dates the agreements expired by their own terms. Notice of the filing was published in the Federal Register,3 with comments, protests, and interventions due on or before January 16, 1991. No comments or interventions were filed. On February 8, 1991, PSNH filed a letter supporting Central Vermont's filing, and urging the Commission to accept the filing. Discussion Central Vermont's support for its rates includes the following traditional cost treatment: (1) a 100-percent contribution to the fixed costs of the generating units providing the services at issue; (2) an amount intended to reflect the cost of Central Vermont's transmission system in those instances where the generating unit involved is not on Central Vermont's system; and (3) any third-party transmission charges that Central Vermont incurs in providing the services at issue. However, such cost data alone do not cost-justify the rates Central Vermont has charged for the services at issue. Accordingly, unable to justify its rates based solely on the costs of the facilities used to provide the services at issue, Central Vermont also includes nontraditional cost treatment in support of its rates: (1) the amount of the New England Power Pool (NEPOOL) capacity credit Central Vermont allegedly would have received if the capacity had been sold to NEPOOL instead of customers under the agreements; and (2) the replacement capacity costs incurred because Central Vermont sold the capacity off-system instead of using it to meet native load. Central Vermont includes in the latter calculation the cost of the NEPOOL capacity deficiency charges which allegedly resulted from Central Vermont buying capacity from NEPOOL. 4 The foregone NEPOOL capacity credits and replacement capacity costs do not constitute a cost of making these short-term sales. While Central Vermont has alternative uses for its capacity (i.e., to meet its native load responsibilities, to sell to NEPOOL under the terms of the NEPOOL Agreement, or to sell off-system as proposed here), it may choose only one of these alternatives because the same increment of capacity cannot be used to serve more than one customer at a time. Central Vermont's cost treatment disregards this fact and presumes that Central Vermont could have used the same increment of capacity to simultaneously meet more than one customer's load. Thus, Central Vermont would require the off-system 3 56 Fed. Reg. 252 (1991). 4 Whenever Central Vermont receives a capacity credit under the NEPOOL Agreement because its customer to compensate Central Vermont as if the same capacity had been used for an additional purpose, e.g., to sell to NEPOOL. Having in effect declined a pool transaction in order to sell the capacity off-system, Central Vermont expects the off-system customer to pay-in addition to a 100-percent contribution to the costs of the capacity used to serve the off-system customer the rates Central Vermont could have charged (i.e., the capacity credit) if it had simultaneously sold the same capacity to the pool. Similarly, having decided to sell the capacity off-system instead of keeping it to meet native load, Central Vermont expects the off-system customer to pay in addition to a 100-percent contribution to the fixed costs of the capacity used to serve the offsystem customer the costs Central Vermont incurs to replace that capacity because it cannot be used simultaneously to serve native load. Central Vermont's capacity may be used to serve only one customer at a time, and Central Vermont cannot expect off-system customers to put Central Vermont in the position it would have enjoyed if it could have used the capacity to meet two or more needs at the same time. We note that all of the transactions at issue here have been concluded and that Central Vermont is seeking recovery of nontraditional costs on an after-the-fact basis. This is not the first time this has occurred. In 1984, in Docket No, ER84-224-000, in the context of a sale of energy to New England Power Company (NEPCO), Central Vermont was discovered to have made sales to NEPCO, PSNH, and Northeast Utilities' operating companies at rates which had not been filed with the Commission, and which had been negotiated without consideration of Central Vermont's costs. Central Vermont was able to demonstrate on an after-the-fact basis that the rates did not produce more than 100-percent contribution to the fixed costs of the facilities used to make the transactions and the rates were accepted for filing. Central Vermont was advised, however, that any similar departure from the Commission's traditional rate treatment would require prior Commission approval. Under the circumstances presented here Central Vermont has transacted without prior Commission approval and has failed to provide adequate support for the rates charged, and Central Vermont has been informed under similar circumstances that prior Commission approval would be required to transact under capacity exceeds its obligations, Central Vermont has effectively sold the capacity to NEPOOL for resale to capacity-deficient members. nontraditional rates — we will direct Central Vermont to revise its rates to a level reflecting 100-percent contribution to fixed costs (i.e., excluding foregone capacity costs, fuel deficiency charges and other replacement power costs) of the facilities used to provide the service. We will also direct Central Vermont to refund all amounts it has collected in excess of the revised rates, together with interest calculated in accordance with the Commission's regulations.5 Since we are rejecting Central Vermont's rates there is no need to consider Central Vermont's requests for waivers of notice or its notices of termination at this time. Central Vermont can renew its requests when it files its revised rates. The Commission orders: (A) Central Vermont's agreements are hereby rejected without prejudice to resubmittal when Central Vermont has revised its rates pursuant to Ordering Paragraph (B) below. (B) Central Vermont is hereby directed to file revised rates for the agreements within thirty days of the date of this order. (C) Central Vermont is hereby directed to refund all amounts received in excess of the revised rates determined in accordance with Ordering Paragraph (B) above within fifteen days of the date the revised rates are accepted for filing plus interest calculated in accordance with 18 C.F.R. § 35.19a (1990). (D) Central Vermont shall file a refund report within fifteen days of making the appropriate refunds pursuant to Ordering Paragraph (C) above. [¶ 61,154] Columbia Gas Transmission Corporation and Commonwealth Gas Pipeline Corporation, Docket No. CP90-644-000 Plains Petroleum Operating Company, Docket No. CI89-389-000 Lois D. Cashell, Secretary. (Issued February 4, 1991) On December 26, 1990, the presiding judge issued an Initial Decision, 53 FERC ¶ 63,022, terminating the above-referenced proceeding. No party filed exceptions to the Initial Decision, and the Commission determined not to initiate review of the decision. Accordingly, the Initial Decision became final on February 4, 1991, pursuant to Rule 708(d) of the Commission's Rules of Practice and Procedure. [¶ 61,156] Central Power and Light Company, Docket No. ER90-289-000 Order Granting Motion to Collect Settlement Rates on an Interim Basis 5 See 18 C.F.R. § 35.19a (1990). Refunds will be deferred until Central Vermont's revised rates are accepted. (Issued February 19, 1991) Before Commissioners: Martin L. Allday, Chairman; Charles A. Trabandt, On January 29, 1991, as corrected on Febru- The settlement agreement, filed by Central and its settling wholesale customers, i.e., its wholesale customers other than Rio Grande Electric Cooperative, Inc. (Rio Grande),1 resolves all issues between these parties in this proceeding. It contemplates a two step settlement rate. The settlement agreement provides that the Step 1 settlement rates are identical to the originally filed Level A rates, as revised by Central pursuant to the Commission's June 7, 1990 order in this proceeding.2 The settlement agreement further provides that, as of January 1, 1991, the Step 1 settlement rates will be superseded by the Step 2 settlement rates. The Step 2 settlement rates will generate lower revenues than the Level B rates.3 Central proposes to make the Step 2 rates In the event that the Commission rejects the Central also proposes to make the Step 2 The settling wholesale customers are: Magic 2 Central Power and Light Company, 51 FERC 3 See id. The Step B rates were accepted to become effective January 1, 1991, subject to refund. reasonable in this proceeding and the settlement rates, with interest pursuant to 18 C.F.R. § 35.19a (1990). If Rio Grande is unwilling to make this commitment, Central will bill Rio Grande for service rendered on and after January 1, 1991, at the Level B rates, subject to refund. Given the concurrence of the affected customers, other than Rio Grande, and the absence of any prejudice to any other customers, we find that good cause exists to grant the motion with respect to the affected customers, other than Rio Grande, as ordered below. Our action, however, is without prejudice to our subsequent determination on the merits of the proposed settlement. With respect to Rio Grande, we will allow Central to bill Rio Grande at the Step 2 rates provided that Rio Grande notifies Central, within 5 days of the date of this order, that it is willing to pay the difference between the rates ultimately determined to be just and reasonable in this proceeding and the settlement rates, with interest, should the rates ultimately approved be higher than the settlement rates. The Commission orders: Good cause having been shown, Central is hereby authorized, pursuant to section 35.1(e) of the Commission's regulations, to implement its proposed settlement rates as to its settling wholesale customers (i.e., its wholesale customers other than Rio Grande) on an interim basis, subject to refund, until the date of final Commission action on the proposed settlement, as discussed in the body of this order. In the event that the settlement is not approved the provisions of the motion, as discussed in the body of this order, shall apply with respect to the reinstatement of Central's otherwise effective rates. We will also allow Central to implement its proposed settlement rates as to Rio Grande, in accordance with the discussion in the body of this order, on an interim basis, subject to refund, until rates ultimately determined to be just and reasonable are approved. The customers may elect to pay the principal amount of the difference in equal monthly installments over a period of months not to exceed the number of months during which the settlement rates are collected, but interest shall continue to accrue on all unpaid amounts. [¶ 61,157] Gary Hibbert, Docket No. QF90-236-001 Order Denying Rehearing (Issued February 19, 1991) Before Commissioners: Martin L. Allday, Chairman; Charles A. Trabandt, Elizabeth Anne Moler, Jerry J. Langdon and Branko Terzic. On January 17, 1991, Gary Hibbert (Mr. Hibbert) filed a request for rehearing of a decision by the Director of the Division of Applications, Office of Electric Power Regulation (Director), denying Mr. Hibbert's application for certification as a qualifying small power production facility.1 Background Mr. Hibbert, proposes to build and operate two separate municipal waste/sewage facilities in two separate Kansas communities, located 45 miles from each other. Each would process waste/sewage and produce biochemically derived methane gas. Mr. Hibbert proposes to deliver the methane gas to KN Energy, Inc. (KN Energy), to be "mixed with KN Energy's natural gas for consumption by [KN Energy's] customers."2 Mr. Hibbert would receive a credit for the volume of methane gas delivered to KN Energy. Mr. Hibbert also proposes to build at a third location, somewhere between the two waste/sewage facilities, a 20-MW natural gas-fired combustion turbine generator which would operate during the summer (the period of peak demand of Midwest Energy, Inc., the local electric utility). According to Mr. Hibbert, the generation facility would be regulated to use only the volume (or BTU equivalent) of natural gas that matched the methane gas produced by the two municipal waste/sewage facilities.3 In his application, Mr. Hibbert requested waiver of the Commission's regulation regarding fuel use in a qualifying small power production facility. This regulation provides that: (1) the primary energy source of a small power production facility must be biomass, waste, renewable resources, or any combination thereof; (2) 75 percent or more of the total energy input must be from these sources; and (3) the use of oil, natural gas, and coal by a facility may not, in the aggregate, exceed 25 percent of the total energy input of the facility. Mr. Hibbert reasoned that because he proposed to burn no more natural gas than the 1 Gary Hibbert, 53 FERC ¶ 62,259 (1990). 2 Application at 1. 3 Application at 2. methane gas he would exchange, there would be no additional natural gas consumed as a result of his waste/sewage operation and his electricity generation. The Director denied waiver of the Commission's fuel use regulation. The Director found that section 3(17)(B) of the Federal Power Act (FPA)5 limits the use of natural gas in a small power production facility to certain specific uses, and requires that the primary energy source be other than natural gas. The Director also stated that this statutory requirement could not be waived. The Director further found that Mr. Hibbert's proposed means of obtaining the natural gas by barter did not alter the fact that the proposed fuel for the facility would be natural gas.6 On rehearing, Mr. Hibbert asks the Commission to consider the waste/sewage facilities and the generator to be an integrated operation, citing Union Carbide Corporation, 48 FERC ¶ 61,130, reh'g denied, 49 FERC 61,209 (1989), aff'd sub nom. Gulf States Utilities Company v. FERC, No. 90-1006 (D.C. Cir. January 11, 1991), and to consider the proposed utilization of natural gas to be an innovative means of avoiding the necessity of construction of extensive and expensive storage facilities for methane gas. Mr. Hibbert suggests that the Commission view KN Energy's natural gas pipeline system as storage, and that it find that the primary energy source for the proposed facility is biomass and waste. This, Mr. Hibbert states, would be consistent with the Commission's mandate under the Public Utility Regulatory Policies Act of 1978 (PURPA) to encourage the production of electricity from renewable sources. Discussion As a preliminary matter, we note that the fuel use question in the instant proceeding, which involves a small power production facility, was not at issue in Union Carbide, which involved a cogeneration facility. 4 18 C.F.R. § 292.204 (1990). 5 16 U.S.C. § 796(17)(B) (1988). 6 53 FERC at p. 63,381. The fuel to be used for the generation of electricity in Mr. Hibbert's proposed power production facility is natural gas. In his application, Mr. Hibbert states that he "proposes to then receive natural gas from KN Energy, Inc. ... for the purposes of generating approximately 20 Megawatts of electrical power,"9 and that "the actual consumption of Applicant's proposed generation component will be a given volume of natural gas. "10 Accord ingly, the Director, on this basis, properly denied Mr. Hibbert's application for certification as a qualifying small power production facility. On rehearing, Mr. Hibbert essentially claims that although he will actually burn natural gas, he will effectively burn methane gas.11 We cannot accept Mr. Hibbert's claim. The facts are that the proposed power production facility will actually burn natural gas and not methane gas. Accordingly, the primary energy source will be natural gas and not methane gas. Therefore, the facility cannot be a small power production facility, as defined in FPA section 3(17)(A) and cannot be certified as a qualify ing small power production facility, as defined in FPA section 3(17)(C).12 Mr. Hibbert would have the Commission agree to what is essentially an elaborate fiction. He would have the Commission find that the methane gas produced in his waste/sewage operations will be the fuel in the generator, and further find, that the methane gas produced in the waste/sewage facilities during the year will be stored in KN Energy's pipeline until it is to be burned in Mr. Hibbert's proposed generator during the summer. However, Mr. Hibbert states that the methane will not actually be stored until it is burned, but will be mixed with the pipeline's natural gas and sold to the pipeline's customers. The fuel for the generator will actually be natural gas. Mr. Hibbert's proposed contractual arrangement with KN Energy allows him to operate a natural gas-fueled power generation facility and to acquire the natural gas by way of barter, rather than cash purchase. Regardless of how it is characterized, as the Director properly determined, the fact is that the proposed power generation facility will be fueled entirely by natural gas.1 13 We therefore find that the Director correctly denied Mr. Hibbert's application for certification as a qualifying small power production facility and we will deny Mr. Hibbert's request for rehearing.. The Commission orders: Gary Hibbert's request for rehearing is hereby denied. [¶ 61,158] Texas Gas Transmission Corporation, Docket No. RP90-104-006 Order on Rehearing 7 16 U.S.C. § 796(17)(A)(i) (1988). Section 3(17)(A) of the FPA was amended with respect to matters not relevant here by the Solar, Wind, Waste and Geothermal Power Production Incentives Act of 1990, P.L. No. 101-575. 8 16 U.S.C. § 796(17)(B) (1988). 9 Application at 2. 10 Application at 3. 11 Mr. Hibbert notes that, instead of building a single power generation facility located between the two waste/sewage facilities, he could build the functional equivalent: two separate power generation facilities located at the two waste/sewage facilities, fueled directly with methane gas. However, this alternative is not the facility he is seeking certification for - a single natural gas-fired power generation facility. The Commission, in acting on an application for certification of qualifying status, essentially renders a declaratory order. That is, the Commission determines, based on the information in the application and pleadings, whether or not the facility, as described in the application, meets or does not meet the statutory and regulatory requirements for quali fying status set forth in PURPA and our implement. ing regulations. See Georgetown Cogeneration, L.P., 54 FERC 61,049, at p. 61,183 (1991); CMS Midland, Inc., 50 FERC 161,098, at pp. 61,277-78 (1990), reh'g pending. Here, the facility proposed to be built, as described in the application, does not meet the statutory and regulatory fuel use requirements. 12 16 U.S.C. § 796(17)(C) (1988). 13 See 53 FERC at p. 63,381. |