State ex rel. Utilities Commission v. North Carolina Electric Membership Corp.

412 S.E.2d 166, 105 N.C. App. 136, 1992 N.C. App. LEXIS 28

• Court: Court of Appeals of North Carolina
• Decided: January 21, 1992
• Docket: No. 9010UC1166
• Status: Published

Opinion

WYNN, Judge.

In 1975, the North Carolina General Assembly enacted G.S. 62-110.1(c) (1989), which directed the North Carolina Utilities Commission (the “Commission”) to “develop, publicize, and keep current an analysis of the long-range needs for expansion of facilities for the generation of electricity in North Carolina, including its estimate of the probable future growth of the use of electricity, the probable needed generating reserves, the extent, size, mix and general location of generating plants and arrangements for pooling power . . . .” 1975 N.C. Sess. Laws ch. 780, § 1. In the course of making this analysis and developing a plan, the Commission must confer and consult with the public utilities in North Carolina, conduct public hearings, and ultimately submit a report of its analysis and plan to the Governor and to appropriate committees of the General Assembly.

The parties are in general agreement that prior to 1987, the Commission’s and the utilities’ general practice was to focus strictly on “supply-side” considerations in analyzing the long-range needs for electricity in North Carolina. Supply-side considerations relate to increasing the supply of power available to a given utility, either by building new electricity generating units or by purchasing power from other utilities. In June 1987, however, the General Assembly enacted legislation amending N.C. Gen. Stat. 62-2 (The Public Utilities Act’s “Declaration of Policy”) by adding a new subsection (3a). See 1987 N.C. Sess. Laws, ch. 354, § 1. The policy of the State of North Carolina follows:

To assure that resources necessary to meet future growth through the provision of adequate, reliable utility service include use of the entire spectrum of demand-side options, including but not limited to conservation, load management and efficiency programs, as additional sources of energy supply and/or energy demand reductions. To that end, to require energy planning and fixing of rates in a manner to result in the least cost mix of generation and demand-reduction measures which is achievable, including consideration of appropriate rewards to utilities for efficiency and conservation which decrease utility bills.

N.C. Gen. Stat. § 62-2(3a) (1989).

The parties are also in general agreement that the practical effect of. adding subsection (3a) to G.S. 62-2 was to codify both the Commission’s and the utilities’ growing tendency to take “demand-side” considerations into account when complying with the directives of section 62-110.1(c). Demand-side considerations focus on the consumer’s need for electricity, as well as ways to reduce that need. In response to the newly-enacted section 62-2(3a) and following several months of meetings and discussions, the Commission issued an Order on 8 December 1988 adopting Commission Rules R8-56 through R8-61 which set forth the process by which the Commission would comply with the new mandate. This process is known as “least cost integrated resource planning.”

Also on 8 December 1988, the Commission issued an Order stating the following: “Integrated resource planning is a strategy which considers conservation, load management and other demand-side programs along with new generating plants, cogeneration and other supply-side options in providing cost-effective, high quality electric service.” The Order required the utility companies subject to its Rules to file their least-cost integrated resource plans (“LCIRPs”) with the Commission, and scheduled hearings in six different cities to analyze and investigate each utility’s plan. Each plan filed was required to contain energy and peak load forecasts for at least fifteen years; an integrated resource plan giving due consideration to existing and new generating facilities, alternative energy resources, conservation and load management programs, purchased power, and transmission and distribution facilities; and a short-term action plan. Appellees Duke Power Company (“Duke”) and Carolina Power and Light (“CP&L”) were among the electric utility companies which filed LCIRPs with the Commission.

Pursuant to the Commission’s invitation to all interested parties, the North Carolina Electric Membership Corporation (“NCEMC”) petitioned to intervene and be heard during the hearings. NCEMC is comprised of twenty-seven electric distribution cooperatives which provide retail electric service to many areas of North Carolina. It also co-owns the Catawba Nuclear Station with Duke Power Company and the Saluda River Electric Cooperative. In its motion, NCEMC alleged that the “[identification and utilization of least cost resource planning [was] critical to [its] successful operation.” By Order dated 25 September 1989, NCEMC was allowed to intervene. Thereafter, NCEMC filed the testimony of three witnesses for the Commission’s consideration.

On 12 December 1989, appellees Duke and CP&L filed separate motions to strike the testimony of each of the witnesses proffered by NCEMC. After considering the motions, the Commission decided to defer its consideration of two of the three witnesses’ testimony until a later time. Thereafter, the matter came on for hearing on 9 January 1990. Following the hearing, the Commission issued an Order on 17 May 1990, stating the following finding of fact: “7. The Least Cost Integrated Resource Plans (LCIRP) filed by CP&L, Duke, and North Carolina Power are reasonable for the purposes of this proceeding. The Commission recognizes that LCIRP is an evolving, dynamic process, and that new information and new understanding of resource planning principles will be developed in the near future. The LCIRPs filed herein are at an early stage in their evolution, and these plans should be recognized as a good faith attempt to achieve an appropriate generation mix at least cost consistent with reliable service.” NCEMC now appeals the Commission’s 17 May 1990 final order.

■ I.

In its first assignment of error, NCEMC contends that the Commission erred in granting its “unqualified approval” of the LCRIPs submitted by Duke and CP&L. In this regard, NCEMC asserts that since the Commission deferred consideration of the testimony of two of NCEMC’s witnesses, the substance of which NCEMC contends tended to show that the plans filed by Duke and CP&L were not least-cost, the better course of action for the Commission would have been to either reserve its judgment or, at most, lend its “conditional approval” of the Duke and CP&L plans.

Although NCEMC assigns error only to the Commission’s entry of an “unconditional” final order and not to its decision to defer consideration of the testimony, it nonetheless would be helpful to an understanding of NCEMC’s position to set forth the substance of those witnesses’ testimony.

At the hearing, NCEMC presented to the Commission deposition-like testimony elicited from Dr. Richard Bower, an economist and former member of the New York Public Service Commission, and Anis Sherali, a power supply engineer.

Dr. Bower’s testimony focused on one important aspect of CP&L’s supply-side plan: CP&L’s announced intention to purchase 400 MW of generating capacity from Duke between 1992 and 1997, under a contract referred to as the “Schedule J” transaction. Bower analyzed the economics of the Schedule J transaction and concluded that it did not make good economical sense. It was his testimony that CP&L could meet its generation needs more economically if it were to facilitate a program whereby NCEMC could transfer excess power being generated through NCEMC’s Catawba Nuclear Station entitlement to CP&L. The rationale underlying Bower’s testimony is that seventeen of NCEMC’s member cooperatives are located in areas controlled by CP&L, and those cooperatives receive their power requirements from NCEMC, which in turn receives its power supply through wholesale contracts with CP&L; CP&L, therefore, could meet its increased need for generating capacity more economically through a transfer of NCEMC’s excess power from Catawba to the CP&L area. CP&L has refused to agree to such a transfer. In sum, the Bower testimony was proffered to indicate that the CP&L and Duke plans were not “least-cost.”

Sherali’s testimony was similar to that elicited from Bower; however, Sherali used a different method of analysis. Sherali testified that even if NCEMC were not allowed to transfer generating capacity from Catawba, the Schedule J transaction nonetheless would impose unnecessary costs upon CP&L ratepayers.

For the reasons which follow, we are of the opinion that the Commission correctly handled these proceedings. First, the Commission did not, as NCEMC contends, grant “unqualified approval” of the Duke and CP&L LCIRPs; rather, the Commission found as fact in its 17 May 1990 order only that the Duke and CP&L plans were “reasonable for the purposes of [the] proceeding” before it. That is to say, the plans submitted by Duke and CP&L were reasonable for the purpose of “analysing] . . . the long-range needs for expansion of facilities for the generation of electricity in North Carolina . . . .” See N.C. Gen. Stat. § 62-110.1(c). Moreover, in response to concerns expressed in a motion filed by the Utilities Commission Public Staff that the Commission’s 17 May 1990 order might be construed as “adopting” Duke’s, CP&L’s and other companies’ LCIRPs, the Commission expressly reiterated that the 17 May 1990 order merely found the power companies’ LCIRPs reasonable for the purposes outlined in G.S. 62-110.1(c); the Commission also expressly made it clear that the LCIRP proceedings were not meant to serve as a substitute for certification proceedings pursuant to G.S. 62-110 or 62-110.1(a).

Second, in its pre-hearing order deferring consideration of Bower’s and Sherali’s testimony, the Commission stated that it would consider the testimony after the Federal Energy Regulatory Commission (“FERC”) had reached a decision in a case in which the testimony of both Bower and Sherali was used. In addition to their assertions that the Schedule J transaction did not promote a least-cost objective, Bower and Sherali also contended that the Schedule J transaction would tend to suppress competition between CP&L and NCEMC’s member cooperatives, and that CP&L had entered into the transaction in bad faith and in violation of federal antitrust laws. Duke and CP&L based their motions to strike Bower’s and Sherali’s testimony on the ground that the same issues presented by their testimony in the instant case were before FERC in a proceeding which was already underway. We agree with the appellees that the testimony of Bower and Sherali raises issues which are more appropriately directed to the attention of the Federal Energy Regulatory Commission. The Federal Power Act, 16 U.S.C. §§ 791a to 828c, authorizes FERC to regulate interstate wholesale electric power transactions. More importantly, FERC’s authority over these transactions is exclusive and is not shared with state regulatory agencies. Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 90 L.Ed.2d 943 (1986). Under 16 U.S.C. § 824d, a utility may not enter into a wholesale power transaction unless FERC has approved the rates and found them to be just and reasonable. As such, Duke and CP&L have submitted the Schedule J transaction for the FERC’s approval. Since one of the factors which FERC considers in determining what is just and reasonable is whether the proposed transaction will have anti-competitive effects or will violate antitrust laws, Federal Power Comm’n v. Conway Corp., 426 U.S. 271, 48 L.Ed.2d 626 (1976); Gulf States Utilities Co. v. Federal Power Comm’n, 411 U.S. 747, 36 L.Ed.2d 635, reh’g denied, 412 U.S. 944, 37 L.Ed.2d 405 (1973), and since NCEMC was allowed to intervene and submit the Bower and Sherali testimony in the proceedings for FERC’s approval of the Schedule J transaction, NCEMC’s concerns about the Schedule J transaction are being addressed adequately and appropriately in the proceedings which are currently before FERC. Moreover, since the Commission has expressly left the Bower and Sherali testimony open for consideration, we must conclude that NCEMC has suffered no prejudice by virtue of the Commission’s decision finding Duke’s and CP&L’s LCIRPs reasonable.

II.

NCEMC next contends that the Commission erred in refusing to order CP&L to supply NCEMC with CP&L’s “real-time” demand signal. A “real-time system signal” is an electronic signal which, when used with the proper equipment, provides a continuous indication of the total demand on a given utility’s system. Although it is unclear from the record, it is presumably those service areas in which NCEMC’s member cooperatives are located, but which are controlled by CP&L, to which NCEMC wishes the signal to be sent. According to NCEMC, it is the real-time system demand signal which allows utilities like CP&L to implement one of the most effective demand-side management techniques: shutting down or curtailing certain categories of use (e.g. domestic hot water heaters) during periods of peak demand. NCEMC asserts that, in order for such a program to operate efficiently, a utility must have accurate information from moment to moment regarding the level of demand on its system, and that the real-time system demand signal provides this information. NCEMC argues that since CP&L refuses to provide NCEMC with its signal, NCEMC is forced to speculate as to the precise time and length of the periods of peak demand on CP&L’s system and that, as a result, voluntary participation on the part of NCEMC’s member cooperatives’ retail customers in programs designed to disrupt service during peak periods of demand is discouraged because the cooperatives inevitably disrupt the service for periods which are longer than necessary. It is NCEMC’s position that in declining to order CP&L to make its signal available to NCEMC, the Commission “was heedless of its statutory mandate to promote ‘the least-cost mix of generation and demand-reduction measures which is achievable ....’” We disagree.

Although the issue of CP&L’s providing its real-time system demand signal to NCEMC arguably bears some relevance to the effectiveness of CP&L’s LCIRP, this Court is of the opinion that the newly-designed least-cost integrated resource planning proceeding was not intended to provide an occasion for the issuance of mandatory orders requiring substantive changes in a given utility’s operations.

General Statutes section 62-110.1(c) makes it clear that the only purpose of a least-cost planning proceeding is to assist the Utilities Commission in “developing], publicizing], and keeping] current an analysis of the long-range needs for expansion of facilities for the generation of electricity in North Carolina.” Nowhere is it suggested in section 62-110.1(c) that the purpose of the proceeding is to issue directives which fundamentally alter a given utility’s operations. Rather, we believe that the least-cost planning proceeding should bear a much closer resemblance to a legislative hearing, wherein a legislative committee gathers facts and opinions so that informed decisions may be made at a later time. Indeed, the very language of section 62-110.1(c), which requires the Commission to consider the analysis which results from the least-cost proceeding when acting upon a petition for the construction of a facility for the generation of electricity, appears to support this inference. In the instant case, however, no such petition was before the Commission and, therefore, the Commission was neither required nor even authorized, in the context of the proceedings in question, to issue the order which NCEMC sought.

If an intervenor desires the Commission to issue a mandatory order which will require a utility to take or to refrain from taking some specific substantive action, it may file a complaint pursuant to G.S. 62-73, which provides in relevant part as follows:

Complaints may be made by the Commission on its own motion or by any person having an interest ... by petition or complaint in writing setting forth any act or thing done or omitted to be done by any public utility ... in violation of any provision of law or of any order or rule of the Commission, or that any rate, service, classification, rule, regulation or practice is unjust and unreasonable.

N.C. Gen. Stat. § 62-73 (1989). By mentioning this alternative method of bringing concerns before the Commission, however, we do not mean to suggest that the issue of the real-time system demand signal is appropriately addressed to the Utilities Commission. We only mention section 62-73 to emphasize the point that the least-cost planning proceeding is not the appropriate occasion for the issuance of mandatory orders.

In the instant case, the Utilities Commission correctly recognized that the issue should be raised before FERC. As previously mentioned, exclusive jurisdiction over interstate wholesale electric power transactions is conferred upon FERC. NCEMC does not dispute FERC’s authority to regulate the wholesale power transactions between it and CP&L. We shall, therefore, proceed under the assumption that NCEMC concedes this point. If the Commission were to order CP&L to provide its real-time system demand signal to NCEMC, issues which were within the exclusive province of FERC would be affected.

In this regard, CP&L contends, and NCEMC does not dispute, that an order requiring CP&L to provide its real-time system demand signal to NCEMC would implicate, at least to some extent, the wholesale rate at which CP&L sells NCEMC’s member cooperatives electric energy. CP&L contends that this is because providing NCEMC with its real-time system demand signal would change “a fundamental assumption” upon which the wholesale rate tariffs (which CP&L charges NCEMC’s member cooperatives) are based: that NCEMC and its member cooperatives would not have access to the real-time demand signal.

According to CP&L, the monthly bills which it charges against NCEMC’s member cooperatives in the CP&L area include both an energy component and a demand component. The energy component is based on a cooperative’s total electric usage, as measured in kilowatthours, for the month, while the demand component is based primarily on the cooperative’s demand, as measured in kilowatts (kW), during a one-hour period when CP&L’s system demand reaches its peak for the month. CP&L further contends, and NCEMC does not dispute, that if NCEMC’s cooperatives have access to CP&L’s real-time system demand signal, then, by carefully observing fluctuations in system demand, the cooperatives could determine with considerable accuracy when the system reaches its monthly peak. With this information in hand, the cooperative could reduce its own demand during the period of peak demand, either by implementing a wide-scale demand reduction program such as that mentioned previously, or by purchasing a generator for use during the period of peak demand. In this way, CP&L argues, NCEMC’s member cooperatives can create artificially low indications of their peak-hour demand, and thereby reduce the demand component of their monthly bills.

While CP&L does not dispute that reducing peak-hour demand is a good idea, it does dispute that the manner in which this could be accomplished, were it to provide NCEMC with the real-time system signal, is fair. It is CP&L’s position that, since its plants and facilities are constructed on the basis of its need for power over a broader period of time than the one-hour period of peak demand, the reduction of a cooperative’s load for only one hour would have little or no effect on the cost of CP&L’s system. As such, CP&L argues that, if it is ordered to supply NCEMC with the signal without a corresponding adjustment to the rate at which NCEMC and its member cooperatives are charged, the costs involved in meeting the expenses of expansion will be shifted to either CP&L’s retail customers or to CP&L’s shareholders.

Regardless of the merits of CP&L’s argument, it is obvious that the issuance of an order requiring CP&L to provide NCEMC with its real-time system demand signal would have some impact upon the fairness of the wholesale rates at which NCEMC’s member cooperatives are sold electricity. For this reason, we are of the opinion that such an issue more appropriately is addressed to FERC. Accordingly, we conclude that the Utilities Commission properly refused to order CP&L to provide NCEMC with its real-time system demand signal. NCEMC’s assignment of error on this point, therefore, is overruled.

III.

In its final assignment of error, NCEMC contends that the Commission exceeded its statutory authority when, in its 17 May 1990 order, it announced its intention to require NCEMC “to participate in all future least-cost integrated resource planning proceedings” once a rulemaking proceeding for that purpose could be held. Unless and until the Commission actually institutes a rulemaking proceeding which results in such a requirement, we can discern no justiciable issue or genuine controversy between the parties. As such, the issue is not ripe for our determination and we decline to address it.

IV.

For the reasons discussed above, the order of the Utilities Commission is,

Affirmed.

Judges COZORT and ORR concur.