Central Lincoln Peoples' Utility District v. Johnson

SCHROEDER, Circuit Judge. I. INTRODUCTION These consolidated cases concern the 1981 wholesale power and transmission rates adopted by the Administrator of the Bonneville Power Administration (BPA). These are the first rates promulgated under the Pacific Northwest Electric Power Planning and Conservation Act (the Act), 16 U.S.C. § 839-839h (1982). The petitioners in the principal case, Central Lincoln II,1 challenge numerous aspects of the rates themselves, as well as the procedures followed by BPA in adopting them. This court has jurisdiction over petitions to review final rates under 16 U.S.C. § 839f(e)(5). Rate determinations become final upon confirmation and approval by the Federal Energy Regulatory Commission (FERC). 16 U.S.C. § 839e(a)(2). These rates initially took effect only on an interim basis pending review by FERC. Order Confirming, Approving, and Placing Increased Wholesale Power Rates In Effect On An Interim Basis, 46 Fed.Reg. 33,542 (1981).2 Proceedings in this court began in 1981 with petitions seeking review of BPA’s rate determinations before FERC had completed its review of any of the rates. FERC’s failure, for two years, to complete its review of any of the rates gave rise to considerable concern. See Energy and Water Development Appropriations For 1983: Hearings Before the Sub-comm. on Energy and Water Development of the House Comm, on Appropriations, 97th Cong, 2d Sess., 110-16 (1982). Some petitioners therefore filed a separate Petition for Review of Agency Action Unlawfully Withheld to compel FER'C to act. Pacific Carbide & Alloys Co. v. FERC, No. 83-7016 (9th Cir. filed Jan. 17, 1983). The petitioners argued that FERC’s failure to act was equivalent to a final action. See Environmental Defense Fund v. Hardin, 428 F.2d 1093, 1098 (D.C.Cir.1970). It was — 1106 — also suggested that such an order to compel the agency to complete its review was appropriate under the All Writs Act, 28 U.S.C. § 1651(a), as relief in aid of our prospective jurisdiction to review the final rates. See FTC v. Dean Foods, 384 U.S. 597, 86 S.Ct. 1738, 16 L.Ed.2d 802 (1966). On June 15, 1983, FERC gave final approval to the regional, rates which constitute all but a relatively small segment of the 1981 rates. Order Confirming and Approving Rates on a Final Basis, 48 Fed.Reg. 28,-317 (1983). The petitioners in Pacific Carbide are therefore no longer seeking an order to compel FERC to act and that petition is moot. Moot as well are the original, pre-June 15, 1983 petitions for review. New petitions for review have been filed to review the rates that have received final administrative approval, and those petitions are now ripe for decision. Petitioners concerned about the scope of review that FERC would exercise over the regional rates challenged the order it has issued in that regard, Order Resolving Scope of Commission’s Jurisdiction, Granting Intervention, and Establishing Further Procedures, 20 FERC (CCH) H 61,292 (Sept. 1, 1982) (hereinafter FERC Jurisdiction Order). Lobdell v. FERC, No. 82-7710 (9th Cir. filed Nov. 29, 1982). Those issues are subsumed in our review of the final rates, and we do not need to decide Whether an independent jurisdictional basis existed for our review of the order before the rates became final. All petitions have been consolidated for our determination. In this opinion we must consider the following issues: a) whether we have jurisdiction to review those rates that FERC has not yet finally approved; b) whether FERC properly exercised a narrow scope of review over the rates established by BPA; c) whether BPA followed appropriate procedures in its rate-making; and d) whether there is merit to any of the petitioners’ substantive challenges to the rates established by BPA and approved by FERC. We conclude that we do not have jurisdiction to review the rates themselves until FERC has confirmed and approved them. Accordingly we do not consider the merits of the petitions filed by the California Energy Commission, the California Utilities, the State of California, and the California Public Utilities Commission challenging the nonregional rates for which FERC approval is still pending.3 We do consider the petitions challenging the regional rates and hold that FERC properly applied a narrow scope of review to the BPA rates; we further hold that the rates as promulgated by BPA are not procedurally defective, and, finally, that the petitioners’ challenges to the evidence supporting the rates as promulgated must fail. II. BACKGROUND OF THE ACT AND THE PARTIES TO THIS PROCEEDING Because this case requires us to construe a unique piece of energy legislation, we begin with a brief look at its background and operation. Congress adopted the Act on December 5, 1980 to respond to increasing demand for the finite supply of inexpensive hydroelectric power generated on the Columbia River System, and to avert protracted legal battles over the allocation of this federal resource. See Central Lincoln Peoples’ Utility District v. Johnson, 686 F.2d 708, 714 (9th Cir.1982), cert. granted, 460 U.S. 1050, 103 S.Ct. 1496, 75 L.Ed.2d 928 (1983) (hereinafter Central Lincoln I); Public Power Council v. Johnson, 674 F.2d 791, 795 (9th Cir.1982); H.R. Rep. No. 976, Part II, 96th Cong., 2d Sess. (1980) (hereinafter House Report, Part II), reprinted in United States Department of Energy, Legislative History of the Pacific — 1107 — Northwest Electric Power Planning and Conservation Act, at 243 (1981) (hereinafter BPA Legislative History); H.R.Rep. No. 976, Part I, 96th Cong., 2d Sess. 24-26 (1980) (hereinafter House Report, Part I), reprinted in BPA Legislative History, at 333; S.Rep. No. 272, 96th Cong., 1st Sess. (1979), U.S.Code Cong. & Admin.News 1980, p. 5989 reprinted in BPA Legislative History, at 445 (hereinafter Senate Report). The Act is intended to provide a comprehensive solution to the Pacific Northwest’s electric power problems. Public Power Council v. Johnson, 674 F.2d at 792. See generally Blumm, The Northwest’s Hydroelectric Heritage: Prologue to the Pacific Northwest Electric Power Planning and Conservation Act, 58 Wash.L.Rev. 177 (1983). To assure the region an adequate supply of electricity, the Act grants the BPA Administrator authority to acquire additional power sources, 16 U.S.C. § 839d, and to initiate conservation measures. 16 U.S.C. §§ 839b, 839d and 839f(j). The Act also creates a regional planning council to govern BPA’s acquisition of major resources and to implement the Act’s fish and wildlife preservation provisions. 16 U.S.C. § 839b. Further, the Act guarantees public participation in the decisions made regarding electric power. 16 U.S.C. §§ 839(3), 839b. Finally, the Act sets forth directives, stressing cost recoupment, for the Administrator to follow in establishing rates both for electric energy sales and for the transmission of non-federal power. 16 U.S.C. § 839e. Under limited circumstances the Act authorizes the sale of power outside of the Pacific Northwest. 16 U.S.C. § 839c(f) (nonregional sales). Such sales generally are to the Southwest states, principally California. These sales ensure that surplus hydropower is not wasted. Instead, the surplus power temporarily displaces more expensive, less environmentally desirable oil-generated power. See 126 Cong.Rec. 27,817 (1980) (Remarks of Rep. Moorhead), reprinted in BPA Legislative History at 181-82. In response to California customers’ complaints that BPA’s nonregional rates were unjust, House Report, Part I, supra, at 85-87 (1980), the Act provides for FERC to review regional rates separately from nonregional rates, and expands FERC procedures governing the latter. See 16 U.S.C. § 839e(k). The Act’s passage marked a departure from the regulatory framework that previously governed review of BPA rates. That framework continues to govern the other Power Marketing Administrations (PMA’s) which, like BPA, Congress created to sell federal hydroelectric power. See United States v. Tex-La Electric Cooperative, Inc., 693 F.2d 392, 394 (5th Cir.1982). Previously, the Flood Control Act of 1944 governed the rates charged by PMA’s. Before these rates could become effective, they were submitted for confirmation and approval to the Federal Power Commission. Tex-La Electric Cooperative, Inc., 693 F.2d at 394; 16 U.S.C. § 825s (1976). When the Department of Energy was organized in 1977, the Federal Power Commission’s rate review authority was transferred to the Secretary of Energy, who ultimately delegated power to confirm and approve the PMA rates to FERC. Delegation Order for Confirmation and Approval, 43 Fed.Reg. 60,636 (1978). Since there are no special provisions for judicial review of those rate determinations, challenges to the other PMA rates are brought in district court under the Administrative Procedure Act, 5 U.S.C. §§ 551 et seq. (1982). See FERC Supplemental Status Report 1 n. 1 (June 3, 1983). The Act, however, provides for initial judicial review of final actions of the BPA in the court of appeals for the region. 16 U.S.C. § 839f(e)(5). The following is a brief description of the parties, most of whom represent multiple entities, and their status in these cases: The Public Power Council (PPC), petitioner. PPC represents 113 publicly and consumer-owned utilities in the Pacific Northwest. The Public Generating Pool (PGP), petitioner. PGP represents publicly and — 1108 — municipally-owned utilities in the Pacific Northwest. Pacific Northwest Investor-Owned Utilities (IOUs), petitioners. IOUs are all of the investor-owned utilities in the Pacific Northwest. Pacific Northwest State Commissions (State Commissions), petitioners. The State Commissions are regulatory bodies with statutory responsibility to ensure that customers of investor-owned utilities receive reasonable rates. The Direct Service Industrial Customers (DSIs), petitioners. The DSIs are primarily large aluminum companies who buy power directly from BPA. The California Energy Commission (CEC), petitioner. CEC is a statutory agency to implement the Warren-Alquist Act, Cal.Pub.Res.Code §§ 25000 et seq. It forecasts state energy needs and determines whether to certify construction of new power plants in California. Pacific Gas and Electric Company, Southern California Edison, Los Angeles Department of Water, et al. (California Utilities), petitioners. These are California investor-owned utilities and interconnected municipal electric systems. The State of California and Public Utilities Commission (State of CA, PUC), petitioners. These are government entities with the responsibility to ensure that energy consumers can purchase electricity for reasonable rates. International Paper Co. and St. Regis Paper Co. (IPC/St. Regis), intervenors. These companies buy large amounts of electricity from BPA preference customers, primarily publicly and consumer-owned utilities. See Central Lincoln I, 686 F.2d at 711. The Federal Energy Regulatory Commission (FERC), intervenor in the rate review proceedings. FERC is an independent federal regulatory agency created by the Department of Energy Reorganization Act, 42 U.S.C. §§ 7101 et seq. (Supp. V 1981). The Bonneville Power Administration (BPA), respondent in the rate petitions. BPA is the federal marketing agent for power generated by federal dams constructed and operated by the Bureau of Reclamation and the Army Corps of Engineers in the Pacific Northwest, pursuant to the Bonneville Project Act of 1937, 16 U.S.C. §§ 832 et seq. (1982). BPA also operates high voltage lines in the region, which transmit both federal and non-federal power. See 16 U.S.C. §§ 838b, 838f. III. OUR JURISDICTION TO REVIEW THE RATES Because some of the petitions in these consolidated cases involve BPA rates that FERC has not yet approved and confirmed, the threshold question we must decide is whether the Act permits judicial review of rates set by the BPA Administrator before FERC confirmation and approval. We conclude that it does not. The Act provides for judicial review in the following subsection: Suits to challenge the constitutionality of this chapter, or any action thereunder, final actions and decisions taken pursuant to this chapter by the Administrator or the Council, or the implementation of such final actions ... shall be filed in the United States court of appeals for the region____ Suits challenging any other actions under this chapter shall be filed in the appropriate court. 16 U.S.C. § 839f(e)(5). Section 839f(e) also describes eight final actions which are subject to judicial review: (A) adoption of the plan or amendments thereto by the Council under section 839b of the title, adoption of the program by the Council, and any determination by the Council under section 839b(h) of this title; (B) sales, exchanges, and purchases of electric power under section 839c of this title; (C) the Administrator’s acquisition of resources under section 839d of this title; (D) implementation of conservation measures under section 839d of this title; — 1109 — (E) execution of contracts for assistance to sponsors under section 839d(f) of this title; (F) granting of credits under section 839d(h) of this title; (G) final rate determinations under section 839e of this title; and (H) any rule prescribed by the Administrator under section 839e(m)(2) of this title. 16 U.S.C. §§ 839f(e)(l) (emphasis supplied). The listing is not exclusive since section 839f(e)(3) states: Nothing in this section shall be construed to preclude judicial review of other final actions and decisions by the Council or Administrator. In two previous cases we recognized that this court has jurisdiction to review BPA actions under the Act, provided those actions are final. Central Lincoln I, 686 F.2d at 710; California Energy Resources Conservation and Development Commission v. Johnson, 677 F.2d 711, 712 (9th Cir.1982); 16 U.S.C. § 839f(e)(l)(B). The statute defines when rate determinations become final: Rate determinations pursuant to section 839e of this title shall be deemed final upon confirmation and approval by the Federal Energy Regulatory Commission. 16 U.S.C. § 839f(e)(4)(D). Since the Act explicitly defines when rate determinations are final, we need look no further than the statute itself, 16 U.S.C. § 839f(e)(4)(D), to determine whether we may review rates before FERC confirmation and approval. When a statute establishes a specific scheme for obtaining review, the courts may assume that set of procedures is exclusive. See Nader v. Volpe, 466 F.2d 261, 266 (D.C.Cir.1972). Courts have no jurisdiction when statutory procedural prerequisites are not met. See Weinberger v. Salfi, 422 U.S. 749, 764-66, 95 S.Ct. 2457, 2466-67, 45 L.Ed.2d 522 (1975); Montgomery v. Rumsfeld, 572 F.2d 250, 252-53 (9th Cir.1978); cf. United States v. Consolidated Mines and Smelting Co., 455 F.2d 432, 451 (9th Cir.1971) (describing doctrine that courts must give effect to statutory determination of finality). Thus, section 839f(e)(4)(D) precludes us from treating rate determinations as final actions before FERC has confirmed and approved the rates. Sound considerations support this result. As both BPA and FERC note, if we were to exercise judicial review of rates before FERC has confirmed and approved them, it would be wasteful in the event of a FERC remand. In fact, most of the petitioners acknowledge that because of FERC’s expertise in the field of federal power rates, the court should defer its examination of challenges to rates until FERC has completed its own review. See generally ECEE, Inc. v. FERC, 611 F.2d 554 (5th Cir.1980). Therefore, most of the petitions to review the BPA rates, filed after the 1981 rate promulgations but before FERC approval, were filed as protective measures because of the 90-day statute of limitations. 16 U.S.C. § 839f(e)(5).4 PPC is the only petitioner arguing that the statute contemplates judicial review of the rates prior to FERC confirmation and approval. PPC relies on the clause of section 839f(e)(5) that provides, “[sjuits to challenge the constitutionality of this chapter, or any action thereunder, final actions and decisions taken pursuant to this chapter ... shall be filed in the United States court of appeals for the region” (emphasis added). PPC contends that the rates may be challenged before FERC approval because they are encorn — 1110 — passed by the language “any action thereunder.” The phrase PPC isolates, however, refers only to challenges that actions taken under the Act are unconstitutional. We need not determine whether we would have jurisdiction to review a constitutional challenge to non-final agency action where our decision might be mooted by subsequent actions of BPA or FERC, cf. Hayburn’s Case, 2 U.S. (2 Dali.) 408, 1 L.Ed. 436 (1792). Since the claims now before us are not constitutional challenges to BPA’s rates, we are constrained by the statute not to entertain non-constitutional challenges to rates until the rates have become final. Accordingly, we now have jurisdiction to consider only the petitions for review of the regional rates, which FERC has approved. The remaining petitions for review, filed in 1981 and including petitions to review the nonregional rates that FERC has not yet approved, are dismissed. IV. THE SCOPE OF FERC REVIEW Before examining the various challenges to BPA’s rate-making, we must look at FERC’s review of the regional rates to determine whether it adopted the appropriate scope of review intended by Congress under the Act. Review of regional rates is governed by section 7(a)(2), 16 U.S.C. § 839e(a)(2), which provides: Rates established under this section shall become effective only, except in the case of interim rules as provided in subsection (i)(6) of this section, upon confirmation and approval by the Federal Energy Regulatory Commission upon a finding by the Commission, that such rates— (A) are sufficient to assure repayment of the Federal investment in the Federal Columbia River Power System over a reasonable number of years after first meeting the Administrator’s other costs, (B) are based upon the Administrator’s total system costs, and (C) insofar as transmission rates are concerned, equitably allocate the costs of the Federal transmission system between Federal and non-Federal power utilizing such system. The heart of the dispute is whether Congress intended to limit FERC’s review of regional rates to the three findings set forth in section 7(a)(2), or whether FERC was expected to review for compliance with preexisting statutory standards, thus probing issues of cost allocation and rate design. FERC has chosen the narrower path. FERC Jurisdiction Order, supra. To place the issue in its proper context, we must first discuss FERC’s order and the conflicting legislative history surrounding section 7(a) itself. To determine the proper scope of review, it is necessary to understand the differences between FERC’s role both in connection with section 7(a), the regional rates, and section 7(k), 16 U.S.C. § 839e(k), the nonregional rates, as well as the difference between rate-making under the Act and rate-making as conducted prior to the Act’s passage. That analysis leads us to conclude that by adopting a narrow scope of review limited to the three items listed in section 7(a)(2), FERC properly interpreted and gave effect to the Congressional desire to remove FERC from actual rate-making and to limit FERC’s role to financial oversight of the regional rates. A. FERC’s Interpretation and the Legislative History of Section 7(a) Six months after BPA submitted the regional rates to FERC for confirmation and approval, FERC sought briefing from all interested parties as to the scope of its review jurisdiction under the Act. Order Directing the Submittal of Briefs on Jurisdictional Issues, Bonneville Power Administration, 18 FERC (CCH) 1161,037 (Jan. 19,1982). After receiving briefs from many of the petitioners here, as well as letters from Senators McClure and Hatfield, FERC issued its order resolving jurisdiction. See FERC Jurisdiction Order, supra. FERC concluded that the Act limited its review of regional rates to the three findings set out in section 7(a)(2). Id. at 61,-557. FERC read the Act as giving BPA “relatively unfettered discretion to design rates and distinguish among customer — 1111 — classes in the region,” subject to judicial, but not FERC review under the relevant statutes. Id, FERC thus perceived its role as assuring that overall rates are adequate, but not excessive, in relation to cost recovery. Id. As to nonregional rates, FERC determinéd that section 7(k) provides a “unique check” on the Administrator’s development of rates outside the region, assuring that the nonregional rates comply with preexisting statutory standards. Id. FERC based its narrow view of its jurisdiction over the regional rates upon its interpretation of the Act. FERC read section 7(a) as establishing a bifurcated rate-making framework. It reasoned that section 7(a)(1), 16 U.S.C. § 839e(a)(l), addresses the BPA Administrator, and establishes the statutory standards governing the setting of the rates. Section 7(a)(1) provides: The Administrator shall establish, and periodically review and revise, rates for the sale and disposition of electric energy and capacity and for the transmission of non-Federal power. Such rates shall be established and, as appropriate, revised to recover, in accordance with sound business principles, the costs associated with the acquisition, conservation, and transmission of electric power, including the amortization of the Federal investment and the Federal Columbia River Power System (including irrigation costs required to be repaid out of power revenues) over a reasonable period of years and the other costs and expenses incurred by the Administrator pursuant to this chapter and other provisions of law. Such rates shall be established in accordance with sections 9 and 10 of the Federal Columbia River Transmission System Act (16 U.S.C. § 838) [16 U.S.C. §§ 838g and 838h], section 5 of the Flood Control Act of 1944 [16 U.S.C. § 825s], and the provisions of this chapter. 16 U.S.C. § 839e(a)(l). In contrast, FERC reasoned that section 7(a)(2), which is addressed to FERC, specifically limits its review function to the three findings listed in the section. Once FERC makes those findings, the rates take effect. Several petitioners before us disagree with FERC’s statutory interpretation. PGP, the IOUs, the State Commissions, and IPC/St. Regis contend that FERC’s scope of review of regional rates is as broad as the scope of review in prior power marketing acts, and includes review of rate design and cost allocation issues. FERC, BPA, PPC, and the DSIs argue that FERC review of regional rates is limited to the three findings specified in section 7(a)(2) and that FERC must confirm and approve the rates once it makes those findings. Both sides can point to items in the legislative history to support their positions. The parties that argue that FERC should adopt a broad scope of review for compliance with all statutory design requirements rely upon language in a House Report that describes section 7(a) as setting forth the “applicable laws” upon which FERC is to approve and confirm the rates. See House Report, Part I, supra, at 68. The proponents of limited review note that amendments that would have made relatively exhaustive FERC review an explicit requirement under section 7(a) were proposed but not adopted both in the Senate and the House. See Transcript of Proceedings of Business Meeting of the Comm, on Energy and Natural Resources, 96th Cong., 1st Sess. 1, 201 (July 18, 1979) (proposed amendment of Sen. McClure) (hereinafter Business Meeting). Pacific Northwest Pacific Power Planning: Hearings on H.R. 3508 and H.R. 4159 Before the Subcomm. on Energy and Power of the House Comm, on Interstate and Foreign Commerce, 96th Cong., 1st Sess. 352-53 (1979) (proposal of Harrison Call, Jr.) (hereinafter Hearings). These unsuccessful efforts to include language explicitly requiring broad review suggest that Congress envisioned a narrower role for FERC. Unfortunately, contemporaneous agency statements about the scope of FERC’s review jurisdiction under section 7(a) are also contradictory. William W. Lindsay, then Chairman of FERC, interpreted the enumeration in section 7(a)(2) as suggesting — 1112 — broad criteria for FERC review. Hearings, supra, at 196. BPA, however, apparently took the position that FERC’s sole responsibility under the new statute was only to confirm that the rates produced the required revenue levels. Id. at 418. Because of these conflicts, we must look beyond section 7(a)’s language and legislative history for guidance. B. FERC Review of Nonregional Power Rates Under Section 7(k) FERC’s review of regional rates under section 7(a) is seen in better perspective by contrasting it with review of nonregional rates under section 7(k), 16 U.S.C. § 839e(k). Section 7(k) provides: Notwithstanding any other provision of this chapter, all rates or rate schedules for the sale of nonfirm electric power within the United States, but outside the region, shall be established after December 5, 1980, by the Administrator in accordance with the procedures of subsection (i) of this section (other than the first sentence of paragraph (6) thereof) and in accordance with the Bonneville Project Act, [16 U.S.C. § 832 et seq.], the Flood Control Act of 1944, and the Federal Columbia River Transmission System Act [16 U.S.C. § 838 et seq.']. Notwithstanding section 201(f) of the Federal Power Act, such rates or rate schedules shall become effective after review by the Federal Energy Regulatory Commission for conformance with the requirements of such Acts and after approval thereof by the Commission. Such review shall be based on the record of proceedings established under subsection (i) of this section. The parties to such proceedings under subsection (i) of this section shall be afforded an opportunity by the Commission for an additional hearing in accordance with the procedures established for ratemaking by the Commission pursuant to the Federal Power Act [16 U.S.C. § 791a et seq.]. Several differences in the nature of FERC’s review responsibilities over the two kinds of rates are apparent from the statute’s face. First, section 7(a)(2) does not provide for additional hearings to be held before FERC, while section 7(k) does provide for such hearings. Second, section 7(k) requires FERC to review the rates for compliance with the Bonneville Project Act, the Flood Control Act of 1944, and the Federal Columbia River Transmission System Act. In contrast, section 7(a)(2) provides for confirmation and approval contingent only upon the three specific findings contained in subsections (A) through (C). Finally, while section 7(a)(2) directs FERC to confirm and approve regional rates upon making certain findings, section 7(k) expressly describes FERC’s responsibility to review nonregional rates for conformance with the broader rate-approval requirements of other applicable statutes. The reasons for these differences between FERC’s review function for regional versus nonregional rates become apparent when one examines the role of nonregional rates in the BPA system. Under the Act, only “surplus energy” and “surplus peaking capacity” may be sold outside the Pacific Northwest Region. See 16 U.S.C. §§ 839c(f), 839f(c). Power resources are considered “surplus” when there is no market or demand for them at any established rate within the region. 16 U.S.C. § 839f(c). The majority of power sold outside the region is “nonfirm” energy subject to rate review under 16 U.S.C. § 839e(k). Nonfirm energy is energy in excess of that which BPA can reliably plan on producing, based on estimates that water levels used for power generation will at times be low or “critical.” Firm energy is the amount of power that BPA can plan on producing at a critical water level. See Central Lincoln I, 686 F.2d at 710 n. 1. Nonfirm energy can be sold within the region and is only available outside of the region when no one in the region will purchase it at established rates. See Central Lincoln I, 686 F.2d at 710; 16 U.S.C. § 839f(c). Usually seasonal surpluses result in the availability of surplus power for sale outside of the region. See 126 Cong. Rec. H9852 (daily ed. Sept. 29, 1980) (statement of Rep. Swift). Such sales permit — 1113 — nonregional purchasers to replace more expensive oil fuel with the region’s hydroelectric power. Id. California is the primary purchaser of nonfirm power. The statutory provision governing rate review for sales of nonfirm power outside the region apparently was inserted in response to the concerns of the California congressional delegation. While the Act was before Congress, BPA announced its 1979 rates, which represented a substantial increase to nonregional purchasers. See generally Order Scheduling Informal Conference, Denying Motion, Granting Interventions and Establishing Procedures, 20 FERC (CCH) 11 61,291 (Sept. 1, 1982). These new rates prompted the California delegation to write a letter to the Secretary of Energy protesting this “unjustified” increase. Letter from Carlos J. Moorhead to Charles W. Duncan, Jr. (September 24, 1979), House Report, Part I, supra, at 86-87. The minority House Report explains that these concerns led to the inclusion of section 7(k)’s review provisions that: reaffirmed that all rates or rate schedules proposed by the BPA Administrator for the sale of nonfirm energy outside of the Region but within the United States shall become effective only after substantive review by the Federal Energy Regulatory Commission for conformance with the requirements of the Bonneville Project Act, the Flood Control Act of 1944 and the Federal Columbia River Transmission System Act. In performing its review, the Commission shall afford any party to the proceedings an opportunity for a hearing to be conducted in accordance with the procedure established by the Commission for rate-making under the Federal Power Act. House Report, Part I, supra, at 88. Accord, id. at 81. Thus, Congress intended section 7(k) to protect interests outside the region. The parties in the present case generally agree that FERC’s review of nonregional rates under section 7(k) is relatively broad.5 Specifically, the parties agree that FERC must apply all of the statutory standards that previously governed BPA rates before it approves rates under section 7(k).6 Section 7(a), however, does not mandate such broad review of the regional rates. The conscious effort to broaden review of nonregional rates is strong evidence that review of regional rates was to be narrow. C. Administrative Review of Rates Before the Act To decide how the Act was intended to operate with respect to administrative review of regional rates, we must also examine the historical background of agency review of rate-making to understand the situation Congress was attempting to change when it passed the Act. Review of rate design and cost allocation was previously undertaken by FERC’s predecessor, the Federal Power Commis — 1114 — sion (FPC). Authority for FPC review was contained in the Bonneville Project Act, the Flood Control Act of 1944 and, more recently, the Columbia River Transmission System Act. 16 U.S.C. §§ 832 et seq., 825s, and 838 et seq. Both the Bonneville Project Act and the Flood Control Act of 1944 contain two sets of standards. The first standard pertains to the recovery of the cost of providing electric energy, including amortization of the capital investment over a reasonable period. 16 U.S.C. § 832f (Bonneville Project Act); 16 U.S.C. § 825s (Flood Control Act). Second, these statutes require either that energy be disposed of to encourage the most widespread use at the lowest rates “consistent with sound business principles,” 16 U.S.C. § 825s, or that rates encourage “the widest possible diversified use of electric energy.” 16 U.S.C. § 832e. The FPC interpreted these provisions as creating a dual statutory standard of providing customers with the benefits of power at the lowest possible price consistent with good business practices as well as protecting the interest of the United States in amortizing its investment in the projects within a reasonable period. Opinion No. 482, 34 F.P.C. 1465 (1965). The Columbia River Transmission System Act when passed added a statutory standard requiring that recovery of the cost of federal transmission be equitably allocated between federal and nonfederal power using the system. 16 U.S.C. § 838h. The FPC as well as FERC, its successor, took the scope of their review from these statutes. See FERC Jurisdiction Order, supra; Hearings, supra, at 202. The FPC engaged in cost allocation and rate design review in applying those standards mandating that rates be set with a view towards widespread use. See 34 F.P.C. at 1470. As rate-making principles became more complex, and BPA began to identify and assign different costs to different customers, FPC review under the widespread use standard became more complicated. See Opinion and Order Confirming and Approving Rate Schedules, 54 F.P.C. 808, 815 (1975). The trend toward more complex review continued when FERC replaced the FPC. See, e.g., Order Remanding Rates Without Prejudice, 45 Fed.Reg. 79,545 (1980) (indicating concern that BPA rates meet widest use standard and requiring more information from BPA to substantiate cost allocation and rate design decisions). Thus, under prior law, BPA designed rates and allocated costs between classes of customers under broad statutory criteria, and FERC reviewed these decisions under the same broad standards. Congress designed the Act to prevent protracted legal challenges to BPA’s power allocation and rate-making decisions and to resolve disputes among the classes of customers competing for BPA’s power. House Report, Part I, supra, at 31-32; House Report, Part II, supra, at 25-27; 126 Cong.Rec. S11597 (daily ed. Aug. 3, 1979) (statement of Sen. Jackson). The Act’s structure reveals Congress’s clear choice to depart from the previous pattern of FERC review in favor of a more limited, oversight role. The Act now contains far more complex and detailed provisions governing BPA’s rate-making process. See House Report, Part II, supra, at 52-54; House Report, Part I, supra, at 68-70. A comparison of the rate directives for BPA in section 7 with those in prior power marketing acts underscores the degree to which the Act elaborates rate-making procedures for BPA and correspondingly simplifies FERC’s review. The Act distills only essential guidelines from prior statutes in the section addressed to FERC review. 16 U.S.C. § 839e(a). The three findings the Act requires FERC to make are selectively derived from previous statutes. Subsection 7(a)(2)(A), providing for review to determine whether the rates repay the federal investment over a reasonable number of years, has its roots in the Bonneville Project Act, 16 U.S.C. § 832f, and the Flood Control Act of 1944, 16 U.S.C. § 825s. Subsection 7(a)(2)(C)’s requirement, that the transmission rates equitably allocate costs between federal and nonfederal power, has its roots in the Co — 1115 — lumbia River Transmission System Act, 16 U.S.C. § 838h. FERC’s required findings notably omit one standard contained in the prior statutes. That standard requires that rates be set to encourage widespread use at low rates, 16 U.S.C. § 825s, or the widest possible diversified use of energy, 16 U.S.C. § 832e. This omission supports the view that Congress withdrew rate design and cost allocation issues, which previously were reviewed under the “widest use” standard, from FERC’s jurisdiction under the new Act. Instead, subsection 7(a)(2)(B) reflects the concern that BPA’s customers pay all costs necessary to the production of the power they consume by adding a finding not found in prior statutes, that rates must be based upon BPA’s total system costs. See 16 U.S.C. § 839(4) (declaration of purpose). We conclude that Congress, by selectively enumerating the findings that FERC was required to make, did not intend FERC review for compliance with all governing statutes and that Congress thus withdrew issues of rate design and cost allocation. That conclusion is reinforced by the fact that review for compliance with all applicable statutory standards would have entailed a substantial expansion of FERC’s review responsibilities once the Act took effect. See Hearings, supra, at 196. The legislative history reflects, however, that Congress meant to avert costly and protracted proceedings by prescribing the appropriate standards to be applied by BPA. See 126 Cong.Ree. S11597 (daily ed. Aug. 3, 1979) (statement of Sen. McClure), reprinted in BPA Legislative History at 433; 126 Cong.Ree. S11599 (daily ed. Aug. 3, 1979) (remarks of Sen. Jackson), reprinted in BPA Legislative History at 435. In light of the far more detailed rate directives to BPA that the Act contains, the congressional intent to avoid rate-making delay is served only if the substantive scope of FERC review has been limited. The only statutory language which petitioners use to support the theory of broader review is the phrase “confirmation and approval.” 16 U.S.C. § 839e(a)(2). Because that phrase was used in all of the prior power marketing statutes, these parties argue that it is a term of art, and that Congress used it to direct FERC to perform review under the substantive provisions of those statutes. This argument cannot be sustained because, under the pri- or statutory scheme, the FPC and later FERC unquestionably drew their review authority from the substantive terms of 'the rate-making statutes, not from any independent definition of confirmation and approval. Our conclusion is also borne out by the Act’s provision for judicial review of BPA rates. The provision for judicial review was added by amendment in the Senate. See 126 Cong.Ree. S11597 (daily ed. Aug. 3, 1979), reprinted in BPA Legislative History at 433. Senator McClure, who had previously attempted unsuccessfully to expand FERC’s authority, explained the amendment as follows: The Administrator’s ratemaking under the bill must be approved by the independent Federal Energy Regulatory Commission and will be subject to strict administrative procedures and judicial review involving the requirement for the Administrator to affirmatively prove that his rates are consistent with the criteria in the bill____ 126 Cong.Ree. S11595 (daily ed. Aug. 3, 1979), reprinted in BPA Legislative History at 431. He noted that without the amendment, virtually none of BPA’s powers would be subject to administrative procedure protections or judicial review. Id. at S11594, BPA Legislative History at 430. Although the precise language of the amendment did not survive, the Act now explicitly provides that rate determinations shall be reviewed by this court to determine whether they are supported by substantial evidence in the rulemaking record. 16 U.S.C. § 839f(e)(2). To avoid delay, Congress attempted to streamline review; rates are not considered in the district court, but are challenged directly in the court of appeals. See 16 U.S.C. — 1116 — § 839f(e)(5).. The provision for judicial review thus was intended to accomplish the twin objectives of providing review based on prior statutory standards, yet avoiding the delay that would result from requiring such review by either FERC or the district court. V. OVERVIEW OF RATE DEVELOPMENT AND RATE-MAKING STANDARD OF REVIEW BPA operates on a self-financing basis so that it must establish rates to recover the costs of acquisition, conservation, and transmission of electric power, including the amortization of the Federal investment. 16 U.S.C. § 839e(a)(l). The statute also requires that rates be as low as possible consistent with sound business principles. Id. See 16 U.S.C. §§ 825s; 838g. To meet these objectives, BPA performed a revenue study and a series of cost allocation studies. See Bonneville Power Administration, United States Department of Energy, Administrator’s Record of Decision 1981 Transmission Rate Proposal and 1981 Wholesale Power Rate. Proposal (June 1981) (hereinafter Record of Decision). First, BPA conducted a repayment study to determine the overall revenue needed to recover costs and repay the Federal investment. Record of Decision IV 1-17. After determining revenue needs, BPA performed five studies to allocate its revenue requirements among the classes of customers it serves. The first of these studies was the Long Run Incremental Cost Analysis (LRIC). BPA predicted future energy, capacity, and transmission demands on its system and the cost of meeting those demands. The LRIC allowed BPA to factor into rate design prospective estimated costs rather than embedded, or historical costs. Record of Decision V 1-8. BPA then performed the Cost of Service Analysis (COSA) to determine the cost of serving particular classes of customers. Record of Decision VI 1-20. The Time Differentiated Pricing Analysis (TDPA) measured how costs vary with season and time of day. Record of Decision VII 1-3. The Transmission Rate Design Study (TRDS) incorporated the results of the previous studies to arrive at transmission rates. Record of Decision VIII1. The Wholesale Power Rate Design Study (WPRDS) set the final power rate schedule by combining the information from the previous studies' and making certain adjustments. Record of Decision IX 1-35. BPA originally published the studies on February 17, 1981 in support of the initial rate proposals. See- 46 Fed.Reg. 12,659 (1981). Public hearings began on March 2 and concluded on May 4, 1981 for the wholesale power rates and May 27, 1981 for the transmission rates. After the hearings, BPA issued a final revised repayment study followed by its revised 1981 power and transmission rates. See Record of Decision I 1-3. The rates set by BPA became final upon confirmation and approval by FERC. 16 U.S.C. § 839e(a)(2). In this proceeding no party challenges FERC’s order of confirmation and approval. Therefore, we review only BPA’s actions. We review questions of law to determine whether “BPA’s interpretation of the Act is reasonable.” Central Lincoln I, 686 F.2d at 711. Because BPA helped draft and must administer the Act, we give substantial deference to BPA’s statutory interpretation. Id. at 710-11. As for the rates, the Act sets out a specific standard of review. Section 839f(e)(2) requires this court to affirm the rates if “substantial evidence in the rulemaking record” supports BPA’s determination. 16 U.S.C. § 839f(e)(2). VI. ALLEGED IMPROPRIETIES IN BPA’S RATE-MAKING PROCEDURES Before reaching the merits of petitioners’ various challenges to the 1981 rates, we must address several claimed procedural irregularities in the manner in which BPA arrived at those rates. A. BPA’s Waiver of Notice of Proposed Rule Making On. February 10, 1981, BPA published notice of the rules of procedure that would — 1117 — govern its 1981 rate-making. 46 Fed.Reg. 11,697 (1981). It made the rules effective immediately, but announced that it would accept comments on them through February 27. Id. BPA stated that time constraints precluded any meaningful opportunity for pre-publication notice and comment: [T]o carry out its obligations under the Act, Bonneville must insure that its rate development process, including the hearings provided for herein, is completed by July 1, 1981, an extremely short period for developing wholesale power rates, of the magnitude and complexity that Bonneville has identified will be necessary. Id. With two exceptions, the Administrative Procedure Act (APA) requires an agency to publish notice of proposed rule making thirty days before the rules take effect. 5 U.S.C. § 553 (1981). The first exception is for interpretative and procedural rules. See 5 U.S.C. § 558(b)(A). We agree with petitioners that that exception is not applicable because these rules had some substantive effect, particularly in connection with their definitions of key terms. Therefore, the issue is whether BPA’s action falls within the second exception to the advance notice requirement. That exception applies when the agency has “good cause” to believe the process would “be impracticable, unnecessary, or contrary to the public interest.” 5 U.S.C. § 553(b)(B). We conclude that the good cause exception does apply. Time constraints beyond BPA’s control made it “impracticable,” as that term is used in the APA for BPA to fulfill its rate-making functions under the new statute without dispensing with the public comment period before the rules became effective. As BPA noted, the most obvious constraint was its pre-existing contractual commitment to complete all rate adjustments by July 1. Another constraint was statutory; section 7(i) of the Act requires extensive hearings to guarantee public involvement in the rate-making process. This congressional goal could be achieved only through swift implementation of the rules governing those hearings. The mandatory hearings and the July 1 contractual commitments combined to create a schedule similar to that which caused this court in Arizona State Department of Public Welfare v. Department of Health, Education, and Welfare, 449 F.2d 456, 481 (9th Cir.1971), cert. denied, 405 U.S. 919, 92 S.Ct. 945, 30 L.Ed.2d 789 (1972), to hold that good cause existed to dispense with notice and comment procedures. See also American Transfer & Storage Co. v. ICC, 719 F.2d 1283 (5th Cir.1983); Council of Southern Mountains, Inc. v. Donovan, 653 F.2d 573 (D.C.Cir.1981); Northwest Airlines, Inc. v. Goldschmidt, 645 F.2d 1309 (8th Cir.1981). Courts have been reluctant to find good cause where the agency delayed action until a statutory deadline pressed upon it. See, e.g., Western Oil and Gas Association v. Environmental Protection Agency, 633 F.2d 803 (9th Cir.1980); United States Steel Corp. v. Environmental Protection Agency, 595 F.2d 207 (5th Cir.), clarified 598 F.2d 915 (1979). In this case, however, given the complexity of the rule making and the fact that the Act did not become law until December 5, 1980, we cannot say that BPA was dilatory in promulgating the rules. B. The Claimed Need for New Notice and Comment After Revision of the Rates and the Repayment Study Throughout the spring of 1981 BPA held hearings on the proposed 1981 rates as required by section 7(i) of the Act. 16 U.S.C. § 839e(i). Following the hearings, the Administrator published revised rates without holding any additional hearings. PGP contends that section 7(i) requires new hearings to be held if the final rates differ from those originally proposed. Section 7(i)(4) provides that “the Administrator may propose revised rates, publish such proposed rates in the Federal Register, and conduct additional hearings.” 16 — 1118 — U.S.C. § 839e(i)(4). Section 7(i) clearly requires the Administrator to hold hearings after the rates are originally proposed. Nothing in the statute, however, mandates the repetition of the hearing process each time a rate is revised. Such a requirement makes little practical sense because it would discourage the Administrator from making use of the information gathered during the hearing to improve the final rate structure. Case law under the APA has recognized that “the requirement of submission of a proposed rule for comment does not automatically generate a new opportunity for comment merely because the rule promulgated by the agency differs from the rule it proposed, partly at least in response to submissions.” International Harvester Co. v. Ruckelshaus, 478 F.2d 615, 632 (D.C.Cir.1973) . As the District of Columbia Circuit noted, a contrary rule would lead to the absurd result that an agency could benefit from comments on its proposals “only at the peril of starting a new procedural round of commentary.” Id. at 832 n. 51. In American Transfer & Storage Co. v. ICC, the Fifth Circuit stated that even if a final rule contains substantial differences from the proposed rule, the agency does not automatically have to engage in a new round of notice and comment. 719 F.2d at 1303. Similarly, in a case upholding the Environmental Protection Agency’s regional air quality transportation control plan although it differed from the plan proposed in a prior notice, the First Circuit declared: “A hearing is intended to educate an agency to approaches different from its own; in shaping the final rule it may and should draw on the comments tendered.... Parties have no right to insist that a rule remain frozen in its vestigal form.” South Terminal Corp. v. Environmental Protection Agency, 504 F.2d 646, 659 (1st Cir.1974) . This court has stated that the APA “does not require an agency to publish in advance every precise proposal which it may ultimately adopt as a rule.” California Citizens Band Association v. United States, 375 F.2d 43, 48 (9th Cir.), cert. denied, 389 U.S. 844, 88 S.Ct. 96, 19 L.Ed.2d 112 (1967). The main concern is to ensure that the final rule is sufficiently related to the proposed rule that the challenging party had notice of the agency’s contemplated action. See Daniel International Corp. v. Occupational Safety and Health Review Commission, 656 F.2d 925, 931-32 (4th Cir.1981); American Iron & Steel Institute v. Environmental Protection Agency, 568 F.2d 284 (3d Cir.1977). Petitioners do not contend that any of the revisions were excessive; they challenge the agency’s right to make any revisions at all without new opportunity for comment. The cases, however, support BPA’s position that it was entitled to make at least some revisions of the 1981 rates based on the information it gathered at the rate-making hearings without conducting a new round of commentary. We therefore hold that the final revision of these rates did not trigger any requirement for a new section 7(i) hearing. We similarly hold that BPA’s revision of the repayment study, after the original notice and comment, required no new notice and comment. PGP argues that section 7(i)(2)(A), which provides parties a right to rebut materials “submitted” to or by BPA, compelled BPA to allow parties an opportunity to rebut the revised repayment study. Section 7(i)(2)(A) ensures that BPA creates a complete administrative record, allowing all interested parties to participate in a meaningful way. This does not mean, however, that each time BPA adjusts the conclusions to be drawn from the record, new notice and comment must begin. Our holding is further supported by the language of section 7(i)(5), which provides no right of rebuttal for materials “developed” by the Administrator, presumably in response to received commentary. The parties have indicated neither the kind of rebuttal they would have made, nor suggested that the revisions were in fact based upon any material not already contained in the record. No purpose would be served — 1119 — by requiring yet another round of notice and comment. C. Ex Parte Communications The State Commissions, IOUs, and PGP contend that BPA violated the APA by conducting ex parte communications with the DSIs that were not included in the administrative record for the 1981 rates. The communications were two letters from BPA to the DSIs concerning ongoing contract negotiations. According to the petitioners, the letters contained agreements, relating primarily to power purchases outside the region and Firm Energy Load Carrying Capacity (FELCC) shift, that controlled the outcome of several issues in the rate-making proceeding. In response, BPA argues that the rate-making proceedings were not subject to the APA’s ban on ex parte communications. This argument is unavailing. Section 553(c) of the APA states that when “rules are required by statute to be made on the record after opportunity for an agency hearing,” the procedural rules of sections 556 and 557 apply. See 5 U.S.C. §§ 553(c), 556, and 557. Section 557(d) prohibits ex parte communications relevant to the merits of the proceeding. This prohibition against ex parte communications applies to BPA’s rate-making proceedings. The Act requires the Administrator both to hold one or more hearings related to the proposed rates, 16 U.S.C. § 839e(i)(2), and to make a final decision “based on the record,” 16 U.S.C. § 839e(i)(5). Therefore, section 7(i) triggers the APA’s ex parte rules. Nevertheless, we decline to hold that these two letters constitute grounds for re-opening BPA’s entire 1981 rate-making. As a federal power marketing agency, BPA must engage in regular business dealings with its customers. In recognition of this fact, section 5(g)(1)(D) of the Act, 16 U.S.C. § 839c(g)(l)(D), specifically authorizes BPA to conduct contract negotiations with the DSIs independent of the rate-making process. No allegation of bad faith has been made against BPA for failing to include the letters in the administrative record. See Hercules, Inc. v. Environmental Protection Agency, 598 F.2d 91, 123 (D.C.Cir.1978); see also Public Power Council v. Johnson, 674 F.2d 791, 794 (9th Cir.1982). Nor can petitioners claim that they were unaware that BPA was statutorily required to engage in negotiations regarding the DSIs’ long-term power supply contracts. See Chicago, Milwaukee, St. Paul and Pacific Railroad v. United States, 585 F.2d 254, 263 (7th Cir.1978). More important, the petitioners have not shown how the two letters could have affected the merits of the 1981 rate-making. See H.R.Rep. No. 880, Part I, 94th Cong., 2d Sess. 20-21, reprinted in 1976 U.S.Code Cong. & Ad.News 2183, 2202 (relevance of ex parte communications depends on “whether a particular communication could affect the agency’s decision on the merits”). See also Rogers Radio Communications Services, Inc. v. Federal Communications Commission, 593 F.2d 1225, 1233-34 (D.C.Cir.1978). The letters themselves concern power supply, not rates. They do not discuss, for example, how the cost of purchasing power outside the region should be spread among BPA’s customers. Thus, at the time it decided the 1981 rates, BPA was free to impose the entire incremental cost on the DSIs if it chose to do so. Given the absence of evidence that BPA relied on the two letters when it decided the 1981 rates, the lack of bad faith, and the statutory authorization for BPA to conduct independent negotiations, we hold, in the circumstances of this case, that the letters were not ex parte communications that BPA was required to include in the administrative record for the 1981 rate-making. D. Marketing Policy Formulation Procedures BPA’s marketing policy governs the manner in which BPA sells, exchanges, or otherwise disposes of electric power and energy. The Marketing Policy Formulation Procedures (MPFP) provide for notice and comment before BPA implements or amends its marketing policy. See 45 Fed. — 1120 — Reg. 73,531 (1980). PGP contends that BPA committed reversible error when it changed certain of its assumptions regarding the allocation of secondary energy without following the MPFP. PGP’s contention is without merit. The MPFP does not apply where “other procedures are expressly provided by law.” 45 Fed.Reg. 73,531 (1980). BPA treated its secondary energy assumptions as part of rate-making, not marketing policy. Thus, the assumptions were subject to the express provisions governing rate-making procedure contained in. section 7(i) of the Act. 16 U.S.C. § 839e(i). To the extent that there is any difference between the two procedures, it is that the section 7(i) procedures guarantee more opportunities for public notice and comment than the MPFP. Since BPA followed other express statutory procedures when it changed its assumptions, the MPFP did not apply, and the changes were not procedurally defective. VII. CHALLENGES TO THE MERITS OF THE 1981 RATES A. Refunds Pursuant to Central Lincoln I This court has held that certain power contracts offered to the DSIs under the Act were invalid. Central Lincoln I, 686 F.2d 708, 714 (9th Cir.1982), cert. granted, 460 U.S. 1050, 103 S.Ct. 1496, 75 L.Ed.2d 928 (1983). Our opinion concluded that the contracts violated the Act’s preference clause, 16 U.S.C. § 839c(a), because they provided that BPA would commit non-firm energy to the DSIs before offering it to preference customers. Our opinion remanded tó BPA for further action. Id. at 715. We stayed issuance of our mandate pending Supreme Court action on the case. In the present case PGP contends that, as a result of our opinion in Central Lincoln I, it is entitled to a refund as a preference customer. PGP asks this court to appoint a master to hear the evidence as to the amount of the refund due its members. This court’s retention of jurisdiction to determine the amount of the refund due preference customers would be inconsistent with our opinion in Central Lincoln I, since there we remanded to BPA to decide just such questions. Moreover, in the event that the Supreme Court reverses Central Lincoln I and holds that the BPA contracts with the DSIs should be enforced, PGP would have no refund claim. Accordingly, PGP is not entitled in this action to pursue the refund claim. B. The Repayment Study BPA conducted a repayment study to determine what overall revenue level would be necessary to recover its costs, including the amortization of the Federal investment. Several petitioners have challenged aspects of the methodology BPA used in connection with that study. PGP argues that use of a fiscal year (October 1, 1981 to September 30, 1982) rather than a rate year (July 1, 1981 to June 30, 1982) was erroneous. PGP also argues that BPA should have taken into consideration certain advantageous long-term contracts that would have had the effect of reducing projected revenue needs. The IOUs and State Commissions challenge the repayment study’s assumption that transmission facilities have a life of thirty-five years, and contend that BPA should have updated the study on which that figure was based. The thrust of all of these challenges is that the repayment study overestimated BPA’s revenue requirements, resulting in inflated rates. The parties, however, cite to nothing in the statute that requires the alternatives they describe as more desirable, nor have they demonstrated in their briefs to this court that BPA’s decisions were either unreasonable or unsupported by evidence in the record. More important, FERC concluded in its review for conformity with section 7(a)(2) that BPA had not overestimated revenue needs. FERC’s main concern was that BPA had underestimated, not overestimated, the amount of revenue needed to repay the Federal investment. See Federal Energy Regulatory Commission, United States Department of Energy, Order Confirming and Approv — 1121 — ing Rates on a Final Basis, Docket Nos. EP 81-2011-000, EF 81-2021-000, and EF 82-2011-001 (June 15, 1983) (hereinafter FERC Order).7 Petitioners therefore have failed to establish any basis for holding that the revenue estimate was too high. C. Bias in the Direction of Effort Study BPA used a Direction of Effort Study as the first step in the larger undertaking of assigning costs to customers, the Cost of Service Analysis (COSA). In preparing its Direction of Effort Study, BPA instructed its managers how to assign costs among various functions when the actual source of the cost was not clear. The IOUs and State Commissions argue that these instructions were biased against customers with heavy transmission costs because the instructions assigned to the transmission function the costs that were not readily attributable to any other function. No specific reason other than the self-interest of the petitioners is given for requiring a different assignment of costs. FERC considered petitioners’ arguments in its review of the transmission rates and concluded that the instructions would yield reasonable cost allocation results. FERC Order at 10. Since no petitioner has challenged FERC’s findings in this regard, we hold that the Direction of Effort Study was not improperly biased. D. Classification of Costs Between Energy and Capacity After the Direction of Effort Study, the next step in the COSA was classification of generation costs as energy or capacity. “Energy” as used in this context is the total production of electricity over a given period of time. “Capacity” is the maximum output of the system at a given moment. Record of Decision V 1-6. The system must produce enough “energy” to meet customer requirements over an extended period of time and must also have the “capacity” to meet the highest peak electricity demand during that period. Since the cost to BPA of producing energy and capacity is different, the Administrator tried to factor the difference into the rates as part of the COSA. The theory was to encourage efficiency and conservation by enabling customers to make informed consumption decisions based on the costs of producing each type of electric power. To further improve the accuracy and usefulness of the energy/capacity classification procedure, BPA developed á Long Run Incremental Cost Study (LRIC). Record of Decision V 1. The LRIC attempted to price electricity on the basis of the cost of producing it in the future, rather than on the embedded costs of production. It projected that in the Northwest the power sources necessary to satisfy relatively constant new energy demand would be expensive thermal plants. Record of Decision V 4-6. Capacity, on the other hand, could be increased more cheaply by adding powerhouses to existing dams. Record of Decision Y 1-4. Since new powerhouses cannot produce constant electricity, but can only generate in times of water surplus, they cannot meet the growth of energy demand, but can increase overall capacity. The LRIC allowed BPA to build these considerations into rates, thus “signaling” wholesale customers to restrict new energy demand when possible, and to channel new demand toward capacity electricity. For purposes of the LRIC, BPA used the cost of the nuclear power plants then under construction in the State of Washington as the yardstick for new energy costs because it appeared that such plants would be the principal source of new energy. It used hydro powerhouses as the yardstick for capacity costs because they add capacity at lower cost. The LRIC indicated that ener — 1122 — gy costs would increase much faster than capacity costs. Record of Decision V 3-4. Thus, users like IPC/St. Regis and PGP, whose average demand is close to their peak demand, are charged higher rates because of the LRIC’s conclusions. Not surprisingly, these petitioners challenge the use of the LRIC to classify generation costs between energy and capacity. At the outset, it should be noted that the parties do not challenge BPA’s use of nuclear power plants to measure energy costs. Indeed, in proceedings before BPA the question was not whether nuclear power should be used, but which nuclear power plants accurately represented the cost of new energy production. Record of Decision V 5. Although in retrospect, use of the Washington nuclear plants as a measure of energy costs appears incorrect, see Chemical Bank v. Washington Public Power Supply System, 99 Wash.2d 772, 666 P.2d 329 (1983), it is not claimed that it was an unreasonable choice when made. Rather, the parties contest the use of any incremental cost study to allocate costs between energy and capacity. Thus petitioners’ first contention is that the LRIC is inconsistent with the statutory purpose of keeping rates as low as possible, consistent with sound business principles. They argue that Congress intended billing credits and conservation programs, rather than a LRIC approach, as the only permissible ways for BPA to achieve conservation and efficiency. The legislative history cited by IPC/St. Regis does not demonstrate that Congress rejected a LRIC approach. Instead, it shows only that Congress rejected a “mul-ti-tier pricing” amendment that would have mandated direct assignment of the cost of new energy sources to certain customer classes. See 126 Cong.Rec. H10,526-27 (daily ed. Nov. 12, 1980), reprinted in BPA Legislative History at 171-72. The LRIC is a much less drastic method aimed at sending cost signals to all classes of customers. Furthermore, the Act specifically allows the Administrator latitude in choosing rate forms. See 16 U.S.C. § 839e(e). Because a main purpose of the Act is to encourage conservation and efficiency, 16 U.S.C. § 839(1), the Administrator is given discretion to achieve these purposes through rate design. That the Act specifies certain methods of conservation cannot reasonably be read to prohibit other conservation measures. Indeed, the House Interior Committee comments on 16 U.S.C. § 839e(e) specifically state that the statute permits rate forms “designed to give BPA customers price signals,” such as the LRIC. House Report, Part II, supra, at 53. The second contention, which relies on the Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968), is that BPA’s failure to consider the impact of the LRIC study on high load factor customers necessitates remand. In the Permian Basin Area Rate Cases, the Supreme Court construed the Natural Gas Act of 1938 as requiring the Federal Power Commission to consider the “consequences for the character and development of the industry” when establishing rates. Id. at 792, 88 S.Ct. at 1373. These cases are unpersuasive authority for setting aside BPA’s use of a LRIC to classify costs between energy and capacity. First, the Permian Basin cases concerned a challenge by natural gas producers to a Federal Power Commission order prescribing maximum rates for sales of natural gas produced in the Permian Basin. The Court held that Federal agencies that regulate utility rates must consider the effects of direct price regulation on the regulated industry. Id. In the present case, however, BPA is not directly regulating the petitioners’ business activities. Possible indirect effects on these industries from rising electric rates is not comparable to direct price regulation by the Federal government. Furthermore, the Act sets out a comprehensive list of requirements to be satisfied by BPA in its rate-making activities. 16 U.S.C. § 839e. The Act does not impose any requirement similar to the Natural Gas Act’s requirement that there be — 1123 — special consideration of the industries represented by these petitions. Consequently, we hold that BPA’s use of the LRIC was not contrary to the Act. E. Rate Pools BPA must serve various groups of customers, including the preference and IOU residential customers, the DSIs, and the IOU nonresidential customers. In setting rates, BPA allocated costs of power resources among these three groups by the creation of three rate pools. The IOUs object to the creation of the three rate pools because it allegedly has resulted in a disproportionate allocation of the high costs of new resources to the IOUs. They argue that there should be only two rate pools, one of which would include both the IOUs’ nonresidential customers and the DSIs, so that the DSIs’ rates would include new resource costs on the same basis as the IOUs’ rates. In support of their argument, the IOUs point to no language in the statute mandating that they be treated on the same basis as the DSIs. They look instead to Appendix B of the report of the Senate Committee on Energy and Natural Resources which suggests that, before June 1985, only two basic rate pools should exist. See Senate Report, supra, at 56-57. The import of this language is questionable, however, because the appendix states that the new resource rate applies to “utilities” and the DSIs are not utilities, and also because the appendix was incorporated into the Senate Report with reservations. Id. Furthermore, other legislative history suggests that BPA has the discretion to treat DSIs in a separate rate pool. Both House Reports and the Senate Report contain language indicating that only the DSIs, not the IOUs, should pay the exchange resource costs that the preference and IOUs’ residential customers do not pay. See House Report, Part II, supra, at 35; House Report, Part I, supra, at 29-30; Senate Report, supra, at 459. More important, the statutory language itself gives BPA discretion to deal separately with IOUs and DSIs. Section 7(b)(1), 16 U.S.C. § 839e(b)(l), provides a rate for BPA’s public body, cooperative, Federal agency customers within the Pacific Northwest, and specified loads of other electric utilities. Section 7(c), 16 U.S.C. § 839e(c), provides for establishment of rates for BPA’s DSI customers. Section 7(f), 16 U.S.C. § 839e(f), governs rates for all other firm power sales in the region. Each of these three sections contains different combinations of priorities of resources on which the rates should be based. Since the Act itself separates the DSIs and the IOUs for rate-making purposes, BPA’s decision to put them into different rate pools is consistent with the Act. F. Allocation of Fish and Wildlife Costs To protect spawning fish swimming upstream and young fish swimming downstream, BPA must install fish passage facilities at federal dams on the Columbia River System. Pursuant to section 7(g) of the Act, 16 U.S.C. § 839e(g), BPA allocated the cost of the passage facilities to all of BPA’s customers. The DSIs contend that this was error because fish passage facility costs are directly related to hydroelectric plants and should be borne'by the preference customers who most benefit from these facilities. To support their position, the DSIs cite section 4(h)(10)(C) of the Act, 16 U.S.C. § 839b(h)(10)(C), which provides: The amounts expended by the Administrator for each activity pursuant to this subsection shall be allocated as appropriate by the Administrator, in consultation with the Corps of Engineers and the Water and Power Resources Service, among the various hydroelectric projects of the Federal Columbia River Power System. Amounts so allocated shall be allocated to the various project purposes in accordance with existing accounting procedures for the Federal Columbia River Power System. When section 4(h)(10)(C) is placed in the context of the Act as a whole, the DSIs’ interpretation is not persuasive. Section 7(g) states that unless otherwise provided, — 1124 — costs and benefits, including fish and wildlife measures, shall be equitably allocated to power rates. In light of section 7(g), a more reasonable interpretation of section 4(h)(10)(C) is that it governs BPA’s decision to install a fish protection facility at a particular project by controlling the allocation of expenditures, not the recovery of costs. BPA’s cost allocation to all customers appears equitable since all users benefit in some fashion from hydro resources. Since BPA’s interpretation is consistent with section 7(g), we uphold it. G. Inclusion of Saturday as a Peak Period Because electricity demand varies with time of use, BPA performed a Time-Differentiated Pricing Analysis (TDPA) to measure long run incremental costs and embedded costs at various periods. Record of Decision IX 2. As a result, the Wholesale Power Rate Design Study (WPRDS) established three wholesale capacity rate periods for embedded costs: winter peak, summer peak, and offpeak. Id. In so doing, BPA classified Saturdays as a peak period, even though the TDPA showed that Saturday power usage more closely resembled Sunday usage, which is offpeak, rather than weekday usage, which is peak. PGP argues that inclusion of Saturday in the peak period is arbitrary and asks this court to order BPA to treat Saturday as offpeak. We find that the record adequately supports BPA’s decision to treat Saturday as peak. The TDPA showed that, in reality, Saturday belonged to an intermediate peak period. Since BPA had two time categories, peak and offpeak, it had to choose how to treat Saturdays. BPA justified categorizing Saturday as peak on the grounds that: (1) treating Saturday as nonpeak might cause load shifting so that in the future, Saturday would have to be reclassified as peak; and (2) the classification helped achieve rate continuity and prevented conflict with existing contracts. Record of Decision IX 2-3. Petitioners point to nothing in the record to dispute these justifications. We therefore uphold BPA’s classification. H. Equalization of Demand Charge On the basis of the COSA, BPA determined that, although there was a difference in the cost of providing capacity to different classes of customers, the difference was not significant, and, therefore, BPA equalized their demand charges. PGP argues that since the COSA indicated that PGP’s capacity costs were lower than those of other customer classes, BPA’s equalization resulted in an unjustifiable overcharge. Both PGP and BPA point to section 7(e) in support of their positions. Section 7(e) states: Nothing in this chapter prohibits the Administrator from establishing, in rate schedules of general application, a uniform rate or rates for sale of peaking capacity or from establishing time-of-day, seasonal rates, or other rate forms. 16 U.S.C. § 839(e) (emphasis supplied). PGP contends that section 7(e) allows equalization of demand charges only between customers in a given class, not between different classes of customers. BPA’s response is that section 7(e) gives it complete latitude to establish uniform rates. We do not find the language of the statute dispositive; it contains neither a blanket prohibition nor a blanket authorization for equalization of demand charges in all circumstances. BPA’s stated reason for equalizing the demand charges was that the difference between charges was relatively small and that equalization facilitated rate continuity and administrative ease. Record of Decision IX 11. Its finding that the difference was relatively small is supported by the Record. Absent any information that PGP can point to in the Record demonstrating that the charge differential was too great to be equalized for administrative efficiency, we decline to hold that BPA’s actions were unreasonable. — 1125 — I. Allocation of Secondary Energy to Nonpreference Customers BPA studies projected a possible long run deficit in firm power available to meet BPA’s firm commitments. Accordingly, BPA planned to use both secondary power, that is, nonfirm power shifted to meet firm needs, and thermal power purchased outside the region to fill the firm power deficit. In allocating between customer classes the cost of making up the deficit, BPA first divided the available secondary energy between two rate pools: the section 7(b) pool consisting of preference customers, and the section 7(f) pool consisting of some of the nonpreference customers, including the DSIs. After allocating the available secondary energy, BPA then divided the more expensive thermal power. PPC, a preference customer, argues that dividing the cheaper secondary energy between the 7(b) and 7(f) rate pools contradicts Central Lincoln I because it violates the preference clause contained in section 5(a) of the Act. 16 U.S.C. § 839e(a). BPA’s decision to allocate secondary energy between rate pools, however, is distinguishable from the BPA action challenged in Central Lincoln I. There, this court invalidated contracts between BPA and the DSIs that allocated nonfirm power to the DSIs’ top quartile. See 686 F.2d at 715. Central Lincoln I held that nonfirm power was subject to the preference. Id. At issue here is BPA’s use of secondary energy to satisfy the firm power obligations imposed by sections 5(b), (c), (d), and (f) of the Act. 16 U.S.C. § 839c(b), (c), (d), (f). We hold that the preference clause does not prevent BPA from meeting its statutory obligations to satisfy the firm needs of its nonpreference customers. In a situation when BPA is shifting energy to meet firm power needs, an interpretation of section 5(a) allowing preference customers to exercise the preference after their firm power needs are met but before the firm power requirements of the non-preference customers are satisfied would subject BPA to conflicting obligations under the Act. BPA could honor the section 5(a) preference only at the risk of breaching its firm power obligations to the non-preference customers. See 16 U.S.C. § 839c(b), (c), (d), (f). PPC’s premise is that the preference entitles its members to purchase not just available power, but the cheapest available power. PPC bases its contention on language in the House Commerce Committee Report that reads: [Sjpecific provisions incorporated in the Committee Amendment are designed to protect the entitlement of both existing and new preference customers to the full Federal base system. These provisions seek to protect preference as to both supply and price. House Report, Part I, supra, at 34 (emphasis supplied). That language, however, is not disposi-tive. The statute itself couches the preference in terms of “power sales,” not price. See 16 U.S.C. § 839c(a). In addition, the section-by-section analysis of the Act states that section 5(a), the preference clause, must be read “in tandem with” other provisions of the Act. BPA Legislative History at 84. One of those provisions is section 7(b), 16 U.S.C. § 839e(b), which contains a rate ceiling for preference customers. The conclusion to be drawn from reading sections 5(a) and 7(b) together is that while section 5(a) protects the preference customers’ access to power supply, section 7(b) protects their right to purchase power at a reasonable price. See BPA Legislative History at 84-85. See also Western Area Power Administration, 25 FERC 11 61,325 (1983). Neither Central Lincoln I, the statutory language, nor the legislative history indicate that the preference was violated in this case. J. The FELCC Shift Section 5(d)(1)(A) of the Act provides that some sales to the DSIs shall “provide a portion of the Administrator’s reserves for firm power loads within the region.” According to the House Interior Committee Report, that portion is to be approximately twenty-five per cent. House Report, Part II, supra, at 48. Accordingly, the Administrator has treated as “quasi-firm” one quarter of the DSI load, termed — 1126 — the “first quartile.” See Central Lincoln I, 686 F.2d at 710. This first quartile is treated as a reserve available to the Administrator to meet other firm requirements in the event of an energy shortfall. Record of Decision IX 15. The Pacific Northwest Coordination Agreement of 1964 permits the BPA to shift “Firm Energy Load Carrying Capability” (FELCC). Record of Decision IV 12. To do that, BPA first determines for a four-year period the region’s projected loads and the system’s energy capability at the “critical water level.” “Critical water level” is the water level from the period of historical stream flows that would produce the least firm power. See Record of Decision IV-12; Central Lincoln I, 686 F.2d at 710 and n. 1. These projected loads and capabilities are balanced and spread evenly over the four-year period to arrive at the FELCC. FELCC can be “shifted” by drawing the reservoirs down lower than they ordinarily would be permitted to fall during the first of the four years, thereby, in effect, borrowing power from future years. If greater than critical water levels occur in the subsequent years, then the FELCC shift allows BPA to market more energy than otherwise would be possible. The FELCC can be classified in two categories. Regular FELCC is that amount of power needed by BPA to assure service to its firm loads. “Surplus,” or excess, FELCC is power that BPA does not need to assure service to its firm loads. BPA determined that the first DSI quartile could be served by shifting regular FELCC and retaining a right to interrupt DSI service in subsequent years in the event water flow falls below the critical level. The IOUs and State Commissions challenge this determination, not because the FELCC shift adversely affects their rates, but because it would endanger service to those customers’ firm needs in the event of serious future shortfalls. The support which these petitioners offer for their position is language in Appendix B to the Senate Report which provides that the top quartile: would be served with resources which are in excess of critical planning amounts but operated to meet the entire DSI load as if it were firm. The operation of the System to carry out this purpose results from treating as a firm load the maximum amount of the DSI load (not all of which can be covered under critical stre-amflow planning), to the extent that this maximum load can be met in the initial period of the PNW Coordination Agreement Critical Period [that is, FELCC shift] while protecting firm loads against the worst historical streamflow and maintaining an ability to restrict an equivalent amount of the DSI Loads in the later periods (without provisional or advance energy being made available for this amount of the DSI load). Senate Report, supra, at 59 (emphasis supplied). BPA cites the same language to support its position that the first quartile can be served by shifting regular FELCC. BPA argues that since restriction rights apply only to regular, not surplus FELCC, the Senate language is a clear reference to BPA’s ability to shift regular FELCC in the first year of the critical period. The Administrator’s interpretation is reasonable. We also observe that the Administrator has taken precautions to protect firm loads from worst historical stream flow situations. Record of Decision IV 15. PGP also challenged the use of regular FELCC during the administrative proceedings, but it has advised the court that it reached an accommodation with BPA before our decision in Central Lincoln I so that its challenges to the FELCC shift are now moot. K. Valuation of DSI Reserves BPA’s power sale contracts with the DSIs grant BPA the right to restrict the DSIs' loads under certain conditions. These restrictions create power reserves to protect against blackouts, equipment failures, and delays in completing new plants. See 16 U.S.C. §§ 839a(17), 839c(d)(l)(A). — 1127 — Restriction rights create three types of reserves. Planning reserves allow restriction of a certain percentage of the DSIs’ firm load to protect the system against delays in the construction of new facilities, their unexpected poor performance, or long-term outages. Operating reserves permit restriction of any DSI load not already valued as a planning reserve to meet any system need. Stability reserves enable BPA to interrupt instantaneously a large percentage of the DSI load for a short time if a sudden large loss of power occurs within the system. See 1981 Record of Proceedings Before the Bonneville Power Administration, Yol. I at 368-69 (available at the Ninth Circuit Court of Appeals) (hereinafter Administrative Record). The Act provides that the Administrator shall adjust the DSIs’ “rates to take into account the value of power system reserves made available to the Administrator through his rights to interrupt or curtail service.” 16 U.S.C. § 839e(c)(3). To accomplish this rate adjustment, BPA grants the DSIs reserve credits and thus effectively reduces the rates they must pay. To determine what credits should be granted, the Administrator estimates the value of replacing the DSIs’ reserves. The Administrator then adjusts that value into a rate credit for the reserves. Record of Decision IX 7-8, 18-21. The DSIs contend that the Administrator undervalued the stability reserves, while IPC/St. Regis and PGP contend that the Administrator overvalued the planning reserves. The DSIs also contend that the reserve credit is too low in light of the value of the reserves. Finally, the DSIs contend that BPA is unfairly charging them for the costs of their own reserve credits. BPA presented an adequate explanation of its valuation methods. Record of Decision IX 7-8. Although PGP criticizes the result as being too high, it cites to no evidence supporting that position. In these circumstances we cannot say BPA’s valuation is unsupported by substantial evidence or instruct BPA to reevaluate the reserves based upon consideration of different factors. The DSIs, contending that the valuation is too low, do present alternative methods of valuation. They argue that the stability reserves should bé valued on the basis of cost to BPA of providing alternative generation capacity. BPA responds that the proper measure of the value of the DSI reserves is the cost of an alternative load-dropping scheme, which would be much cheaper than adding generation capacity. The record supports BPA’s position. Finally, BPA’s assessment of a portion of the cost of the reserves to the DSIs by lowering the value of their reserve credit is appropriate because the DSIs are firm power customers who benefit from the reserve. L. Transformation Charges Some customers take power at high voltage levels and others take power at low voltage levels. BPA therefore incurs costs in transforming power to different voltages. In its 1974 rates, effective through 1979, BPA included a transformation charge. Beginning with its 1979 rates, and also in these 1981 rates, BPA eliminated the transformation charge. PGP complains that it relied to its detriment on the continuation of the transformation charge in future rates. The 1981 rate proposal does not attempt to justify the elimination of the transformation charge beyond referring to the 1979 Record of Decision. Record of Decision IX 14. In most circumstances, the lack of any evidence in this record concerning the reasons for the elimination of the charge would require a remand to BPA for additional consideration of the issue and to provide the parties the opportunity to submit evidence. BPA, however, has represented to this court and in the Record of Decision that it is considering and will continue to consider applications by those who have relied to their detriment upon continuation of the transformation charge and that it will take steps to mitigate any adverse impact. See Record of Decision IV 14. Based on those representations, it is not necessary to require any formal remand — 1128 — for purposes of consideration of the transformation charge. M. General Rate Schedule Provisions General Rate Schedule Provisions (GRSPs) are specialized rate-making terms of art used between BPA and its customers. BPA treats GRSPs as part of rate-making, subject to the same annual review and adjustment as the rates themselves. PGP alleges that this causes BPA’s customers a great amount of uncertainty in planning for the future, and raises the possibility that BPA unilaterally will redefine the GRSPs without outside consultation or participation. PGP argues that, as a matter of law, GRSPs should be defined only in BPA’s long-term supply contracts. PGP’s argument fails for several reasons. First, nothing in the Act requires BPA to regard the definitions of GRSPs as part of contractual negotiations rather than as part of rate-making. Moreover, section 5(b)(1) of the Act guarantees that BPA will satisfy the firm power needs of its preference customers, including PGP. 16 U.S.C. § 839c(b)(l). See BPA Legislative History at 84-85 (section-by-section analysis). Because GRSPs can affect only rate-making, not supply, their inclusion in rate-making proceedings causes PGP no more uncertainty than changes in the actual rates. Finally, PGP’s suggestion that BPA will not seek outside participation when it changes the GRSPs is misleading. As part of rate-making, GRSPs are subject to all of the procedural protections set out in section 7(i) of the Act, including notice, comment, at least one public hearing, and the right to cross-examine witnesses. See 16 U.S.C. § 839e(i). In these circumstances, we decline to hold that, as a matter of law, BPA must treat GRSPs as subject to contractual negotiation rather than as part of the rate-making process. N. Transmission Rate Issues BPA adopted two sets of transmission rate schedules. One set updates BPA’s current transmission rates and reflects “historic decisions embodied in the present contractual arrangements.” Record of Decision VIII1. BPA developed a second set to “provide customers with a broader, more flexible service at a uniform rate.” Id. The second set is designed to better meet customer concerns and the full range of BPA rate design objectives. Id. BPA customers may choose which rate schedule is most advantageous to them. Despite this choice, the IOUs, State Commissions, and PGP challenge certain aspects of the transmission rates. The IOUs and State Commissions contend that the transmission rates and services available were not clearly defined and thus customers cannot choose rationally between the two sets. The imprecision arose because BPA provided customers with a choice between a transmission rate schedule based on the extension of current rates and an interim schedule designed to provide experience with new, more flexible transmission rates. That the new rate schedule was still in its experimental stage and thus less well-defined than the previous schedule does not require remand. BPA recognized that the new rates were in the developmental stage and allowed users who did not wish to experiment to continue using the previous rate schedule. Record of Decision VIII 1-16. The IOUs and State Commissions also contend that it is inequitable to allocate transmission costs between wheeling customers and Federal power customers on a similar basis because the service received by each type of customer is different. BPA responds that its transmission cost assessment methodology properly allocates costs by first dividing transmission costs into segments and then dividing the costs between wheeling and Federal customers using each segment. This methodology is explained adequately in the record. Record of Decision VI 1, 7-9, 19-20. Furthermore, in reviewing BPA rates pursuant to the Act, FERC concluded that the transmission costs were equitably allocated. See FERC Order at 10-11. The IOUs and State Commissions do not challenge FERC’s finding. Therefore we will not overturn the transmission rates. — 1129 — PGP, the IOUs and State Commissions contend that the BPA improperly treats the cost of power lost during transmission as a contract matter rather than as a rate matter. BPA asserts that losses are not costs within the meaning of the statute. BPA also argues that its existing contracts treat losses as a contract matter and, because it cannot unilaterally amend these contracts, it could not have changed its transmission loss policy in the short period allowed by the 1981 rate procedure. FERC agrees with BPA that losses are not a cost of transmission within the meaning of the Act. Although FERC has clear responsibility to review the allocation of transmission costs under section 839e(a)(2)(C), FERC did not include consideration of losses in its review of costs. FERC Order at 11. In view of BPA’s history of treating losses as a contract matter and FERC’s unchallenged approval of the practice, we reject petitioners’ contentions. The IOUs and State Commissions contend that the costs of transmission lines over 69kV which serve only the DSIs should be allocated entirely to the DSIs. BPA decided not to allocate these lines to the DSI delivery segment because: (1) it did not do this for other customer classes; and (2) these lines have a higher capacity than needed and it is assumed they will be extended in the future to serve other customers. Record of Decision VI 8. BPA presented evidence that delivery lines above 69kV can eventually serve other customers. Administrative Record, supra, Vol. VIII at 3565. See also Public Service Co. of Indiana, Inc. v. FERC, 575 F.2d 1204, 1217-18 (7th Cir.1978) (if lines capable of carrying power greater than customer needs have functions that will benefit entire system, substantial evidence supports FPC decision that these costs should be “rolled-in” and allocated on demand basis). FERC also agrees that the total cost of these lines should not be assigned to the DSIs. FERC Order at 11. Therefore we reject petitioners’ claims. VIII. CONCLUSION In conclusion, we dismiss for lack of jurisdiction the challenges to the 1981 nonre-gional rates because FERC has not yet confirmed and approved them. We also dismiss those petitions seeking review of the 1981 regional rates that were filed pri- or to FERC’s confirmation and approval order of June 15, 1983. We dismiss the Petitions for Agency Action Unlawfully Withheld as moot. We have reviewed petitioners’ challenges to the merits of the 1981 regional rates as confirmed and approved, and deny the relief requested. Footnotes [1] We have denominated this case Central Lincoln II to distinguish if from Central Lincoln Peoples’ Utility District v. Johnson, 686 F.2d 708 (9th Cir.1982), cert. granted, 460 U.S. 1050, 103 S.Ct. 1496, 75 L.Ed.2d 928 (1983), which we have denominated Central Lincoln I. [2] The Secretary of Energy first placed the rates in effect until June 30, 1982 pursuant to 16 U.S.C. § 839e(i)(6). On June 22, 1982, FERC extended the interim approval of the 1981 rates until January 1, 1983. Order Granting Extension of Interim Rates For A Limited Time, Docket Nos. EF 81-2011-001 and EF 81-2021-001, 19 FERC (CCH) H 61,281 (1982). Although FERC is the agency that has the responsibility to confirm and approve rates on a final basis, or to disapprove them, 16 U.S.C. § 839e(i)(6), the Act provided for a year’s transition period during which the Secretary of Energy would have the authority to grant interim approval to proposed rates. Id. [3] In the event that the California petitioners file new petitions after the nonregional rates become final, upon motion or stipulation of the parties, the briefs already filed in these cases may be transferred to the new cases. The clerk shall retain the briefs already on file. [4] The 1981 rates are no longer in effect. The 1982 rates were granted interim approval and placed in effect by FERC on September 29, 1982, effective October 1, 1982. Order Granting Interim Approval, Granting Waiver, Noting Interventions, Denying Motions and Establishing Procedures, 20 FERC (CCH) f 61,388. Challenges to these rates were brought in Kaiser Aluminum & Chemical Corp. v. BPA, No. 82-7521 (9th Cir. filed Sept. 13, 1982). The issues concerning the 1981 rates are not moot, however. If lower rates are ultimately approved by FERC, revenue collected in excess of such rates may be ordered refunded with interest. 46 Fed.Reg. 33,569 (1981). [5] The California petitioners, who challenge the sale of electricity outside the region under BPA’s nonfirm rate, assert that these are final actions subject to our review. We conclude, however, that these sales constitute an implementation of the BPA’s nonregional rates that are not yet final. [6] In the event that FERC disapproves rates under either section 7(a) or 7(k), FERC must remand the rates to BPA for further proceedings. The California Utilities are alone in arguing that section 7(k) authorizes FERC to set revised rates. Their argument is based on section 7(k)’s invocation of the procedural provisions of the Federal Power Act (FPA) specifically overriding that act’s exemption of federal agencies. See 16 U.S.C. § 824(f). From this, the California Utilities infer that all of the substantive provisions of the FPA are meant to govern the rate review under section 7(k). This is not borne out by the language of section 7(k) itself, which carefully provides the statutory standards that are to govern review, and refers to the FPA in the context of "procedures established for ratemaking.’' The FPA procedures for ratemaking are contained in 16 U.S.C. § 824d. The power of the Commission to fix rates and charges under FPA is set forth in 16 U.S.C. § 824e. That section also provides substantive grounds for invalidating rates that are "unjust, unreasonable, unduly discriminatory or preferential.” Id. The California Utilities do not explain why Congress would provide one set of standards to govern rates in section 7(k) yet would invoke another set of standards to govern any other remedial action. [7] FERC’s concern stemmed, in part, from the fact that BPA’s repayment study for the 1981 rates omitted $200 million in costs associated with the Washington Public Power Supply System (WPPSS) Nuclear Project No. 3. See FERC Order at 6. Since none of the parties in the present case, however, challenge the 1981 repayment study on the basis that the 1981 rates are too low to recover BPA’s costs, the effect of the WPPSS exclusion on the validity of the 1981 rates is not an issue properly before this court.