CP Nat. Corp. v. Bonneville Power Admin.
| Decision Date | 13 May 1991 |
| Docket Number | 90-70029,Nos. 89-70262,s. 89-70262 |
| Citation | 928 F.2d 905 |
| Parties | CP NATIONAL CORPORATION, a California corporation, Petitioner, v. BONNEVILLE POWER ADMINISTRATION, Respondent. CP NATIONAL CORPORATION, a California corporation, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent. . Augued and |
| Court | U.S. Court of Appeals — Ninth Circuit |
George L. Wagner, Spears, Lubersky, Bledsoe, Anderson, Young & Hilliard, Portland, Or., for petitioner.
Jerome M. Feit, Solicitor, F.E.R.C., Washington, D.C., for respondent.
Randy A. Roach, Asst. Gen. Counsel, Bonneville Power Admin., Portland, Or., for respondent.
Appeal from Federal Energy Regulatory Commission and Bonneville Power Administration.
Before WRIGHT, POOLE and THOMPSON, Circuit Judges.
CP National applied to the Bonneville Power Administration ("BPA") for an increase in its average system cost ("ASC"). BPA determined that, pursuant to the 1984 average system cost methodology ("ASC methodology"), CP National was not entitled to an increase because the Oregon Public Utilities Commission ("OPUC") had not determined the costs in question to be reasonable for ratemaking purposes. The Federal Energy Regulatory Commission ("FERC") affirmed the BPA determination. CP National appeals this rate determination.
CP National presents three arguments urging reversal. First, CP National contends that BPA wrongfully refused to accept costs related to CP National's cogenerated power purchases as a basis for an increase in its ASC. Second, CP National argues that because it allegedly passed on to its ratepayers all subsidy monies advanced by BPA pursuant to its initial Appendix I filing, BPA could not subsequently recollect those monies from CP National. Third, CP National argues that it is entitled to the rate increase because BPA currently grants to CP National's transferee, Oregon Trail Electric Consumers Cooperative, Inc., the benefit of the higher rate, and thus the higher BPA subsidy. We affirm.
Act (the "Regional Act"), 16 U.S.C. Sec. 839c(c) (1988), established a power exchange program between BPA and investor-owned utilities ("IOUs") in the Pacific Northwest. Congress aimed with this exchange program to eliminate the disparity that developed between the rates paid by residential customers of the IOUs and the lower rates paid by residential customers of publicly-owned utilities, who receive lower-cost federal power. See California Energy Resources Conservation and Dev. Comm'n v. Johnson, 807 F.2d 1456, 1459-60 (9th Cir.1986); Pacificorp v. FERC, 795 F.2d 816, 818 (9th Cir.1986). The exchange program enables IOUs to furnish residential power at lower rates than their costs would otherwise permit, by providing IOUs access to federally funded power.
In reality, the exchange program established by the Regional Act amounts to "a mechanism for calculating a subsidy, not for establishing a traditional cost of purchased power." Federal Energy Regulatory Commission Order No. 400-A, "Methodology for Sales of Electric Power to the Bonneville Power Administration," 30 F.E.R.C. p 61,108, 61,195-96 (1985). The exchange actually transfers no power to or from BPA because the "exchange" is simply an accounting transaction: "In practice, only dollars are exchanged, not electric power." Public Util. Comm'r of Oregon v. Bonneville Power Admin., 583 F.Supp. 752, 754 (D.Or.1984).
Under the exchange system contemplated by section 5, each electric utility in the northwest may elect to sell power to BPA at the "average system cost of [a] utility's resources." 16 U.S.C. Sec. 839c(c)(1) (1988). BPA then sells the same amount of power back to the utility at BPA's lower wholesale rate. 1 This effectively enables the IOU to provide power to its residential customers at the same priority rate given to residential customers who receive BPA federal power.
The Regional Act sets the price of the exchange according to the IOU's "average system cost" ("ASC"), but does not specify the methodology to be used by the BPA in making ASC determinations. See Central Electric Coop. v. Bonneville Power Admin., 835 F.2d 199, 201 (9th Cir.1987). Instead, section 5(c)(7) of the Act provides only the manner in which the BPA should develop such a methodology:
The "average system cost" for electric power sold to the Administrator under this subsection shall be determined by the Administrator on the basis of a methodology developed for this purpose in consultation with the Council, the Administrator's customers, and appropriate State regulatory bodies in the region. Such methodology shall be subject to review and approval by the Federal Energy Regulatory Commission....
16 U.S.C. Sec. 839c(c)(7) (1988). We have characterized the methodology as "[t]he crucial part of the agreement" between BPA and the IOUs participating in the residential exchange subsidy program. Central Electric, 835 F.2d at 201. The ASC methodology currently in effect was adopted by the BPA in 1984, and subsequently approved by FERC and this court. See Administrator's Record of Decision (June 1984); FERC Order No. 400, "Methodology for Sales of Electric Power to Bonneville Power Administration," 49 Fed.Reg. 39,293 (1984); Order No. 400-A, 30 F.E.R.C. p 61,108 (1985); Pacificorp, 795 F.2d at 819, 821-25.
The 1984 ASC methodology takes a jurisdictional approach to cost determination. It relies heavily on the findings of state regulatory authorities that the rates submitted to BPA have been found reasonable for retail rate purposes. The BPA, in its record of decision adopting the 1984 methodology, explained this reliance:
Reliance on decisions of the relevant ratesetting bodies for the development of these costs was accepted on the premise that Inherent in the very mention of "informed decisions" is the notion that there has been public scrutiny and the vigorous analysis of costs that is typically found in a rate case.
Administrator's Record of Decision (June 1984), quoted in Central Electric, 835 F.2d at 201-02 n. 7. The ASC methodology makes clear to all involved in the power exchange program that costs must be approved by a state commission before they will be considered in an ASC determination.
Pursuant to the 1984 ASC methodology, a utility desiring a revised ASC determination must submit to BPA an Appendix 1 filing. The utility must include in the filing "a loss study, reflecting [the utility's] Costs as approved by the State Commission and a reconciliation of all Costs included on the revised Appendix 1 to the rate order issued by that utility's State Commission." Administrator's Record of Decision (June 1984) (filing instructions Sec. IIB3). Moreover, a utility may not file a revised Appendix 1 at just any time. Filings must instead be based on an identifiable "exchange period." An identifiable exchange period begins when a new retail rate goes into effect and ends when that retail rate is superseded by a further rate change. Central Electric, 835 F.2d at 201 & n. 6. Again, this exchange period requirement makes action by the retail regulatory body a prerequisite to any recomputation of a utility's ASC: the IOU cannot even get in BPA's door until the state regulator approves a proposed rate change.
This appeal concerns BPA's denial of CP National's average system cost increase request, and BPA's consequent denial of additional exchange credits under the Regional Act. As the discussion of the 1984 ASC methodology reveals, however, the real story begins earlier, with CP National's request to the state regulatory body for permission to raise its rates.
In late 1986 CP National filed for jurisdictional rate increases with the Oregon Public Utilities Commission ("OPUC"). Prior to a full hearing, OPUC issued Order No. 86-1211 authorizing an interim rate increase subject to refund pending OPUC's final determination.
The primary aim of CP National's request was the recovery of certain costs of cogenerated power purchased from qualifying facilities ("QFs") under the Public Utility Regulatory Policies Act of 1978 ("PURPA"), Pub.L. No. 95-617, 92 Stat. 3117 (1978) (). PURPA, as administered by both federal and state regulatory bodies, requires utilities to make compulsory power purchases from cogenerators and small power producers at their "avoided cost," as defined in the regulations:
"Avoided cost" means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.
18 CFR Sec. 292.101(b)(6) (1990). The applicable avoided cost is determined by the state regulatory body, here OPUC. OPUC, allegedly over the objections of CP National, required CP National to purchase PURPA power from certain cogenerators at the "avoided cost" of CP National's wholesale power supplier, the Idaho Power Company, rather than its own avoided cost. As a result, CP National purchased cogenerated power at prices Idaho was paying cogenerators under PURPA, rather than the lower prices CP National would avoid paying the Idaho Power Company if CP National purchased power from cogenerators. CP National's request for a retail rate increase stems from these PURPA power purchases.
CP National subsequently filed an...
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