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
C (q , K) = b K + vq | for q < K |
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 Pg (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 Pg (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 Po (t) as a payment for not producing. The firm need not accept the offer. However, if Po (t) is set equal to the difference between the guarantee price Pg (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 Pg (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 Pg (t) - P(t)> Pg(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 Pg (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 Pg - 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 Pg (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 Pg (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 Pg (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.