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07/09/82 the Second Taxing District v. Federal Energy Regulatory

July 9, 1982

TOWN OF WALLINGFORD, CONNECTICUT, PETITIONERS

v.

FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT, CONNECTICUT LIGHT AND POWER CO., INTERVENOR 1982.CDC.176



UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT

THE SECOND TAXING DISTRICT of the CITY of NORWALK, the

THIRD TAXING DISTRICT of the CITY of NORWALK, and the

Petition for Review of an Order of the Federal Energy Regulatory Commission.

APPELLATE PANEL:

Mikva and Ginsburg, Circuit Judges, and Cowen,* Senior Judge, United States Court of Claims. Opinion for the court filed by Circuit Judge Mikva.

DECISION OF THE COURT DELIVERED BY THE HONORABLE JUDGE MIKVA

In this case, municipal customers of Connecticut Light and Power Company ("Connecticut Light" or "Company") challenge a decision of the Federal Energy Regulatory Commission ("FERC" or "Commission") to approve in major part a rate design submitted by Connecticut Light. The municipalities are members of the Connecticut Municipal Electric & Gas Association ; they include the Third Taxing District of Norwalk, a customer drawing its full power requirements from Connecticut Light, and the Second Taxing District of Norwalk and the Town of Wallingford, both customers who receive only a portion of their power requirements from the Company. The CMEGA members are understandably interested in paying low rates for their service from Connecticut Light, and in being able to shift to even cheaper sources of wholesale power when possible. The Company, which has large amounts of underutilized generating capacity, is just as understandably concerned to ensure that the municipalities bear their fair share of the costs of the facilities on which they rely for their power.

This proceeding is the fourth in a series of efforts by Connecticut Light to tailor rates to costs of service by the use of a rate design that charges rates for power based on whether it was consumed at periods of highest demand on the system. CMEGA objects specifically to the method used by the Company to calculate rates charged partial requirements customers for the costs borne by the Company in maintaining the capacity to serve their power demands. CMEGA contends that approval of the rate design is a sharp departure from FERC's treatment of the full requirements customers in this case, FERC's treatment of previous rate designs by Connecticut Light, and FERC policy on rate design more generally. CMEGA also challenges FERC's refusal to order a refund for the full requirements customers, who were not made subject to some features of the rate design applied to the partial requirements customers. Finding substantial record support for FERC's decision on the rate design, we affirm. I. THE CHALLENGED RATE DESIGN and ITS HISTORY

The general aim of rate design is to enable a utility to recover allowable revenues by charging customers utility rates that reflect the costs of providing service. As is standard, Connecticut Light began the process of determining the rate to be charged its wholesale municipal customers by distinguishing between "demand costs" and "energy costs." *fn1 "Demand costs" reflect the costs to the Company of maintaining the facilities needed to meet its customers' requirements. "Energy costs" are the costs incurred in running the facilities to generate each unit of power actually produced. Individual customers' bills are the sum of a demand charge, calculated to reflect the customer's share of demand costs, and an energy charge, calculated to reflect the costs of producing the power used by the customer.

In the rate design at issue here, Connecticut Light figured demand charges in two stages. First, the Company allocated total demand costs among customer classes by utilizing the 12-month coincident peak (12-CP) method. Under this method, demand costs are allocated by taking the hour of highest total usage (the coincident peak) during each of the preceding twelve months, determining the percentage of peak usage drawn by each customer class during each of the twelve months, and averaging the resulting percentages for each customer class. For example, if a customer class such as the CMEGA municipalities was responsible for 30% of usage at coincident peak during the three summer and three winter months, and 20% of usage at coincident peak during the remaining six months, the class would be allocated 25% of demand costs. Because a public utility is expected to maintain the capacity to meet its customers' needs, a customer class's highest "contribution" to coincident peak will reflect the added costs incurred by the utility in maintaining the capacity to meet the needs of that class, at least, if usage by other customer classes remains constant. For example, if municipal wholesale customers draw a higher percentage of power used at coincident peak during the summer months because of the heavy use of residential air-conditioning, and if other users draw relatively steady amounts of power throughout the year, the municipalities' contribution to coincident peak during the summer represents the increased costs incurred by the Company in meeting their demands. Because it averages monthly contributions to coincident peak for an entire year, therefore, the 12-CP method best reflects real costs imposed on the system by customer classes when the classes tend to use fairly steady amounts of power throughout the year. It least reflects actual costs when a customer class imposes particularly heavy seasonal demands, as in the air-conditioning example. *fn2

Once demand costs were allocated to customer classes, the Company then computed the portion of the class's allocation to be borne by each class member. In the rate design at issue here, Connecticut Light calculated individual demand charges on the basis of a stratified rate, applied to the customer's "billing demand": the maximum clock hour of kilowatt demand supplied by the Company to the customer during the previous twelve months. The rate was "stratified" in that the customer's billing demand was subdivided into two tiers: usage at "peak" and at "off-peak" hours. The Company charged a higher demand charge for usage during periods of off-peak demand, and a lower demand charge for peak use, because the newer nuclear plant used to supply off-peak capacity is the more expensive portion of the Company's capital facilities. The Company's method of billing a demand charge based on the customer's full amount of highest demand during the past twelve months is called a "twelve-month, 100% billing demand ratchet." The "ratchet" effect is that a customer which in one month imposes high demands on the Company, for whatever reason, will not slip back to paying demand costs based on a lower amount of usage until twelve months have passed, no matter how severely the customer curtails energy use. *fn3

In addition to the demand charge, the rate at issue here imposed an energy charge on Company customers. The charge was based on the number of kilowatt hours actually drawn by the customer from Connecticut Light each month. Like the demand charge, the proposed energy charge was stratified, but with a higher rate charged for usage during peak periods and a lower rate charged for off-peak usage. This stratification too was designed to track costs of service, because the Company must employ less fuel-efficient plant to generate the larger amounts of power consumed at periods of peak usage.

The rate design at issue here, R-4, *fn4 was the fourth in a series of stratified rates submitted by Connecticut Light to the Commission. Although the stratified rates were intended to tailor wholesale rates *fn5 more closely to the costs of providing service, they initially met with little success before the Commission. The first, R-1, filed in 1972, proposed a rate stratified into four levels, with different portions of a customer's load assigned to the different strata but without a distinction between demand and energy charges. R-1 imposed the highest charges on partial requirements customers, by assigning initial portions of their use to the level at which the charge was highest, and employed a 100% ratchet based on the customer's total demands for power, from whatever source. While noting that "the concept of tailoring rates to the service provided is worthy in the abstract," the Commission rejected the stratification proposed in R-1 because the method by which it had been developed had not been shown to track actual costs of service. The Connecticut Light & Power Co., Opinion No. 761, 55 F.P.C. 1986, 1999 (1976). The Commission also rejected the total demand ratchet in the form proposed. The Company had defended including a customer's total demands for power -- including power generated by the customer itself -- in the ratchet by arguing that it needed to maintain system capacity to meet its wholesale customers' entire potential demand, in case of outages by alternate suppliers at times of peak demand. The Commission, however, found that the ratchet in this form imposed a burden on customers wholly beyond the actual costs of serving them. Id. at 1996. *fn6

The R-1 proceedings, initiated in 1972, were not completed until 1976. In 1974, after the initial decision by the ALJ had rejected the stratified rate proposed in R-1, Connecticut Light filed the second rate in the series, R-2, which also proposed a stratified rate coupled with a demand ratchet. R-2, however, was importantly different from R-1. The R-2 rate was subdivided into a demand charge and an energy charge, each in turn stratified into only two tiers, with one charge for peak usage and the other for off-peak usage. The ratchet in R-2 was based solely on the highest amount of power actually drawn by the customer from Connecticut Light during the preceding twelve months, not on the customer's total power demand, however supplied. In December, 1975, R-2 was superseded by Connecticut Light's filing of R-3, a stratified rate similar in structure to R-2. See The Connecticut Light and Power Co., Docket No. ER76-320, Initial Decision (Oct. 16, 1978). R-2 was eventually settled during the R-3 proceedings.

In the R-3 proceeding, both the stratified rate and the demand ratchet were rejected. The ALJ rejected the stratification as proposed because he found that the Company had not made an adequate showing of how the proposed rate differentials tracked actual costs of service. *fn7 He rejected the proposed 100% ratchet in favor of an 80% ratchet because of concern that it might result in overcollections when combined with the 12-CP method of allocating demand among customer classes. *fn8 FERC affirmed without comment. The Connecticut Light & Power Co., Opinion No. 103, 13 FERC para. 61,155 (1980).

R-4, the proceeding at issue here, intermeshed with the proceeding in R-3. R-4, filed July 31, 1978, incorporated the same two-tier stratification structure and 100% billing demand ratchet as R-3 and R-2. The only differences between R-3 and R-4 of importance here concern the dividing line between power use classified as "peak" and "off-peak" and the amount of reserve capacity postulated for the purposes of calculating the actual peak and off-peak demand charge rates. The ALJ issued his initial decision in R-4 in September, 1980, some two months before FERC's final order in R-3. In R-4, however, the ALJ approved the stratified rate design, finding that the Company had shown that the design matched costs of service with charges for service in a technically accurate manner. Connecticut Light & Power Co., Initial Decision, No. ER78-517 (Sept. 9, 1980); Joint Appendix 642. The ALJ rejected the 100% ratchet for wholesale customers drawing all of their power from Connecticut Light, because he found that the Company had not made the showing requisite to override the ratchet's potential for unfairness. Id. at 668. The ALJ did not however, consider the application of the ratchet to partial requirements customers, because he concluded that the issue had not been raised. Id. at 672 n.37. FERC affirmed, but on the ground that application of the ratchet to partial requirements customers was justified by their ability to utilize alternate power sources in order to limit their peak demand from Connecticut Light. The Connecticut Light & Power Co., Opinion No. 114 (Feb. 19, 1981), J.A. 834. On all other issues, FERC adopted the reasoning of the ALJ.

The CMEGA municipalities petitioned for rehearing and Connecticut Light petitioned for clarification of whether the order was to have prospective effect only. FERC denied rehearing but in clarification stipulated that the rate was to be prospective only. The Connecticut Light & Power Co., Opinion No. 114-A (April 20, 1981), J.A. 872. The result was that the partial requirements customers remain subject to the stratified rate and 100% demand ratchet; the full requirements customers are not subject to the demand ratchet after February 19, 1981, but do not receive refunds for amounts they ...


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