if the plant is capable of producing at least K. The guaranteed payment is an insurance policy for the firm.

•     The opportunity to sell more at the spot price P(t) or to sell less in exchange for the payment P_g - P(t) permits the firm to increase its net revenues above the level implied by the guaranteed price. The firm will trade more or less than the contractual amount only if it is profitable to do so. The contractual revenues are only a floor on the firm's total earnings.

•     The purchaser can guarantee payments of no more than P_g (t)aK by refusing to engage in spot trades. The purchaser will buy more only if the seller can generate the additional power efficiently.

•     The purchaser can reduce its payment obligations by exercising the right to buy less than a K at a price of P_g (t)- P(t)/megawatt, provided the seller accepts the offer. If the seller agrees not to produce

[9] It is not difficult to see why this offer works. It is equivalent to retaining the price guarantee P _g (t), but deducting P(t) if the firm elects not to produce. By not producing, the firm is saving the variable cost, v. It should therefore accept the bargain if v> P(t).

at all, the purchaser's maximum payment is not P_g (t) a K, hut rather [P _g (t) - P (t)] a K

•     This proposal retains regulatory jurisdiction in those areas where regulation may serve a useful purpose These are:

Long-Run Capacity Planning

A criticism of deregulation proposals in the electric power industry is that an unregulated market may be less efficient than an administered market in planning capacity additions to meet demands. This argument would have little basis if futures markets existed for electric power, but they do not and their appearance is not likely (a deregulated market is more likely to develop long-term contracts for electric Power supply, with elements similar to those suggested in this proposal). Furthermore, for large capacity additions, the market criteria for profitability do not coincide with the social calculus for an efficient investment. The market compares total present-value revenues against total present-value costs. The social calculation relies on total present-value benefits, which exceed the revenues earned for a large increment to capacity.

For these reasons it may be desirable for a regulatory body to retain some control over the amount of planned capacity additions. The price guarantee provides a means by which this may be accomplished. By increasing or decreasing the guarantee price and the share a regulator can control the amount of capacity additions by altering the profitability of new investment.

Standard Offer No. 4 has been held as an example of the problems of offering a guaranteed price. Reserve margins in the next decade are expected to be adequate and the amount of independent power responding to the price offer will be a surplus on the electric power market. If this is true, it merely argues that the guaranteed price is too high. In practice the guarantee price should be flexible, adjusting to match perceived capacity needs with indicated supplies.

Electric Power Tariff Structure

The proposed pricing schemes affect only the supply side of the electric Power market. Regulators are free to choose customer prices at will, subject to the constraint that revenues are sufficient to cover costs (if the regulatory commission cannot run a deficit). Another constraint on the regulatory commission is that the price structure should not encourage end users to abandon the public supply system and produce for their own needs. This bypass problem is an indication that some consumers are subsidizing others (because they are paying more than their "stand-alone" cost of supply), and it is already emerging as an important issue in electric power regulation (see Chapter 4).

Cross-subsidization is endemic to regulated industries; indeed, some would say it is basic to the regulatory process. Posner (1971) describes regulation as an institution that allows a system of taxation and subsidies. Much of the cross-subsidization present in regulated electric power tariffs would be eliminated if the electric power industry were opened to competition. A free market would bring supplies to those customers who are paying more than their incremental cost of production, at the expense of those who are paying less.

Cross-subsidies exist sometimes for political reasons, but other times for reasons of perceived fairness. Complete abandonment of the power to cross-subsidize would eliminate the flexibility to respond to these concerns. The proposed pricing system preserves some regulatory flexibility for end-user pricing, although constrained by market realities.

PURPA may revitalize the electric power industry, bringing new technology and new vigor to the market. It also may bring a return to the early years of this century, when a proliferation of backyard power plants of inefficient scale with quickly obsolete technology interrupted the development of a new industry. The pricing proposal described here provides an opportunity to extend the structural changes inherent in PURPA to the industry at large. The proposal would avoid a regulatory system that discriminates against particular generation technologies and replaces it with a system that allows competition among all potential suppliers of electric power, while retaining important aspects of regulatory oversight for the planning of electric power supply and for fairness (consistent with costs) in the pricing of electric power.

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