Power Act.10 Several parties, including Bonneville,11 filed for rehearing of that issue on May 16, 1988, in Docket No. EF87-2011-005.12 By order issued on November 14, 1990, the Commission granted rehearing. The Commission found that only sales of nonfirm power outside the Region must meet the standards of section 7(k), and that sales of firm power outside the Region need only meet the standards of section 7(a).13

On April 14, 1988, Bonneville filed a request for a stay of further Commission action on all pending Bonneville rate filings until the Commission acted on the pending rehearing request or until August 8, 1988, the end of the 120-day period provided for the filing of a substitute for the rejected SL-87. The Commission took no action on the motion. On August 3, 1988, Bonneville requested an extension of four days to file its substitute rates for the rejected SL-87. The extension was granted. On August 12, 1988, as completed on October 14, 1988, Bonneville filed its substitute for SL-87 (Modified SL-87) in Docket No. EF87-2011-007. The Commission granted interim approval to Modified SL-87 on December 1, 1988.14

14

On January 13, 1988, in Docket Nos. EF87-2011-006 and EF87-2021-004, Bonneville filed for approval of the rates it charges under the Pacific Northwest Coordination Agreement (PNCA),15 which provides for the sale and exchange of hydroelectric and thermal capacity and energy and for the storage of water for hydroelectric generation among 16 utilities in the Pacific Northwest.

Bonneville estimates that all of its rates currently on file would produce total annual revenues of about $2.912 billion during fiscal year (FY) 1988 and $2.975 billion during FY 1989. The power rates and the transmission rates for nonfederal power are expected to produce reve

10 16 U.S.C. § 839e(k) (1988).

11 In addition to Bonneville, rehearing was requested by: the Public Power Council, the Association of Public Agency Customers, the Public Generating Pool, the Pacific Northwest Generating Company, the Direct Service Industrial Customers, M-S-R Public Power Agency, Southern California Edison Company, the Department of Water and Power of the City of Los Angeles, the Public Service Department of the City of Glendale, the Public Service Department of the City of Burbank, and the Water and Power Department of the City of Pasadena. Additionally, a notice of intervention was filed, in Docket No. EF87-2011-005, by the Public Utility Commission of Oregon and a motion to intervene was filed by the Washington Water Power Company.

12 On April 21, 1988, the Direct Service Industrial Customers et al., filed a petition with the Ninth Circuit Court of Appeals for review of the April 6, 1988 order. On July 1, 1988, the court dismissed the suit, without prejudice, as being premature. Direct

nues of approximately $2.5 billion and $0.4 billion, respectively.

Bonneville requests final approval of most of its proposed rates and the Impact Aid Methodology for the period October 1, 1987 through September 30, 1989. For Modified SL-87, Bonneville requests final approval for the period December 1, 1988 through September 30, 2010. Bonneville requests extension of current rate schedule UFT-2 for the period October 1, 1987 through June 30, 1990. For SP-87, Bonneville requests approval from October 1, 1987 through September 30, 1992. Bonneville seeks approval of VI-87 for the period October 1, 1987 through July 31, 1993. The requested approval period for rate schedule FPT-87.3 is October 1, 1987 through September 30, 1990. Approval for the PNCA is sought from its effective date of July 1, 1986 until a PNCA party requests Commission approval of revised charges. Bonneville also requests approval of the Nonfirm Energy Rate Cap contained in the General Rate Schedule Provisions for a 12-year period, from October 1, 1987 through September 30, 1999. Finally, Bonneville requests waiver of section 300.1(b)(6) of the Commission's regulations, 16 which limits the approval period to five years.

The Commission published notice of each of Bonneville's filings in the Federal Register," and provided opportunity for public comments.

Twenty-one entities, representing 178 individual parties, submitted timely and untimely comments, motions to intervene, or notices of intervention. 18

Discussion

Under Rule 214 of the Commission's Rules of Practice and Procedure, 19 the timely, unopposed motions to intervene and the timely notices of intervention serve to make those

Service Industrial Customers et al., v. FERC et al., No. 88-7167 (9th Cir. July 1, 1988).

13 United States Department of Energy Bonneville Power Administration, 53 FERC 61,193 (1990).

14 United States Department of Energy - Bonneville Power Administration, 45 FERC ¶ 61,358 (1988).

15 In City of Tacoma, Washington v. Washington Water Power Company et al., 34 FERC ¶ 61,341 (1986), Bonneville had been directed to file its current and future PNCA rates in its regional rate proceedings. Bonneville's filing was in compliance with this decision.

16 18 C.F.R. § 300.1(b)(6) (1990).

17 52 Fed. Reg. 30,721 (1987), 53 Fed. Reg. 3631 (1988), and 53 Fed. Reg. 32,647 (1988).

18 See Attachment for a listing of the intervenors. 19 18 C.F.R. § 385.214 (1988).

movants who filed timely and unopposed motions and notices parties to this proceeding. We find that good cause exists to grant the untimely and the opposed motions to intervene. We are satisfied that in each instance the movants have each expressed an interest in the outcome of these proceedings that may not be represented by another party, that any delay in filing does not adversely affect the outcome of this proceeding, and that their participation is in the public interest.

Scope of Review

In Central Lincoln Peoples' Utility District v. Johnson,20 the court interpreted the Northwest Power Act as setting a narrow scope for Commission review of Bonneville's regional wholesale power and transmission rates. The Commission's review of these rates is limited to a determination of whether they meet the three specific, limited requirements of section 7(a)(2): (1) the rates must be sufficient to assure repayment of the federal investment in the Federal Columbia River Power System over a reasonable number of years after first meeting Bonneville's other costs; (2) the rates must be based on Bonneville's total system costs; and (3) the transmission rates must equitably allocate the cost of the federal transmission system between federal and nonfederal use of the system 21 Under this narrow review, the Commission does not address either rate design or cost allocation between customer classes except as they relate to the equitable allocation of transmission costs between federal and nonfederal users of the federal transmission system.22

Bonneville's rates for the sale of nonfirm federal power outside the Region must also meet the standards of section 7(k) of the Northwest Power Act.23 Bonneville's rates for the sale of firm federal power outside the Region are not subject to the standards of review of section 7(k),24 and are reviewed sub

20 735 F.2d 1101 (9th Cir. 1984).

21 Bonneville's filings must also comply with the financial reporting requirements in the Department of Energy's (DOE) regulation RA 6120.2.

22 735 F.2d at 1115.

23 Section 7(k) provides that the rates must be the lowest possible consistent with sound business principles. Section 7(k) also states that the rates must comply with the standards of the Bonneville Project Act of 1937, the Flood Control Act of 1944, and the Federal Columbia River Transmission System Act.

24 United States Department of Energy - Bonneville Power Administration, 53 FERC ¶61,193 (1990).

25 In Aluminum Company of America v. Bonneville Power Administration, 903 F.2d 585, 591-94 (9th Cir. 1990), the Ninth Circuit held that the Commission may not hold an evidentiary hearing under sec

In developing its proposed 1987 rates, Bonneville conducted a Risk Assessment Analysis26 which concluded that during the rate approval period, October 1, 1987 through September 30, 1989, underrecovery of revenue could be between $350 and $400 million, annually. Consequently, Bonneville utilized three measures, which it labeled a Risk Management Strategy package, to provide risk coverage of up to an estimated $185 million per year during the rate period: (1) basing nonfirm energy projections on 1939 water year conditions; (2) incorporation of an Investment Service Coverage ratio27 of 1.08 as a part of its annual revenue requirement; and (3) provision of a Cost Recovery Adjustment Clause that would allow a limited, one-time, upward or downward rate adjustment based on the first year's actual operations.

The traditional measure of the adequacy of revenues of Bonneville and other DOE Power Marketing Administrations (PMAs) has been the power repayment study. The power repayment study is used to test whether proposed rates will be adequate to ensure the recovery of the costs of providing service, including the amortization of the federal investment, with interest, over the repayment period, usually 50 years. The power repayment study must include a narrative statement explaining how cost recovery can be assured.28

In accordance with a previous Commission directive,29 Bonneville prepared separate studies for generation and transmission elements of the Federal Columbia River Power System. Bonneville's generation power repayment study shows an annual surplus (or uncommit

tion 7(k) to supplement a record the Commission thinks is inadequate. While the court did not completely foreclose the possibility that an evidentiary hearing could be held under other circumstances, we do not anticipate evidentiary hearings in future section 7(k) proceedings.

26 The analysis quantified identified risks by simulating the revenue impact of low aluminum prices, low fuel prices, low regional employment levels, warmer temperatures, reduced contractual surplus power sales, and critical water conditions.

27 The Investment Service Coverage is a contingency fund based on a percentage revenue surcharge on Bonneville's interest costs.

28 18 C.F.R. § 300.12(b)(1990).

29 United States Department of Energy Bonneville Power Administration, 26 FERC (1984).

61,096

ted funds) of about $34 million annually over the repayment period. However, because Bonneville sets rates only at levels high enough to pay current costs with a small level of risk protection, projection of Bonneville's current transmission power repayment study shows an annual revenue deficiency of about $5 to $6 million over the balance of the repayment period.30 The level of deficiency in repayment of the federal investment is not sufficient to 31 convince us to reject the proposed rates.

On the basis of Bonneville's submittals and our own analysis, we find that Bonneville's proposed rates are sufficient to assure repayment of the federal investment over a reasonable number of years after meeting Bonneville's other costs, and that the rates are based on Bonneville's total system costs.

Several intervenors have raised questions regarding Bonneville's submittal. One party takes exception to Bonneville's practice of including both depreciation and future replacement costs in the determination of the required revenue level. This intervenor asserts that Bonneville's filing is double-counting by including monies for depreciation and replacement related to the same asset. However, the Commission has concluded that Bonneville's filing is not double-counting. The depreciation component is not added to the repayment (amortization) component but the greater of annual depreciation or amortization expense is included in the income statement to demonstrate the adequacy of current revenues, thus enabling Bonneville to satisfy both DOE, using repayment accounting, and its independent auditors, using depreciation accounting. Bonneville's approach is reasonable and this methodology does not result in revenues in excess of Bonneville's repayment requirement.

Parties allege that Bonneville has overestiImated its revenue requirement by not assuming the refinancing of high-interest bonds. The interest rates on these bonds range from 8.95 percent to 14.40 percent, with principal amounts ranging from $29 million to $140 million. In the past, Bonneville has demonstrated that it makes use of any opportunity to reduce its interest expenses, and Bonneville has indicated that it will continue to do so. Any estimate of when and at what cost, and in what amounts, Bonneville would refinance any of its bonds, or whether it would be able to at all, however, would at this time be extremely spec

30 We note that Bonneville has taken steps to address this revenue deficiency in its 1989 submittal, which includes a transmission power repayment study that shows no revenue deficiency.

31 The deficiency is less than two percent of the transmission revenues.

ulative. Thus, Bonneville's comparatively conservative approach of not assuming refinancing is reasonable.

Several intervenors challenge Bonneville's Risk Management Strategy. Certain parties contend that assumption of a below average water year in Bonneville's ratemaking process will result in overcollection of revenues. The Commission has in the past, however, encouraged Bonneville to establish rates which have reasonable assurance of preventing underrecovery of revenues. Thus, continued use of the 1939 water year, a below average water year, as approved in previous filings, 32 is appropriate. Some intervenors object to Bonneville's inclusion of an Investment Service Charge as part of its revenue requirement. The Commission has previously approved such a charge,33 and we continue believe that the Investment Service Charge will assist in ensuring federal repayment. These intervenors also argue that the Cost Recovery Adjustment Clause, if actually implemented, should be subject to a separate section 7(i) rate proceeding. Bonneville states that the Cost Recovery Adjustment Clause has already been subjected to a section 7(i) rate proceeding during the overall 1987 rate proposal proceeding, and that there is no need to subject the formula to another section 7(i) hearing. The Commission concludes that, since Bonneville has subjected the Cost Recovery Adjustment Clause to hearings, the Commission may approve this formula-type automatic adjustment clause and that it would not require further Commission action when implemented.

Equitability of Allocation of Transmission

Costs

Section 7(a)(2)(C) of the Northwest Power Act requires that the costs of providing transmission over the transmission system be equitably allocated between the federal and nonfederal users of the system. In Bonneville's previous rate case, the Commission stated that an equitability test could not be administered until Bonneville separated its system into its generation and transmission functions to ensure that only transmission costs would be paid with transmission revenues. Consequently, the Commission directed that "Bonneville shall in future filings explain precisely how costs and revenues have been assigned between the federal and nonfederal users of the

32 See, e.g., 39 FERC at pp. 61,207-08.
33 Id.

transmission system based on repayment accounting."34

In the instant filing, Bonneville has submitted separate repayment studies for the power and transmission systems. In the transmission power repayment study, revenue responsibilities for the two user groups (federal and nonfederal) were developed for each group using the 12 coincident peak method. The transmission rates for nonfederal use of the transmission system were designed to repay that portion of the transmission costs attributed to nonfederal users. Based on its review of the transmission power repayment study and transmission rates, the Commission concludes that Bonneville has reasonably allocated its transmission costs between the two major customer classes and that the proposed transmission rates comply with section 7(a)(2)(C).

While Bonneville has provided a separate transmission power repayment study, Bonneville requests that it be allowed the discretion to use transmission revenues to repay generation costs. In Bonneville's July 31, 1987, letter transmitting the rates in the instant case, the Administrator stated that he:

... has the statutory responsibility to manage and apply Bonneville revenues and other receipts as a single fund in a prudent and business like manner. . . . Under some circumstances, such as where power rates are under extreme pressure but transmission rates are not, application of the Administrator's sound business judgment may well dictate application of certain transmission revenues to repay generation costs. We request that the Commission not take any action that might jeopardize this important management principle. (Emphasis added.)

Bonneville asserts the right to apply revenues from one function, such as transmission, to temporarily support unrecovered costs of the other function. We have no objections to Bonneville's doing so. However, the Commission has previously recommended that, if Bonneville chooses to temporarily apply revenues from one function to the unrecovered costs of the other function, Bonneville account for these funds, repay them from the appropriate revenues, and charge the costs to the appropriate customers. We note that in its 1989 submittal Bonneville has, in fact, made an effort to do just this.

35

34 39 FERC at p. 61,209 (emphasis added).

35 See 39 FERC at p. 62,209.

36 The intertie adder is a wheeling charge Bonneville applies to both federal and nonfederal power using the interconnections between Bonneville's transmission system and an adjacent nonregional transmis

Certain intervenors argue that the elimination of the intertie adder36 from the Market Expansion and Displacement Rates components of the NF-87 rate for nonfirm energy sales would violate Bonneville's statutory obligations regarding the equitable allocation of transmission costs between federal and nonfederal users. The Commission's review indicates that Bonneville has, in fact, eliminated the intertie adder for certain services using the intertie when inclusion of the adder would result in so high a price that the sale would be lost. This is within Bonneville's discretion provided that the two classes of customers, federal and nonfederal, are equitably charged. Since Bonneville's filing indicates that costs have been reasonably allocated to the two classes, this concern is dismissed.

Several intervenors contend that the Market Transmission Rate schedule, MT-87, violates Bonneville's statutory requirement of equitability, that MT-87 must be cost-based, and that MT-87 should be set for hearing. Bonneville states that MT-87 is market-based and that MT-87 enables Bonneville to participate in the Western Systems Power Pool Experiment. Bonneville also states that the magnitude of revenues involved is negligible, and will not affect overall equitability. The intervenors appear to misunderstand the equitability test. The statutory requirement of equitability speaks only to federal and nonfederal users as a class, and the rate meets this requirement of equitability. Section 7(a)(2)(C) does not require that each individual customer be assigned responsibility for the equitable recovery of the cost of specific transmission facilities. Consequently, we see no benefit to be gained from setting this rate for hearing.

Analysis of Pacific Northwest Coordinating Agreement Rates

In Docket No. EL85-18,3 37 the Commission directed Bonneville to file the rates Bonneville charges the parties for services provided under the terms of the PNCA. Bonneville complied with the Commission's directive with a supplemental filing in the instant case on January 13, 1988, requesting approval of the PNCA charges for a period from July 1, 1986 until a PNCA party requests Commission approval of revised charges. These charges are intended by the parties to the PNCA to be only a means of correcting exchange accounts among the par

sion system. The charge is set to recover Bonneville's costs for providing such service to the user.

37 This docket was a complaint by City of Tacoma seeking to revise PNCA rates. See City of Tacoma, Washington v. The Washington Water Power Company et al., 34 FERC || 61,341 (1986).