Marginal cost pricing for utilities: a digest of the California experience.
California has been a bellweather state in inaugurating regulatory pricing techniques,(1) and the California Public Utilities Commission (CPUC) has moved marginal cost pricing from crude to refined. The dollars at stake have been huge by any standard. Electric revenues for the state's "big three" companies total about $16.8 billion annually (1995 data). The dollars are proportionally as large for major companies in other states.
In California, after two decades, procedures for marginal cost pricing have reached an advanced stage of maturity. However, by reason of California legislative action imposing a rate freeze, further steps are now at an abrupt stop until the year 2002. So there is opportunity now, in this hiatus, to pause and to rethink the basic question: can microeconomic marginal cost theory, as expressed in the doctrine, in actuality be put into operation without major debilitating deviations so as to achieve the goal of economic efficiency by transmitting accurate price signals to consumers?
The time is ripe for a reexamination of the efficacy of the marginal cost pricing doctrine for other states that have adopted it, as well as for California. The entire electric industry stands at the crossroads of restructuring. Will the doctrine become an anachronism or continue as a guide for regulated pricing? Energy professionals and academicians alike will contribute to the answer.
The California experience is instructive both historically and prospectively. Historically, a brief-summarization of the CPUC's tortuous steps to cross the bridge from theory to practice - virtual tour de force in economic improvisation provides an overview of the raw data for a reexamination.
Prospectively, the pricing issue is even more intriguing. In California, will the CPUC continue marginal cost pricing for utility services that will remain regulated after the rate freeze expires (local transmission, distribution and its several subfunctions, and QF payments)? Will free market prices for the deregulated electric generation sector - as they emerge from restructuring - conform to the microeconomic model of perfect competition as this model has been interpreted by the CPUC for fixing prices at the generating plant, either short-run or long-run? Nationally, given the divorce of generation from price regulation, will marginal cost pricing be relegated to the role of "just another" cost allocation method?
Whatever the answers to these questions may turn out to be, the ventures of the CPUC provide useful background for the general microeconomist as well as for the specialist in micro theory applied to energy pricing.
A. The Marginal Cost Pricing Doctrine
The "marginal cost pricing doctrine" is shorthand for the proposition that utility rates should be predicated upon marginal costs for the purpose of attaining economic efficiency by means of accurate price signals.
The doctrine stems from Professor Alfred E. Kahn's hugely influential two-volume book, The Economics of Regulation, (1970 and 1971). Kahn espoused marginal cost pricing as a means of bringing "economic efficiency" to regulated utilities. This pricing would result in "price signals" to consumers of sufficient accuracy so that they could evaluate the appropriate economic level and timing of their use of utility services. Thus, the buying decisions of consumers would be the means by which the end purpose of economic efficiency would be reached.
B. The Theory(2)
Quoting Professor Kahn, normative/welfare microeconomics concludes that "under pure competition, price will be set at marginal cost" (the price will equal the marginal cost of production), and this results in "the use of society's limited resources in such a way as to maximize consumer satisfactions" (economic efficiency) (I, pp. 16-17).
The basis for the theory is clearcut: since productive resources are limited, making the most effective use of these limited resources is a logical goal. In a competitive economy, consumers direct the use of resources by their buying choices. When they buy any given product, or buy more of that product, they are directing the economy to produce less of other products. The production of other products must be sacrificed in favor of the chosen product.
From this point, marginal cost theory takes a giant step. In essence, it states that if consumers are to choose rationally whether to buy more or less of any product, the price they pay should equate to the cost of supplying more or less of that product. This cost is the marginal cost of the product. If consumers are charged this cost, optimum quantities will be purchased, maximizing consumer satisfaction. If they are charged more, less than optimum quantities will be purchased: the sacrifice of other foregone products will have been overstated. If they are charged less, the production of the product will be greater than optimum: the sacrifice of other foregone products will have been understated. A price based on marginal costs is presumed to convey "price signals" that will lead to the efficient allocation of resources. This is the theory, drawn from the microeconomic model of pricing under perfect competition, upon which the doctrine rests.
Economists agree that the real world is imperfectly competitive, a long way from being a mirror of the perfectly competitive model. The CPUC's utilization of marginal costs for pricing represents attempts to arrive at economic efficiency and accurate price signals by "second best" solutions.
Hall (1996) points out that neoclassical theory is inapplicable for a number of reasons. We list these reasons now as part of this introduction so that the reader may have them in mind as the survey unravels. Hall's main reasons are: (i) investment options are lumpy, not continuous; (ii) demand shifts over time, as do relative input prices and technology; (iii) technology is heterogeneous;(3) and (iv) system reliability standards and optimal reserve margins are responsive to uncertain demand and uncertain supply. These reasons, among others - especially investments by consumers - point to the difficulty of resolving the issue of adopting short-run versus long-run marginal cost, including the question of whether these costs should be calculated relative to the actual or optimal system (Hall, pp. 79-80).
Since references to water projects and water quality are equally applicable to power, Hall's observation (pp. 92-93) is relevant:
The conceptual issues of marginal cost go well beyond neoclassical theory, including joint products, peak demand, discontinuous and incrementally sized water projects, shifting input prices and shifting demand over time, changing water quality, omitted externalities, probabilities of shortages, and shifting system reliability.
C. Scope of this Paper
This paper explores the history of the CPUC's actions without evaluation. It is a digest, limited to providing a skeletal outline of the CPUC's steps in implementing a marginal cost approach to electric rates. As such, it serves only as a highly condensed starting point for examination of the underlying issue: the economic efficacy of marginal cost pricing as a ratemaking tool.
Such an examination, the subject of a separate paper,(4) explores whether the CPUC's approaches conformed to marginal cost theory or departed from it, on both theoretical and practical grounds. Specifically, are the CPUC's adopted "second best" alternatives sufficiently rigorous so as to achieve the objectives of the marginal cost pricing doctrine, or do they fall short in material respects?
II. THE CALIFORNIA HISTORY(5)
Regulatory practice does not straight-forwardly unfold from dictates of economic analysis, but in fact regulatory policy has an inherent human and institutional aspect.
Theory improves over time, given the energetic attempts to apply it and the repeated discoveries of serious shortcomings.
Darwin C. Hall
This history charts the attempts of a well staffed and knowledgeable utility regulatory commission to apply neoclassical microeconomic pricing theory. It has not been a smooth path. Solutions did not become apparent overnight: they evolved, partly by trial-and-error, partly by refinements in theory and practice, but always painstakingly, over a span of more than 20 years. The only constant has been the commitment to make marginal cost pricing work.
Readers who are associated with utility regulation, either as utility or commission experts, will find the history to be familiar ground. The same may not be true for the uninvolved academic scholar, a newly appointed utility commissioner, or a member of the general public. Unique terms, and particularly their acronyms and abbreviations, are myriad. We are introduced to EPMC (equal percentage of marginal cost), ERI (energy reliability index), CT (combustion turbine), and a host of others, not to mention the standard technical nomenclature of the utility industries. And while most economists may be inclined to rest easy when reference is made to "marginal costs" and like terms of the microeconomic vocabulary, they may find themselves in new territory as they attempt to pierce the special nuances of familiar definitions modified and particularized to accommodate a utility-type application.
But history is history. That is the scope - and the limit - of the digest that follows.
A. The Legislative Directive: ACR 192, August 31, 1974
This History begins with a 1974 act of the California legislature that directed the CPUC to investigate marginal cost pricing as one of six alternatives to existing rate structures. At that time, a shortage of electricity in the near future seemed probable, and for that reason, conservation was emphasized.
B. The CPUC Response - The Adoption of Marginal Cost: Decision No. 85559, March 16, 1976 (Generic)
In what easily could be mistaken for a high level debate within the economics profession, the testimony presented argued the pros and cons of using marginal costs versus average costs in ratemaking, with the diverse points of view presented by highly qualified economists. The Commission concluded that "efficient resource allocation requires that all prices be set equal to their 'incremental' costs," but that such costs would have to be adjusted so as to equate to the revenue requirement. For this adjustment, it favored the "inverse elasticity rule" but acknowledged that elasticity data were lacking (pp. 5-6).
The Commission adopted a policy "to make conservation in the sense of efficient allocation of electricity the keystone of the rate structure" (p. 7).
Other than deciding to follow the marginal cost approach, the Commission made no decisions as to how the approach would be applied. Left in abeyance was whether to use long-run or short-run marginal costs.
Some of the language was colorful. Commissioners Symons and Sturgeon, in dissenting-in-pan comments, had this to say:
Trailing the fashionable banner of "conservation," the majority opinion floats off into the heavens of "theoretical economics" where cloudy and nebulous concepts like "incremental and marginal pricing" are found. Combine this with a strong dose of the elusive "inverse elasticity rule" and you have a rate-setting formula where Whim is King.
C. Types of Marginal Costs: Decision No. 91107, December 19, 1979 (PG&E)
This decision sketched out, in broad outline, the types of marginal costs associated with electric utility operations. These are capacity costs (unit: $ per kilowatt), energy costs (unit: [cents] per kilowatt-hour) and customer costs (unit: $ per customer). Capacity costs are segregated by function into generation, transmission, or distribution classifications. Defining marginal cost as "the changes in total costs with respect to a change in output (or, the cost to produce one additional unit of a commodity or the savings from producing one unit less)," the marginal cost calculations should "measure the change in total system costs (capacity, energy, customer) which results from a change in the level of kilowatt capacity, the number of kilowatt-hours generated or the number of customers on the system" (p. 85).
(i) A Digression on the Nature of Costs. The cost categories established by the Commission as outlined above are primal to the difficulty of determining a marginal cost for utilities.
Microeconomic theory presupposes a simple cost calculation: the extra cost of manufacturing an additional tube of toothpaste, an additional television set, or an additional clothes dryer, each tube, set or dryer being identical to the others. Before and after costs are clear cut.
But calculating the extra cost of an additional kilowatt-hour (even in multiples of thousands or millions) is not as easy as the theory suggests. Kilowatt-hours are identical only in terms of their energy content: their costs differ depending upon the sources and timing of their production (generation), the distance and line loadings involved in their bulk movement from generating plant to major centers of use (transmission), and the configuration and variety of the facilities employed in their continued movement to the customer (distribution, primary and secondary). For the utility, a complex of different types and magnitudes of these functional costs must be accounted for, not just a before-and-after cost for an identical product manufactured in a single-function process.
The CPUC's categorization of the types of utility costs is not unique. It views each type of cost from the traditional perspective. The change is that the CPUC substitutes marginal costs for the average costs that earlier had been the norm. This is, of course, the vitality important substitution which is the main concern of this paper. Average costs include all costs of the utility which are legitimately incurred and therefore recoverable in rates: investment costs of all plant and other facilities - including a return of and on the outstanding invested dollars - and operation and maintenance expenses. Most investment costs arise from facilities constructed in prior years. For this reason, utility jargon often uses the term "embedded" costs, rather than average costs, to reflect the fact that such costs are an integral part of the utility's financial obligations regardless of when the obligation was incurred. Marginal costs disregard these average or embedded costs. In theory, at least, marginal costs look to the future.
Utilities encounter large fixed costs in providing facilities having sufficient generating, transmission and distribution capacity to supply customers' demands when, where, and to the extent needed.
The public expects that lights should turn on at the flick of a switch and that heat should respond to the moves of the thermostat. Capacity to provide energy at the customers' demand is taken for granted.(6) The costs of capacity are fixed since they do not vary with output in the short run.(7) Utility jargon for fixed costs is imprecise: the terms "capacity" costs, "demand" costs, and "readiness-to-serve" costs often are used interchangeably. Borrowing from economic literature, they also may be referred to as "sunk" costs. Whatever the term, fixed costs are primarily the investment costs of facilities, plus items such as property taxes that remain stable regardless of the degree of utilization of the plant.
In utility practice, fixed costs are recovered in large-user rates as a demand charge, one of three components of the total rate.(8) This charge is assessed on a "per kilowatt of the customer's maximum demand" basis.
Utilities experience two types of variable costs. Some fluctuate with the amount of energy taken by the customer. For electricity, these are primarily the costs of the fuel used at the generating plant. Others are dependent upon the number of customers.
Variable costs that fluctuate with energy volumes are recovered from measured usage charges assessed per-kilowatt-hour for electricity; per-them or per-cubic foot for gas. The common jargon for the former is "energy charge"; for the latter, "commodity charge." The usage charge is the second separate component of large-user rates. The "customer" charge is the third.
Both fixed and variable costs are almost always common or joint. The generating plant produces power for customers of all classes; transmission lines similarly carry power that will be delivered via the distribution system to intermingled types of customers. Therefore, a difficult issue in utility costing is the selection of the most appropriate method of cost apportionment among customer classes (in utility jargon, "allocation"). A wide variety of allocation methods have been suggested and tried over the years. For example, per-kilowatt demand costs can be allocated on the basis of the customer's load at the time of the system peak. This is one version of what are called "peak responsibility" methods. All modern allocation methods purport to follow the principle of "cost causation" that is, charging the cost to the factor (i.e., the customer class) for whose benefit it was incurred.
(ii) Decision No. 91107. D.91107 also reflects the CPUC's first attempt to come to grips with company - specific marginal costs. A wide army of costs were introduced. For example, PG&E presented alternative marginal costs, based on different approaches, for the generation, transmission, primary and secondary distribution, and customer functions, divided into energy and demand (capacity) components. To illustrate, PG&E estimated the costs of generation at the transmission level, in dollars per kilowatt per year, as follows (p. 82, Table 9-3):
Gas Turbine Assumption $34.83 Pumped Storage Assumption 57.12 System Power Values Approach 80.54
Marginal costs - the aggregate of capacity, energy, and customer costs - were far out of balance with the revenue requirement. PG&E's electric revenue data at that time were (p. 88, Table 9-4):
Marginal costs $2,917,253,000 Revenue requirement 1,426,633,000 Excess of marginal costs over revenue requirement $1,490,620,000(*) * With adjustments, this figure is $1,572,577,000 (p. 89).
The Commission commented: "The staff was confronted with the dramatic task of first eliminating over 1 1/2 billion dollars from its rate design proposal prior to attempting to develop marginal cost-oriented rates" (p. 89).
The Commission also introduced rate floors (minimum rates) and ceilings (maximum rates), - practice that continues to the present day.
D. Inclusion of Marginal Costs in the Electric Ratemaking Process: Decision No. 92549, December 30, 1980 (SCE)
The CPUC's "Standard Practices" Handbook cites this decision as the first "recognizing the desirability of marginal cost pricing applied to electric ratemaking" (p. 1.A.3). It was issued some 10 years after Professor Kahn's The Economics of Regulation, some four years after Decision 85557 instituted studies on marginal cost pricing, and one year after D.91107, C., supra. As an early endeavor, it is understandably tentative in its treatment of marginal cost applications. Many issues, later resolved, are approached quite gingerly. The Commission, it seems, was groping toward coherent answers, struggling with the complexity of marginal cost pricing when initial attempts are made to convert theory into practice.
At the outset, a prime difference between the situation as seen in 1979-1980 and as reflected in the more recent cases, discussed infra, should be kept in mind. In this SCE case, as in the earlier PG&E case, marginal costs exceeded the revenue requirement. Marginal costs had to be reduced to bring them into balance with the revenues that the utility would be allowed to collect. In part, this paradox reflects the perceived shortage of capacity of 1980, as contrasted to the excess of capacity prevailing in later years. More importantly, in the early years, the incremental cost of new capacity was estimated to be much higher than the cost of existing capacity, a relationship that was reversed later.
The Commission saw the main issue regarding electric pricing as "the relationship of marginal cost and cost recovery by customer groups ... [with the staff arguing] that marginal costs should be used to the exclusion of embedded [average] costs ... [while Edison felt] that both embedded costs and marginal costs should be used" (p. 124). However, many proposals were "presented in concept only" (p. 124).
The Commission concluded, "Marginal costs provide the acceptable approach to allocating cost recovery among customer groups" (Findings of Fact #12, p. 230) and that "[d]irecting rates for marginal usage by each major customer group toward the cost to the utility of furnishing an additional unit of system supply will provide appropriate signals" (Findings of Fact #29, p. 233).
Marginal costs exceeded the revenue requirement by about $1.4 billion. To "scale down" the marginal costs, the Commission ignored the inverse elasticity approach, adopting instead an equal percentage of the difference (EPD) between the revenues from marginal costs and present revenues, adjusted to reflect the lifeline rate program, with the marginal costs to include only energy and capacity costs of generation and transmission (pp. 150-151). Marginal customer costs were excluded. (This exclusion of marginal customer costs was reversed later.)
E. Calculation Methodology: Decision No. 92749, March 31, 1981 (Generic)
This decision promulgated a "general methodology" for electric marginal cost calculation but addressed only "costing considerations [and provided] no guidance as to the proper or preferred method for using marginal cost or rationing cost in either rate design or resource planning" (p. 10). It postponed the tough measures of implementation. Short-run and long-run costs are distinguished, but with no determination as to how each is to fit into a final calculation (pp. 12-13). D.92749 did, however, include an important conceptual statement: "The fundamental concept of marginal costs analysis is identification of a least cost system response to a change in demand" (p. 13).
F. Adoption of the Combustion Turbine (CT) as a Proxy for Generation Costs and Adoption of Short-run Marginal Costs: Decision 93887, December 30, 1981 (PG&E)
Two important elements of this early decision are (i) its adoption of the cost of a combustion turbine (CT) as a basis (or proxy) for the marginal generation costs of demand or capacity (p. 168) and (ii) its adoption for setting rates of short-run energy plus short-run capacity costs (p. 170).
On the latter point, the Commission's objective was clear: "[W]e want to show the consumer the present cost of his consumption" (p. 170). This is significant, because it indicates that the intent was to suggest current price signals, not signals having longer-range price implications. For this reason, the Commission adopted the rule that "short-run energy plus short-run capacity costs should be used in setting rates" (p. 170), emphasizing that different marginal cost combinations might be adopted for other purposes (p. 169).
The Commission (pp. 171, 169, and 183) stated the equation:
MC = shortage cost + marginal operating costs.
(i) Shortage cost. The decision illustrates the shortage cost in reference to the reserve margin. Assume a 15% reserve margin as a starting point. A small increase in demand drops this to 12%. "The shortage costs can be viewed as the cost of increasing the reserve margin from 12% back to 15%" (p. 171).
PG&E created "a proxy to measure the shortage costs ... what a customer would have to pay to avoid a shortage by assuming that the least cost to customers would be the least capital-intensive addition to capacity... a gas turbine (CT)" (pp. 171-172). (ACT has low capital costs, but high energy costs, and therefore is considered to be well-suited to provide peaking capacity that would be operated only during short-duration peak-load periods. Generally, a shortage of capacity, if any, would occur only in peak periods when available reserves are low.)
The Commission adopted a 24-year useful life for the CT, with a 9.1% carrying cost, totalling $76.56/kw/year at transmission voltage in 1982 dollars (p. 180).
(ii) The short run. "[The short run is] a period in which the fixed assets or capital goods of a firm cannot change in response to a change in demand" (p. 171), [but the firm] "can change its variable inputs" (p. 169).
(iii) Background. The Commission continued to recognize that "the total marginal cost of an electric utility includes energy costs, demand or capacity costs, and customer costs" (p. 167). It also listed the variety of purposes for which marginal costs are considered: "Marginal costs are used for resources planning, that is, investment decisions to be made in the future, cogeneration pricing, small power production pricing, cost effectiveness of conservation planning, and ratesetting" (p. 168). Additionally, "within one general theory there can be different calculations of marginal costs depending on the purposes they serve and the time period which is being considered" (p. 168). The determinations of D.93887 as outlined above apply only to the ratesetting purpose (p. 169).
The Commission realized that its shortage cost concept was difficult, indicating that the cost could be derived as (i) the cost of purchasing energy from outside sources, (ii) the price increase required to reduce demand (the market clearing price), or (iii) the cost of load management incentive to reduce demand, in lieu of the CT proxy it adopted.
G. Adoption of Real Economic Carrying Charge for CT: Decision 82-12-055, December 13, 1982 (SCE)
In this decision, the Commission retained the CT as the basic unit for the additional generating resource to be incorporated into the marginal capital cost of generation (here termed a "shortage cost"), but substituted a "real economic carrying charge" (RECC) for the previously used "levelization factor."
The levelized cost of a CT was $128 per kw per year (p. 189). The substitution of the RECC (inclusive of an adjustment for inflation) [TABULAR DATA FOR TABLE 1 OMITTED] reduced this to $58 per kw per year (p. 201).
The Commission elaborated on its position on a shortage cost. It explained, "The conceptual basis ... is that when a utility system is in equilibrium, with reserve margins equal to target levels, the customer cost of not meeting an additional increment of peak demand (the shortage cost) is equivalent to the utility cost of supplying the demand in a least cost way (building more peaking capacity such as a combustion turbine)" (9. 200).
Also, the Commission concluded that a transmission and distribution shortage cost component should be included in its retail rate calculations, but did not do so because accurate data were not available (pp. 201-202).
H. Adoption of the Equal Percentage of Marginal Cost (EPMC) Methodology for Allocation by Rate Classes: Decision 83-12-065, December 20, 1983 (SDG&E)
This decision adopted the Equal Percentage of Marginal Cost (EPMC) method for the allocation of revenues authorized to be collected from the several customer classes. EPMC was substituted for the prior EPD method.
Table 1 summarizes the proceeding data to illustrate the utilization of EPMC (p. 147, Table 12).
The Commission did much soul-searching in deciding upon EPMC, reviewing a number of alternative approaches. It discarded EPD because it found that EPD "does not move toward marginal cost-based allocations when total system marginal cost revenue is less than total system present revenue, as in the current case for SDG&E" (p. 135).
I. Adoption of the Energy Reliability Index (ERI) to Modify Annual CT Costs: Decision 83-12-068, December 22, 1983 (PG&E)
In prior decisions (see section F of this History) the CPUC had adopted the annual cost of a CT as representing a shortage cost (the value of additional capacity, or conversely demand reduction, to the utility system) (p. 333). In this decision, the Commission decided to adjust this cost, either up or down, by a multiplier called the Energy Reliability Index (ERI). As defined in the "Standard Practices" manual of the CPUC (December 1986), "the ERI represents the expected average amount of kwh energy requirement that would go unserved in a particular year relative to the expected unserved energy the system would be expected to experience when operating at design reliability." Of course, with surplus capacity, there would be only a remote probability of unserved energy, so the ERI would be less than one.
In an earlier proceeding, PG&E proposed that the ERI multiplier was always to be equal to or less than one. Here, PG&E recognized that "because of the lead time required to construct a CT the ERI can exceed one during times when the utility is short of capacity" (p. 343).
The staff felt that "the full CT cost during times of excess capacity overvalues additional QF(9) capacity [and should be adjusted downward]" (p. 343). However, when capacity is short, it may take five years to build a gas turbine even on an emergency basis, if needed, and the ERI should be adjusted upward.
The Commission decided on an ERI limit of two - that is, a multiplier of two - that should apply for the first five years, with a limit of one after that (p. 346).
In contrast to its adoption of EPMC for revenue allocation in H. supra, the Commission in this decision gave only 5% weight to EPMC, assigning 95% weight to a System Average Percentage Change (SAPC) method to prevent "a significant, disproportionate increase in revenue allocation to the residential class relative to the system average increase" (p. 366). SAPC changes the revenue for a given class by the percent change in total system revenues.
With respect to payment to QF's, the Commission found that "T&D [transmission and distribution] costs are not avoided by utility purchases of QF power, and thus should not be included in payments to QF facilities" (p. 350).
On the larger issue of including customer costs in the marginal costs used for any purpose, the Commission said, "Since all uses of marginal costs ... are related to changes in demand or in utility-owned generation and not to changes in the numbers of customers, inclusion of marginal customer costs is not appropriate ... We reiterate that the use of marginal customer costs is conceptually inconsistent with current applications of marginal costs" (p. 353). [This exclusion of marginal customer costs is consistent with D, supra, but was reversed in L, infra.]
J. Anti-bypass Policy: Decisions 87-02-030, 87-05-071 and 88-03-088 (February 1987-March 1988) (Generic)
In a series of three interrelated decisions spanning the period from early 1987 to early 1988, the California PUC struggled to adjust its electric policies to changed conditions, important among which was the emerging threat of bypass.
We recognize that, with ... generating capacity well above target reserve margins, utilities [have] an opportunity to stimulate additional sales to some customers by offering a reduced rate for such incremental sales. By "incremental sales," we mean those additional sales that would not be made under existing tariff rates; the additional sales are made only because of the utility's ability to offer a discounted rate. (D.88-03-088, 3/9/88, p. 6)
The Commission concluded that "special contracts" - that is, contracts not conforming in price and other matters to the general tariff - could be issued by the "big three" California companies to customers with demands of 1000 kw or greater, with terms having the following elements (ibid, pp. 49-50):
A floor price consisting of an energy component, a transmission and distribution (T&D) component, and a generation component.
For contracts designed to deter proposed self-generation by the customer, the term of the contract is no longer than five years, commencing when the proposed self-generation facility would have begun generating. For contracts for incremental sales, the term of the contract is no longer than three years, starting when the incremental sales under the contract begin. The term of the contract may not extend into any period when forecasts indicate that additional capacity will be needed to meet target reserve margins.
The contract contains time-of-use [prices] that set a differential between on- and off-peak contract rate[s] for marginal consumption that is roughly the same as the differential between on- and off-peak rates in the otherwise applicable TOU [Time-of-use] tariff.
K. Application of ERI to Marginal Generation Capacity Costs: Decision 89-12-057, December 20, 1989 (PG&E)
In this decision, the Commission saw the ERI as a means to dampen the effect of utilizing the full annualized cost of a combustion turbine for revenue allocation and rate design under a situation of excess generating capacity.
The use of the ERI to reduce full turbine capacity cost was not new. It had been used for the limited purpose of reducing the capacity prices paid to QF's to reflect the value of the additional capacity supplied by QF's, which value is less ("but not nonexistent") when the utility has excess capacity. Also, the ERI had been applied in an earlier PG&E rate case (I., D.83-12-068, supra) for the purpose of revenue allocation and rate design, but this precedent was contested again in this proceeding.
The record was uncontested that the full annualized turbine cost was $55.69/kw-yr., which, when adjusted for franchise fees and uncollectibles, amounted to $56.17/kw-yr. Should this figure, which presumably represented a shortage cost, be used for rate making, or should it be reduced by the ERI mechanism to reflect the then-current existence of excess capacity?
The Commission's Division of Ratepayer Advocates (DRA) argued in favor of applying the cost-reducing ERI (p. 195):
The role of marginal cost in communicating underlying costs to customers is ... reduced during times of excess capacity....[E]conomic theory holds that customers will not pay more for a good or service than the value of that product to them. In times of excess capacity, the value of additional generation capacity is diminished, and prices should reflect that diminution in value....[I]n times of excess capacity, a utility may be able to add resources at less than the price of a combustion turbine. For example, it may be cheaper to return a retired plant to operation than to purchase a new combustion turbine.
DRA concluded than an ERI-adjusted marginal cost would "provide price stability and accurate long-term price signals" (p. 194).
The Commission decided that it was appropriate to apply an ERI adjustment. It chose a six year average ERI of 0.418, which, when applied to the generation capacity cost of $56.17/kw-yr., reduced the cost to $23.48/kw-yr. (pp. 201-202).
L. Alterations in Methodology: Decision 92-12-057, December 16, 1992 (PG&E)
Several issues were in contention.
(i) Marginal energy costs. Should a built-out or a barebones resource plan be followed as a basis for these costs? Adopted: built-out (pp. 241-241a).
A built-out resource plan "includes all potential supply and demand resource additions which are found to be costs effective ... including uncommitted DSM [Demand Side Management] programs." A barebones plan "excludes resources not yet committed to be built" (p. 241). The CPUC adopted built-out "because it more accurately represents how PG&E plans and operates a system" (p. 241 a).
(ii) Marginal generation capacity costs. Should a value of service (vos) methodology be substituted for the ERI-adjusted CT proxy? Adopted for PG&E: VOS. This adopted cost was $5.24/kw-yr. (But for QF pricing, a CT cost of $66.12/kw-yr. was established) (p. 246 and p. 249).
VOS originates with customer surveys from which average customer outage costs are determined on a dollar per kilowatt-hour basis. The end-result is a marginal generation capacity cost which is intended to equate probabilistic customer outage costs with the cost of additional capacity (p. 247).
(iii) Marginal transmission capacity costs. The Commission approved PG&E's proposal to split transmission costs into bulk and area components, since "bulk transmission expenditures are caused by system peak load, whereas area transmission expenditures are caused by peak load growth in a particular area" (p. 249 and 249-253).
(iv) Marginal primary distribution capacity costs. The Commission adopted PG&E's proposal to calculate these costs separately for each of its 13 operating divisions (p. 255).
(v) Method of estimating marginal transmission and distribution capacity costs. The method previously followed was termed "Regression/Real Economic Carrying Charge" (RECC). It uses a regression approach to estimate the marginal investment per kilowatt of peak demand and then amortizes (levelizes) this investment cost by multiplying by the RECC, yielding an annual dollar amount per kilowatt-year which is equivalent in real terms to the investment in dollars per kilowatt. Thus, it captures the full cost, rather than the deferral value, for each year of amortization.
PG&E proposed that the present worth (PW) method be substituted. The term "PW" is not used here in its usual sense. The Commission explained, "This method calculates the difference in total cost of meeting a change in load that begins next year instead of this year. This means that if there is a reduction in demand that postpones the need for the next investment, it will postpone the need for all future investments as long as demand is reduced" (p. 257). Moreover, "changes in load generally result in deferral of planned investments ... the value of this deferral is captured directly by the PW method" (p. 258).
The present worth method was adopted as "more economically efficient because it takes into consideration both supply and demand" (Findings of Fact No. 155, p. 292). The Commission found, "The present worth costing methodology is reasonable to use because it is the only method which estimates the opportunity cost of deferring transmission and distribution investments due to a change in load growth, taking into account both the timing and magnitude of such changes" (Findings of Fact No. 160, p. 292).
(vi) Marginal customer costs. The Commission adopted PG&E's recommendation that marginal customer costs be determined on a six-region basis, rather than staying on a system-average basis (p. 261). (This was a reversal of the Commission's earlier position, reported under D and I, supra, to exclude customer costs. The formal record does not contain an explanation for the change.)
(vii) EPMC Multiplier. The decision does not state the precise EPMC multiplier adopted to bring marginal cost revenues into balance with the revenue requirement. It says only that the revenue requirement "is approximately twice marginal cost revenues" (p. 263).
M. An Overview - The Maturity of the Theory: Decision 96-04-050, April 10, 1996 (SCE)
This decision presents a valuable overview of the Commission's ratemaking process. For this survey, however, we address only the marginal cost methodology as it had evolved and was reaffirmed by 1996. We quote in full, to preserve intact the Commission's careful language (p. 24):
Short-run (SRMC) vs. Long-run (LRMC or LRIC) Marginal Costs
We also reaffirm our policy of basing marginal costs for ratesetting purposes on short-term pricing signals. This approach is consistent with the ratesetting principles we have established in prior electric rate cases. It comports with economic theory as well as observed operations of competitive markets. Parties to our electric industry restructuring proceeding also propose to price generator services based on short-run market signals. None of the parties, including Edison, suggest that we unbundle and price these services based on long-ran marginal costs. Consumers and suppliers constantly interact on the basis of short-run price signals, and we believe that ratesetting should follow suit (p. 3).
Components of Marginal Costs/Definitions
Marginal energy cost, is the change in a utility's total operating costs which results from producing an additional kWh of electricity. Marginal energy costs vary over time and are therefore calculated on a time-differentiated basis by both time of day and by season.
The second component, marginal demand or capacity costs, measures the change in total costs caused by a kW change in demand. These costs are subdivided into three categories: generation, transmission, and distribution.
The third component, marginal customer-related costs, measures the change in total system costs required to hook up a new customer to a utility's distribution system and to maintain existing customers on the system. Customer-related costs include the capital costs of customer premises equipment (meters, transformers, service drops) and customer service and accounting expense.
For marginal generation costs, the Commission reaffirmed using the capital costs of a CT as a base, adjusted by the ERI, adopting for this proceeding a six-year average ERI of 0.85 (pp. 54-55).
For marginal customer costs, the Commission choose the "new customer only" (NCO) method over the "rental" method (pp. 62-63 and p. 69).
To bring marginal costs into equality with the revenue requirement, the Commission affirmed its use of the EPMC method, with rate caps when its results might be "unduly detrimental" to specific customer classes (p. 19). (In this proceeding, revenue requirements were greater than marginal costs on the order of 1.5 to 1, the reverse of the relationship in the early cases.)
N. The Abrupt Halt: Assembly Bill 1890, September 23, 1996 and Decision 97-03-017, March 7, 1997 (PG&E)
On September 23, 1996, Governor Wilson signed into law the California Legislature's Assembly Bill No. 1890 relative to the restructuring of the electric industry in California.
A key provision of this new law mandated that electric rates for all customers of regulated electric utilities be frozen at their June 10, 1996 levels, except for a rate reduction of no less than 10% for residential and small commercial customers from these June 10, 1996 levels. The rate freeze is to last "at least through the end of 2001" (p. 36).
As a major freeway accident may halt all traffic, AB 1890 halted any further applications of marginal costs to consumer rates. The influence of marginal costs embedded in the June 10, 1996 rates would be preserved intact, of course, but further progress toward marginal costs in both revenue allocations (EPMC) and rate designs was abruptly terminated.
In D.97-03-017 the Commission said (p. 40):
In view of AB 1890, we depart from the traditional Rate Case Plan expectations by not establishing new revenue allocations and rate design. We recognize that the rate freeze ordered by AB 1890 through the addition of Section 368(a) to the Public Utilities Code now precludes the January 1, 1997 or other rate changes we previously thought possible (p. 4).... [Therefore, marginal costs] are adopted only for the limited purposes of: (1) payments to qualifying facilities (through capacity allocation factors and the capacity value), (2) evaluation of demand-side management cost-effectiveness, and (3) price floors for discounted special contracts.
III. CALIFORNIA EPILOGUE(10)
In D.97-03-017, the Commission did not address the issue of the validity of the obsolete price signals that would be before the public, at least through 2001; nor did it mention the presumed loss of economic efficiency resulting from out-of-date prices over this period.
D.97-03-017 is the most recent CPUC decision that can be reviewed in this paper. Perhaps in subsequent decisions, or public statements, the Commission will explain its recurring prior emphasis on marginal cost price signals to induce economic efficiency in comparison to its apparent tendency to avoid facing the implications of abandoning this goal for rate purposes in the 1996-2002 interval.
1. California was not the first state to consider marginal costs. That distinction goes to the Wisconsin PUC. Its August 8, 1974 decision re Madison Gas and Electric Company is recognized as the first to hold that marginal costs, together with peak load pricing, were appropriate rate design considerations. The New York PUC was only five months behind California's March 16, 1976 adoption of marginal costs. The New York PUC's Opinion 76-15, of August 10, 1976, issued when Professor Kahn was chairman, held that marginal costs, as distinguished from average costs, are the most relevant costs for rote-setting and should be utilized to the greatest extent practicable. Other early states were Florida, North Carolina, and Connecticut.
2. The more detailed opinions of Professors Kahn and Hall, referred to under this subhead, have been abstracted (about 32 typed pages) and are available upon request. The writer thanks Professors Kahn and Hall for their review of these abstracts.
3. By this remark, Hall calls our attention to the wide variety of types, sizes and purposes of generating plants: conventional mainline plants serving base loads, intermediate loads, or peak loads, fired by oil, natural gas, coal or nuclear; smaller distributive generation installations; cogeneration facilities; and renewable-source plants powered by solar, wind, geothermal or biomass, in addition to hydro, which itself may be run-of-river, annual or cyclical storage, or pumped storage. His comment suggests the difficulty of reducing the all-encompassing category of "generating cost" for this widely-dispersed aggregation of generating facilities into a single marginal cost figure. In this respect, note the changes in the CPUC's attempts to simplify a "marginal cost for generation" applicable industry-wide as revealed in the History.
4. This paper was presented by the writer at the Western Economic Association International's 73rd Annual Conference, Lake Tahoe, Nev., June 28-July 2, 1998.
5. Page numbers for quotations for indicated decisions refer to the mimeo version of the decision, except for E., D.92749, where the page references are from 42 PUR 4th. Emphasis has been added to quotations in some instances, arid some text footnotes may not be shown.
6. This simplified statement does not apply to interruptible customers who have agreed to a lower quality of availability.
7. In the long-run, of course, all costs are variable.
8. Rates for smaller-use customers may consist of a single charge, where all costs are recovered on a per kilowatt-hour of usage basis, probably with a minimum; or the rate may be fashioned as a two-part rate, with a usage charge plus a customer charge.
9. Under the Public Utility Regulatory Policies Act of 1978, utilities are required to purchase electric energy and capacity provided by Qualifying Facilities (QF). QF's are cogenerators and small power producers. In its 1996 annual report to stockholders, PG&E estimated that QF deliveries accounted for about 19% of its 1996 electric energy requirements.
10. The foregoing history has surveyed only the development of marginal cost pricing for electric operations. The CPUC first addressed marginal cost pricing for natural gas in 1992. In a generic decision, D.92-12-058 of December 16, 1992, long-run marginal costs (LRMC) were adopted for gas, and were applied to PG&E in D.95-12-053 of December 20, 1995. The CPUC's adoption of long-run marginal costs for gas contrasts with its use of short-run marginal costs for electric (see F and M, supra.) This seeming contradiction is not explained in the formal record.
California Public Utilities Commission, Public Staff Division, Energy Rate Design and Economics Branch, "Standard Practices," December 1986.
Hall, Darwin C. Advances in the Economics of Environmental Resources: Volume 1, 1996, Marginal Cost Rate Design & Wholesale Water Markets, JAI Press, Inc., 1996.
Kahn, Alfred E., The Economics of Regulation, John Wiley & Sons, Inc., Vol. 1, 1970, Vol. 2, 1971.
State of California, Assembly Concurrent Resolution No. 192 - Relative to Electric Rates, August 31, 1974.
-----, 1995-96 Regular Session, Assembly Bill No. 1890 (Chapter 854, Statutes of 1996), signed by Governor Wilson on September 23, 1996.
California Public Utilities Commission, Decision No. 85559, "Opinion and Final Report to the Legislature pursuant to Assembly Concurrent Resolution No. 192, Adopted August 31, 1974," issued March 16, 1976.
-----, Decision No. 91107, "Application of Pacific Gas and Electric Company for authority, among other things, to increase its rates and charges for electric service.... for gas service," issued December 19, 1979.
-----, Decision No. 92549, "In the Matter of the Application of Southern California Edison Company for authority to increase rates charged by it for electric service," issued December 30, 1980.
-----, Decision No. 92749, OII No. 67, "Re-calculation of Marginal Costs of Electric Service," March 3, 1981 (42 PUR 4th, pp. 1-17).
-----, Decision 93887, "Application of Pacific Gas and Electric Company for authority, among other things, to increase its rates and charges for electric and gas service... for electric service... for gas service," issued December 30, 1981, for the test year 1982.
-----, Decision 82-12-055, "In the Matter of the Application of Southern California Edison Company for authority to increase rates charged by it for electric service," issued December 13, 1982, for the test year 1983.
-----, Decision 83-12-065, "In the Matter of the Application of San Diego Gas & Electric Company for authority to increase its rates and charges for electric, gas and steam service," issued December 20, 1983 for the test year 1984.
-----, Decision 83-12-068, "Application of Pacific Gas and Electric Company for authority, among other things, to increase its rates and charges for electric and gas service," issued December 22, 1983, for the 1984 test year.
-----, Decision 87-02-030, "Rulemaking Proceeding on the Commission's Own Motion to Revise Electric Utility Ratemaking Mechanisms in Response to Changing Conditions in the Electric Industry," issued February 11, 1987.
-----, Decision 87-05-071, "Rulemaking Proceeding on the Commission's Own Motion to Revise Electric Utility Ratemaking Mechanisms in Response to Changing Conditions in the Electric Industry," issued May 29, 1987.
-----, Decision 88-03-088, "Rulemaking Proceeding on the Commission's Own Motion to Revise Electric Utility Ratemaking Mechanisms in Response to Changing Conditions in the Electric Industry," issued March 9, 1988.
-----, Decision 89-12-057, "Application of Pacific Gas and Electric Company for authority among other things, to increase its rates and charges for electric and gas service," issued December 20, 1989, for the test year 1990.
-----, Decision 92-12-058, "Adoption of Long-run Marginal Cost (LRMC) Methodology for Gas Utilities," issued December 16, 1992.
-----, Decision 92-12-057, "Application of Pacific Gas and Electric Company for Authority, Among Other Things, To Increase Its Rates and Charges for Electric and Gas Service," issued December 16, 1992, for the test year 1993.
-----, Decision 95-12-053, "Revision in Marginal Cost Methodology for Gas," issued December 20, 1995 (PG&E).
-----, Decision 96-04-050, "In the Matters of the Application of Southern California Edison Company, A. 93-12-025... and Order Instituting Investigation [SCE] I. 94-02-002," issued April 10, 1996.
-----, Decision 97-03-017, "Application of Pacific Gas and Electric Company for Authority, Among Other things, to Decrease Its Rates and Charges for Electric and Gas Service, and Increase Rates and Charges for Pipeline Expansion Service," issued March 7, 1997.
AB: Assembly Bill ACR: Assembly Concurrent Resolution CPUC: California Public Utilities Commission CT: Combustion turbine EPD: Equal percentage of difference EPMC: Equal percentage of marginal cost ERI: Energy reliability index LRMC: Long-run marginal costs NCO: New customer method PG&E: Pacific Gas and Electric Company PW: Present worth QF: Qualifying Facility RECC: Real economic carrying charge SAPC: System average percentage change SCE: Southern California Edison Company SDG&E: San Diego Gas & Electric Company SRMC: Short-run marginal costs T&D: Transmission and distribution VOS: Value of service
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|Author:||Conkling, Roger L.|
|Publication:||Contemporary Economic Policy|
|Date:||Jan 1, 1999|
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