Minnesota v. Federal Energy Regulatory Commission

BRIGHT, Circuit Judge.

The State of Minnesota and the Minnesota Public Utilities Commission (collectively referred to as the MPUC) petition for review of orders¹ of the Federal Energy Regulatory Commission (the Commission) approving a proposed amendment to the Coordinating Agreement among the Northern States Power Companies (NSP Companies). The MPUC contends that the Commission lacked jurisdiction to review the proposed amendment because the Coordinating Agreement does not establish a wholesale rate for the resale of electricity. We deny the petition and affirm the orders of the Commission.

I. Background.

The NSP Companies are three affiliated public utilities providing wholesale and retail electric service to customers in the Upper Midwest. NSP-Minnesota, the parent company, serves Minnesota, North Dakota, and South Dakota. NSP-Wisconsin and the Lake Superior District Power Company, subsidiaries of NSP-Minnesota, serve Wisconsin and the Upper Peninsula of Michigan. To achieve economies of scale, the NSP Companies develop and operate their respective generation and transmission facilities on an interconnected and integrated basis. The Companies accomplish this objective through their participation in a Coordinating Agreement, which establishes, among other things, procedures for sharing the costs of the entire system.²

On November 1, 1982, the NSP Companies filed with the Commission an amendment to the Coordinating Agreement. The amendment proposed a methodology for determining the rate of return on investment (or capital) as a component of the fixed costs shared by the Companies under the Coordinating Agreement. The proposed amendment included a fifteen percent rate of return on equity. The MPUC intervened and challenged the Commission’s jurisdiction to review the proposed amendment. According to its brief, the MPUC challenges the Commission’s jurisdiction in order to protect its interest in regulating retail electric rates and to avoid being bound by a federal determination as to rate of return on investment which will affect retail rates. The MPUC argues that the Commission exceeded its authority under the Federal Power Act and intruded upon retail ratemaking functions by accepting a filing that sets a rate of return on capital as part of a cost allocation agreement between affiliated power companies.

II. Discussion.

The issue in this case is whether, as the MPUC claims, the Commission exceeded its jurisdiction and usurped the retail ratemaking authority of the MPUC by accepting an amendment to the Coordinating Agreement which establishes a rate of return on capital. Under the Federal Power Act, the Commission is vested with exclusive authority to regulate wholesale rates for the resale of electric power in interstate commerce. See 16 U.S.C. § 824(b) (1976 & Supp. V 1981);³ New England Power Co. v. New Hampshire, 455 U.S. 331, 340, 102 S.Ct. 1096, 1101, 71 L.Ed.2d 188 (1982); FPC v. Southern California Edison Co., 376 U.S. 205, 215-16, 84 S.Ct. 644, 651-52, 11 L.Ed.2d 638 (1964). In determining that it possessed jurisdiction to review the proposed amendment, the Commission found that the Coordinating Agreement among the NSP Companies established a wholesale rate for the resale of electric power in interstate commerce. The Commission’s jurisdiction to review the proposed amendment, therefore, turns on the nature of the transactions provided for under the Coordinating Agreement.

The MPUC’s challenge to the Commission’s jurisdiction rests on its contention that the Coordinating Agreement serves simply as a mechanism for allocating costs among the NSP Companies and does not establish a wholesale rate for the resale of electricity. A wholesale rate, the MPUC points out, requires that there be a “sale of electric energy * * * for resale.” 16 U.S.C. § 824(d). The MPUC argues that the Coordinating Agreement does not provide for sales of electric energy between the NSP Companies and, therefore, cannot establish a wholesale rate. To demonstrate that the NSP Companies do not sell power to each other, the MPUC observes that NSP-Minnesota, which has the greatest generating capacity of the NSP Companies, does not purchase electric energy from its affiliates on a “steady, reliable basis.” It also contends that the NSP Companies’ failure to specify a price for a kilowatt or kilowatt hour further demonstrates that no sales transactions take place.

In evaluating the MPUC’s claim that the Commission erroneously found the existence of a wholesale rate under the Coordinating Agreement, we note that our review of the Commission’s orders is limited in scope. First, we are required to accept as conclusive the “findings of the Commission as to facts, if supported by substantial evidence.” 16 U.S.C. § 825l (b) (1976); see Otter Tail Power Co. v. FERC, 583 F.2d 399, 407 (8th Cir.1978), cert. denied, 440 U.S. 950, 99 S.Ct. 1431, 59 L.Ed.2d 639 (1979). In addition, we must defer to the Commission’s judgment in making determinations within its area of administrative expertise. See E.I. du Pont de Nemours & Co. v. Collins, 432 U.S. 46, 54-57, 97 S.Ct. 2229, 2234-2235, 53 L.Ed.2d 100 (1977); FPC v. Florida Power & Light Co., 404 U.S. 453, 463, 92 S.Ct. 637, 643, 30 L.Ed.2d 600 (1972); Union Electric Co. v. FERC, 668 F.2d 389, 392-93 (8th Cir.1981).

Given the limited nature of our review, we cannot say that the Commission erred in determining that the Coordinating Agreement establishes a wholesale rate.⁴ Contrary to the MPUC’s assertion that the Coordinating Agreement does not provide for sales of electric energy, the Commission specifically found that “[t]he [Coordinating] Agreement establishes the means by which the interstate transfer of power between companies occurs and the inter-company charges for such transactions.” 23 FERC II 61,026 (1983). Indeed, the Coordinating Agreement contains numerous provisions authorizing the NSP Companies to exchange electric power among themselves in return for payment. Transactions of this nature plainly constitute “sale[s] of electric energy * * * for resale” and, as such, are sufficient to establish wholesale electric rates. See 16 U.S.C. § 824(d).

The MPUC’s observation that NSP-Minnesota does not purchase electric power from the other NSP Companies on a “steady, reliable basis” is of little consequence to the issue before us, for nothing in the Federal Power Act suggests that the Commission lacks jurisdiction to regulate wholesale rates merely because the sales between affiliates occur on an intermittent basis. In any event, the Commission need not document particular transfers of electricity to demonstrate that NSP-Minnesota received energy generated and transmitted by the other NSP Companies. See FPC v. Florida Power & Light Co., supra, 404 U.S. at 467-68, 92 S.Ct. at 645-46. Rather, it may establish the transfer of electric power among the affiliates by showing that they shared continuous access to an integrated energy pool. See Arkansas Power & Light Co. v. FPC, 368 F.2d 376, 382 (8th Cir.1966); Indiana & Michigan Electric Co. v. FPC, 365 F.2d 180, 183-84 (7th Cir.), cert. denied, 385 U.S. 972, 87 S.Ct. 509, 17 L.Ed.2d 435 (1966); Northern States Power Co. v. Minnesota Public Utilities Commission, 344 N.W.2d 374, 382 (Minn. 1984) (that electric power conceivably flows in interstate commerce in form of wholesale sale is sufficient for Commission to assert jurisdiction).

Similarly, we reject the MPUC’s contention that the failure of the Coordinating Agreement to specify prices for units of electric power transferred among the NSP Companies reflects that sales do not take place among them. Despite the Agreement’s failure to specify prices per unit of power, the Commission determined that the Coordinating Agreement establishes “rates and charges” by means of formula rates.⁵ 23 FERC ¶ 61,026. Courts have approved the use of formulas in establishing wholesale electric rates, see Louisiana Public Service Commission v. FERC, 688 F.2d 357, 360 (5th Cir.1982), cert. denied, 460 U.S. 1082, 103 S.Ct. 1770, 76 L.Ed.2d 343 (1983); Northern States Power Co. v. Minnesota Public Utilities Commission, supra, 344 N.W.2d at 382, and we conclude that the Commission properly exercised its authority in approving the formula rate in this case. Thus, because the factual record and the application of the Commission’s expertise to that record supports the Commission’s conclusion that the Coordinating Agreement regulates sales of electric power among the NSP Companies, we reject the MPUC’s contention that the Agreement fails to establish a wholesale electric rate.

The MPUC advances two additional arguments in contending that the Coordinating Agreement does not establish a wholesale electric rate. First, it maintains that the parties traditionally have not treated the Coordinating Agreement as establishing a wholesale rate. Second, it contends that the terms of the Coordinating Agreement are too general, and that to treat the Agreement as establishing a wholesale rate would allow the NSP Companies effectively to establish charges. The MPUC made these arguments before the Commission, and the Commission nevertheless determined that the Coordinating Agreement established a wholesale rate. We see no reason to disturb this determination.

III. Conclusion.

We conclude, therefore, that substantial evidence supports the Commission’s determination that the Coordinating Agreement establishes a wholesale rate for the resale of electric power in interstate commerce. Because a change in the rate of return on investment affects the wholesale rate under the Coordinating Agreement, the Commission possessed jurisdiction to review and approve the proposed amendment.

We must observe, however, that the Commission’s procedures permit interested parties to intervene in the ratemaking proceedings and require a public hearing on the justness and reasonableness of the proposed rate. In this case the NSP Companies and their wholesale customers entered into a settlement agreement resolving all proceedings before the Commission, leaving intact the proposed fifteen percent equity return. The MPUC reserved only its attack on the Commission’s jurisdiction, and has not otherwise challenged the reasonableness of the settlement.

Accordingly, on the issue of jurisdiction, we deny the MPUC’s petition and affirm the orders of the Commission here in question. As we have noted, the reasonableness of the rate of return is not an issue before us.

1 . The Commission’s orders are reported at 24 FERC ¶ 61,011 (1983); 23 FERC ¶ 61,026 (1983); and 21 FERC ¶ 61,375 (1982).

2 . Observing the role of the Coordinating Agreement in the operation of the NSP System, the Commission noted,

The coordinating agreement determines charges * * * to be assessed the parties based on formula rates. System operating expenses, both fixed and variable and including such items as taxes, operation and maintenance expenses and the cost of capital, are calculated for each calendar year and then allocated to each party to the coordinating agreement based on the party’s responsibility for the incurren ce of such expenses. Variable costs are allocated according to the amount of kWh taken by each party in proportion to the total kWh generated. Fixed costs are allocated in proportion to the demand each party places on the total system generation and transmission investment.

3 . The Federal Power Act grants the Commission jurisdiction over “the transmission of electric energy in interstate commerce and * * * the sale of electric energy at wholesale in interstate commerce, * * * but * * * not apply * * * to any other sale of electric energy * * 16 U.S.C. § 824(b). Section 824(d) of the Act defines a wholesale sale of electric energy as "a sale of electric energy to any person for resale.”

4 . The Minnesota Supreme Court recently held that the Coordinating Agreement at issue in this case established a wholesale rate within the Commission’s exclusive jurisdiction. See Northern States Power Co. v. Minnesota Public Utilities Commission, 344 N.W.2d 374, 382 (Minn.1984). In that case, the state supreme court denied the MPUC jurisdiction to disallow costs arising from the abandonment of the Tyrone nuclear plant near Durand, Wisconsin. Id. at 375.

5 . The Commission noted that

The fact that the agreement does not specify unit demand or unit energy charges * * * is irrelevant. The unit costs can be determined by dividing the reported calendar year fixed and variable costs by the amount of capacity (kW) each party is assigned by the participation ratios and the number of kWh taken by each party.

23 FERC ¶ 61,026.