Opinion ID: 1526377
Heading Depth: 1
Heading Rank: 9

Heading: Residential Rate Design

Text: Establishing cost of service for rate design is a complex process. The methodology employed here by Central Maine, and adopted by the Commission as to this issue, entails three steps. All of Central Maine Power's costs are first designated according to their function, i. e., power supply, transmission, subtransmission or distribution. Each of these functionalized costs is then classified according to its demand, energy or customer components. Finally, all costs are allocated among the various customer classes by use of allocation factors, which are derived by various methods depending upon the function and classification of the cost. [54] In the proceeding below, as a complement to its decision to discard the existing declining block rate structure [55] and impose a flat energy rate, the Commission established a $5.70 monthly customer charge. The Consumer Coalition and the Natural Resources Council of Maine, intervenors below, challenge that action. Specifically, they dispute the classification of certain parts of the distribution system sometimes called the minimum or phantom distribution systemto customer costs. These costs, they argue, are properly classified to demand rather than customer costs, a revision which they contend would lower the monthly customer charge from $5.70 to $3.15. The Commission argues that while the intervenors' proposed designwhich seeks to track as closely as possible the marginal energy and demand costs of producing electricitymay have merit, it faced the different problem of producing an equitable rate structure once declining block rates had been abolished. Prior to the rate proceeding presented for review here, Central Maine Power charged each residential customer $3.40 per month for customer costs. This minimum bill included the right to use 25 kilowatt hours of energy at no additional charge. In its original filings, Central Maine proposed increasing that customer charge to $4.00 and providing no free energy at all. At the same time, the Company observed that while its actual customer cost was  considerably more per month, the difference would be recovered in the first energy blocks of their proposed declining block-rates. [56] When the Commission suggested the use of a flat energy rate, Central Maine Power witness Anderson stated that in that event the customer charge should be $5.68. The Commission ultimately found that if there ever was a cost justification for declining blocks, that justification no longer applies to residential customers, and, therefore,. . . the declining block structure should be eliminated from the residential class rate. [57] The Commission, therefore, determined to accept Central Maine's customer cost figure of $5.68, rounded to $5.70, as the residential customer charge to be assessed in connection with the new schedule employing flat energy rates. There is little dispute over the definition of what costs should be classified as a customer cost. The Company defines customer costs as . . . fixed costs which vary on a total company basis with the number of customers serviced and . . . not. . . with demand (KW) and energy (kwh) consumption. In addition, these costs have no time dimension at all. Or, as the Commission Decree paraphrases it, costs that vary with the number of customers in the rate class, regardless of the energy or demand use. The Consumer Coalition seeks to refine the definition somewhat by citing Professor James Bonbright to the effect that the customer charge should be composed only of those costs which are clearly allocable as such and which vary directly with the number of customers regardless of consumption. Bonbright, Principles of Public Utility Rates, 347-348 (1969). These nuances are of some significance to the intervenor's arguments. In any event, the major dispute focuses upon determining which costs meet this general definition and should thus be included in the customer charge. No party disputes inclusion of such items as meters and meter reading, billing and customer service costs. What is hotly contested is inclusion of a minimum distribution system , consisting, according to the Commission, of a minimum amount of poles and wires needed, on average, to connect a residential customer to the Company's distribution system. In its Decree the Commission quoted Professor Bonbright, supra, at some length as to the propriety of including the minimum distribution system costs in customer costs: But the really controversial aspect of customer-cost imputation arises because of the cost analyst's frequent practice of including, not just those costs that can be definitely earmarked as incurred for the benefit of specific customers but also a substantial fraction of the annual maintenance and capital costs of the secondary (low-voltage) distribution systema fraction equal to the estimated annual costs of a hypothetical system of minimum capacity. The minimum capacity is sometimes determined by the smallest sizes of conductors deemed adequate to maintain voltage and to keep from falling of their own weight. In any case, the annual costs of this phantom, minimum-sized distribution system are treated as customer costs and are deducted from the annual costs of the existing system, only the balance being included among those demand-related costs to be mentioned in the following section. Their inclusion among the customer costs is defended on the ground that, since they vary directly with the area of the distribution system (or else with the lengths of the distribution lines, depending on the type of distribution system), they therefore vary indirectly with the number of customers. What this last-named cost imputation overlooks, of course, is the very weak correllation between the area (or the mileage) of a distribution system and the number of customers served by this system. For it makes no allowance for the density factor (customers per linear mile or per square mile). Indeed, if the company's entire service area stays fixed, an increase in the number of customers does not necessarily betoken any increase whatever in the costs of a minimum-sized distribution system. While, for the reason just suggested, the inclusion of the costs of a minimum-sized distribution system among the customer-related costs seems to be clearly indefensible, its exclusion from the demand-related costs stands on much firmer ground. For this exclusion makes more plausible the assumption that the remaining cost of the secondary distribution system is a cost which varies continuously (and, perhaps, even more or less directly) with the maximum demand imposed on this system as measured by peak load. Bonbright, Principles of Public Utility Rates, supra, at 347-348 (1961). While recognizing the difficulties of properly allocating the minimum distribution system costs, the Commission found inclusion of such costs as customer costs to be the most reasonable solution, saying: We find that the most cost-related rate structure for the residential class is one that recovers the full customer cost in the customer charge and the demand and energy costs in a uniform charge for every kilowatt-hour consumer. We find that there is no justification for continuing to use a declining block rate structure for this class. We direct Central Maine to file a residential rate with a minimum customer charge of $5.70 and a flat energy charge designed to generate the necessary revenues for the residential class. Challenging this action, the Consumer Coalition points to the same passage by Professor Bonbright as authority for the proposition that these costs (of the minimum distribution system) are basically unallocable according to the usual standards, and hence must be allocated according to the policy goals the Commission seeks to attain. Instead of doing so, the Coalition charges, the Commission made the purely conclusory statement that allocation to customer costs is reasonable, while providing no supporting findings. Such action, it argues, is arbitrary and contrary to expressions of policy contained in the Commission's decrees and in state and federal legislation. The Natural Resources Council joins in this argument, and notes particularly that Professor Bonbright's conclusion that the lesser of two evils was to include the minimum distribution system costs in customer costs was made in the context of an electric industry with decreasing marginal costs, a situation which has since been reversed. Facing the same issue today, the Council urges, Bonbright would have supported allocating costs of the minimum distribution system to the energy charge, to help achieve marginal-cost based rates. The Commission, in the Council's view, eliminated the declining block structure because it discriminated in favor of electric space heating customers, then inexplicably perpetuated that discrimination by raising the customer charge. [58] By accepting Central Maine Power's cost-of-service study figure for actual customer charges, the Council says, the Commission erroneously assumed it would be left with actual energy charges and therefore appropriate price signals. In fact, they argue, the energy charge has been priced below the Company's incremental cost of providing service, thus moving away from cost-based rates. Now, the Council insists, the energy charge will be whatever revenue requirements dictate, irrespective of any relationship between that charge and the true incremental cost of providing service. Appropriate price signals do not result, since the customer charge affects only the choice whether to take service, and does not affect consumption patterns. A redesign of residential rates along the lines suggested by the Consumer Coalition and the Natural Resources Council is not without merit. The path chosen by the Commission is not without faults. According the Commission due deference in light of its legislative function and expertise, however, we find the result reached and the methodology used to be reasonable, and the rate design to be supported by substantial evidence. Mars Hill, supra, at 588. Marginal cost pricing, as a rate design methodology, attempts to reflect a utility's incremental (or decremental) cost of providing one more (or one less) unit of electricity at a given moment. Although in the fore-front of many contemporary reevaluations of electric rate structures, it is not without its difficulties, most notably that [t]here are enormous definitional problems in determining what is and what is not a marginal cost. A. C. Aman, Jr. & G. S. Howard, Natural Gas and Electric Utility Rate Reform: Taxation Through Ratemaking? 28 Hastings L.J. 1085, 1090 (1977). Before the Commission, marginal costs were defined variously as the cost of producing an additional unit of output and as the first derivative of average cost. Three different calculations of marginal costs, each showing substantially different results, were presented the Commission. It was reasonable for the Commission to decline to attempt implementation of marginal rates, given such difficulties. [59] Recovery of fixed customer costs, including those attributable to the minimum distribution system, through a $5.70 customer charge was also reasonable, and supported by substantial evidence. No party contests Central Maine's establishment of the $5.68 composite customer cost figure, nor disputes that some of that cost was once hidden in the declining block structure. As noted, the focus of dispute is upon proper classification of those costs, particularly those of the minimum distribution system. The Commission, having opted for a flat energy rate, faced the option of classifying such costs to the energy charge (raising the price per kilowatt hour) or segregating them in a distinct charge. The testimony of Mr. Anderson was that elimination of the customer charge and classification of those costs to energy would require an energy charge of 3.16 cents per kilowatt hour, while use of a $5.68 customer charge would allow the energy charge to be set a full 1 cent lower. Central Maine Power presented the following chart illustrating the cross-subsidization which would result from imbedding customer costs in the energy charge. REVENUE CUSTOMER COST EXCESS KWH Actual Recovered (Deficiency) 0 $5.68 $ 0 (5.68) 25 5.68 0.25 (5.43) 100 5.68 1.00 (4.68) 500 5.68 5.00 (0.68) 1000 5.68 10.00 4.32 2000 5.68 20.00 14.32 5000 5.68 50.00 44.32 10000 5.68 100.00 94.32 Obviously, high-use customers would be (unknowingly, in most cases) subsidizing low-use customers. While conservation of electricity is an undisputed goal, it cannot be the justification for discrimination of this sort. So, too, although flat rates for energy are perhaps less effective in encouraging conservation than some other methods might be, [60] they are reasonable when used in conjunction with a customer charge which properly assesses the cost of being tied to the electric service system. Substantial evidence supports the Commission classification of minimum distribution system costs to the customer charge. The NARUC Cost Allocation Manual [61] recognizes two methods of determining the customer cost component of distribution system plant: the minimum size and minimum intercept methods. Central Maine Power used the minimum size method, which entails classification of a minimum distribution system to customer costs. [62] Significantly, a Consumer Coalition witness conceded on cross-examination that his proposal to classify distribution plant cost to demand related cost was not recognized in the NARUC Manual, while use of the minimum size method was. The Commission was faced with the task of allocating what it termed basically unallocable costs. The testimony and evidence supporting classification of the minimum distribution system to customer costs was substantial. The NARUC Manual approves such a choice, and not the intervenors' alternative. Professor Bonbright criticized inclusion in customer costs, but rejected inclusion in demand costs with at least equal fervor. Though the costs of the minimum distribution system vary, at best, only indirectly with the number of customers served, they do not vary at all with demand or energy, leaving the Commission only a Hobson's choice with respect to the allocation of these costs. Facing this dilemma, the Commission was entitled to exercise reasonable discretion in selecting a methodology to account for these costs. Classifying them to the customer charge, in order to implement flat energy rates without exacerbating existing cross-subdization, was a reasonable exercise of that discretion. The use of averaging to produce a flat energy charge which will produce the necessary residential revenue requirement, while perhaps lacking in precision, is a reasonable technique producing a reasonable result. Adoption of the policy urged by the intervenors of classifying the costs of the minimum distribution system to the energy (demand) charge would be equally imperfect, and Commission discretion must, therefore, carry the day. New England Telephone, supra, at 59 (1978).
The Natural Resources Council of Maine, supported by testimony of its expert witness, Dr. Richard S. Bower, proposed to the Commission that two different residential rates be implemented: a higher one for the November through February heating season, and a lower one for the remainder of the year. The Commission rejected the proposed differential, and the Natural Resources Council appeals. Relying on a marginal cost analysis conducted for Central Maine Power by the National Energy Research Association (NERA), Doctor Bower concluded that the marginal cost of service varied by season, [63] and that a seasonally-differentiated rate was the proper method of reflecting that differential and producing cost-based rates. Doctor Bower's methodology for determining marginal costs per kilowatt-hour for each season was straight-forward. He adopted the NERA study's calculations as to the marginal demand-related unit costs, as to marginal energy costs, and as to allocation factors for each pricing period (November-February and March-October). Using information on residential load and total residential energy sales, Doctor Bower produced marginal costs per kilowatt-hour for each pricing period, from which in turn he developed his seasonally differentiated residential rates. [64] The Commission agreed that, on average, providing service is more costly during the winter months. It concluded, however, that it lacked sufficient information to establish seasonally differentiated rates which would be equitable in individual cases. The NERA study on which Doctor Bower relied did not attempt to break down the variations in marginal costs during the broad winter pricing period. Rather, it computed only average costs which are subject to considerable fluctuation depending upon the day of the week and the time of day. Consequently, although on average the costs of producing electricity during the heating season are higher, the Commission recognized that at many hours during that season the costs may actually be lower than during some hours of the non-heating season. Without this more detailed breakdown of costs, the Commission was concerned that the seasonal rate could be a shotgun approach, and declined to adopt it: We reject Dr. Bower's proposed seasonal rate because we find that there is a substantial likelihood that many customers would be penalized in excess of the costs they actually impose on the system. Rates that vary by season, in conjunction with rates that vary by time-of-day, may be the best way to reflect the actual cost of service. However, there are certainly many hours during the winter months which should properly be characterized as off-peak hours. Unless and until time-of-day rates are available for all customers, a seasonal rate would unfairly charge on-peak rates for a considerable amount of off-peak use. Given more information, the Commission now argues, seasonal rates might be an appropriate method of reflecting cost differences. However, it continues, on the state of the record here, the Commission acted within its discretion in refusing to implement a seasonal rate. The Natural Resources Council assails the Commission rationale, contending that the NERA study was far more comprehensive than the Commission admits, producing costs measured both seasonally and on an on-peak and off-peak daily basis, year round. Recognizing that it suffers from the limitation of being unable to precisely monitor the specific performance of specific customers as an ideal time-of-use rate structure would, the Council urges that the same limitation applies to the flat-rate structure adopted by the Commission, and that the Commission erred in not choosing the structure (i. e., seasonally differentiated) that would have minimized the discrimination the Commission found to be imposed on low and medium residential users in the form of a subsidy to heavy users. Even if, the Council says, the costs are only averages, they do vary seasonably, and the Commission itself has decreed that averages must sometimes be employed where greater precision is unattainable. Further, the principal rationale offered by Central Maine Power on this issuethat a lower summer rate could increase demand at that time, and interference with scheduled generator maintenancewas considered by NERA in producing its study, and the experience of the Central Vermont Company (an electric utility) with a seasonal differential produced no suggestion of maintenance difficulties. Finally, the Council points to, inter alia, the Maine Electric Rate Reform Act, 35 M.R.S.A. §§ 91 et seq. (1977) and the federal Public Utility Regulatory Policies Act of 1978 (PURPA), P.L. 95-617, 92 Stat. 3117 ( U.S.Code Cong. & Admin.News 1978, p. 7659) as establishing policies mandating implementation of such ratemaking techniques as seasonal differentials. The rejection of Doctor Bower's proposal, the Council concludes, was based on unsupported speculation as to its potential for error, and was arbitrary and capricious. Once more we are plunged into the thicket of the rate design briar patch. Once more we conclude that the Commission acted within its discretion, with a methodology and result that is reasonable and supported by substantial evidence. Initially we note that the resulta failure to adopt seasonally differentiated ratesderives some aura of reasonableness from the bare fact that a contrary decision would have been unprecedented. Seasonally differentiated rates have never been implemented in this jurisdiction, and one alleging that the failure to do so is in itself unreasonable shoulders not only the ordinary burden of the appellant but the weight of past practice. While tradition alone will not save unreasonable conduct, the unreasonableness of a historically accepted practice in the circumstances under consideration must be shown. See Central Maine Power Company v. Public Utilities Commission, supra, 382 A.2d 302 at 328, n. 39. Several witnesses testified as to the proper rate design; only Doctor Bower recommended a seasonal rate. Central Maine Power's Anderson rejected a seasonal differential on the basis of the necessity for summer maintenance noted above; we do not find the evidence on that facet of the issue conclusively supportive of either position, nor does it appear that the Commission necessarily assigned any significance to it. Doctor Wilson specifically rejected use of a seasonal differential for several reasons, including the relatively small winter-summer peak differential, the scheduled maintenance problem, and Central Maine Power's responsibilities as part of NEPOOL. In abbreviated form his testimony was that: On the Central Maine Power Company system, I've not made any seasonal differential. That's kind of unusual. Normally, in a situation like this I would recognize a seasonal differential. There are several reasons for not doing it. One, the winter peak and the summer peak tend to be pretty close together with each other. . . . . . Moreover . . . there's reason to believethat the excess capacity during the off peak periods and particularly during the spring and the fall is necessary for planned maintenance anyway . . . . there's not so much of that off peak time that it would appear obvious to me that an off peak rate ought to be charged. . . . . . Moreover, we've got another complication . . . [i. e.] whether or not the rates for the Central Maine system ought to reflect NEPOOL peaks and whether they ought to reflect peaks in Maine. . . . Well, as it turns out, other than the seasonal differential between CMP and NEPOOL the daily loads look pretty much the same. On a daily basis we don't have terribly much in the way of complication as to whether we ought to use CMP or NEPOOL. . . . . . [G] iven the fact that the summer peak is nearly as great as the winter peak, given the fact that the off peak periods are needed for system maintenance and given the fact that NEPOOL doesn't have the kind of winter peaks that the CMP systems has, I thought that the most directcertainly the least complex and perhaps the most accurate way of designing rates was to impose no seasonal differential at all. Doctor Bower referred on several occasions to the experience of Central Vermont Company under a seasonally differentiated rate. As Central Maine points out, however, Central Vermont's winter/summer peak differential has historically been much larger than Central Maine's and as of the 1977 test year was still slightly above Central Maine Power's. [65] The impact of a seasonal rate in leveling the differential could be expected to be far less in the case of Central Maine Power than in the Vermont experience; moreover, the perceived necessity for a leveling would be correspondingly reduced. The Commission's conclusion that the risks of a seasonal rate outweighed the prospective advantages is buttressed by these distinctions between the comparative problems and potential gains of the utilities involved. Perhaps the Commission would have considered the risks it foresaw in a seasonal rate worth undertaking had Central Maine's seasonal differential like Central Vermont's, hovered around 40 percent. We cannot so determine, but we can evaluate the shortcomings of evidence supporting a seasonal rate in determining whether the Commission's rejection of it was erroneous as a matter of law. The citation by the Council of state and federal legislation establishing policies variously urging and mandating consideration of more clearly cost-based rate designs and structures does not suggest unlawful Commission action. The Maine Electric Rate Reform Act specifically states that the Commission is authorized to implement experimental or other reforms as [it] may determine is appropriate, 35 M.R.S.A. § 94. Similarly, the Public Utility Regulatory Policies Act requires state regulatory commissions to consider such standards as seasonal rates, and determine whether or not it is appropriate to implement such [a] standard . . . § 111(a); See also H. Conf. Rep. No. 95-1750. The Act, as the Council concedes, was not signed into law until nearly a month after the Commission's Decree in this case, and allows commissions three years to consider the implementation of the standards set forth therein. § 111(b). The question, the Council says in its reply brief, is not whether the Commission has violated any specific directive of PURPA, but whether it violated its policy in declining to adopt seasonal rates. On the basis of this record, we cannot find such a violation. The Commission made its decision after hearing conflicting evidence as to the propriety of seasonal rates. In choosing the more conservative path of declining to adopt seasonal rates without further assurances of precision in tracking actual costs, it was faithful to its obligation to make no findings without substantial evidence. We deny the appeal of the Natural Resources Council of Maine as to this issue. The entries are: 1. As to Central Maine Power Company: Section 303 appeal denied in part and sustained in part. Section 305 complaint granted in part and denied in part. Judgment for defendant on Section 305 complaint as respects the capital structure issue, for plaintiff as respects remaining issues. Appeal from Superior Court denied as moot. 2. As to Intervenors St. Regis Paper Company, Consumer Action Coalition, and Natural Resources Council of Maine, et al.: Section 303 appeals denied. Remanded to the Public Utilities Commission for further proceedings consistent with this opinion. McKUSICK, C. J., and DELAHANTY, J., did not sit. WERNICK, ARCHIBALD, GODFREY and NICHOLS, JJ., concurring.