
    437 F.3d 1215
    ALLEGHENY POWER, Petitioner v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent Allegheny Electric Cooperative, Inc., Intervenor.
    No. 04-1340.
    United States Court of Appeals, District of Columbia Circuit.
    Argued Oct. 25, 2005.
    Decided Feb. 7, 2006.
    
      Leonard W. Belter argued the cause for petitioner. With him on the briefs were Raymond B. Wuslich and Margaret H. Claybour.
    Beth G. Pacella, Attorney, Federal Energy Regulatory Commission, argued the cause for respondent. With her on the brief were Cynthia A. Marlette, General Counsel, and Dennis Lane, Solicitor.
    Robert Weinberg and Eli D. Eilbott were on the brief for intervenor in support of respondent.
    Before: TATEL and GRIFFITH, Circuit Judges, and WILLIAMS, Senior Circuit Judge.
   Opinion for the Court filed by Senior Circuit Judge WILLIAMS.

WILLIAMS, Senior Circuit Judge.

This is a dispute between a utility and the Federal Energy Regulatory Commission over the rate for sending electricity over certain low-voltage facilities not covered by the relevant Open Access Transmission Tariff. We grant the utility’s petition in part and dismiss it in part.

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Allegheny Energy, Inc., owns (1) Allegheny Energy Supply Company, L.L.C., which owns and operates generation facilities, and (2) several utilities, divided along state lines and collectively doing business as Allegheny Power (“Allegheny”), which deliver electric power. The Allegheny utility operating in Pennsylvania is West Penn Power Company.

Allegheny Electric Cooperative, Inc. (“AEC”), is an organization through which fourteen local distribution cooperatives in Pennsylvania buy then' electricity. It is a wholesale customer of Allegheny. AEC receives electricity from Allegheny at 18 delivery points, all West Penn facilities.

The case in essence starts with a contract that Allegheny and AEC signed in 1994. One of the types of service provided under the contract — and the only one that concerns us here — is known as partial requirements service. Allegheny Power, 97 FERC ¶ 61,274, at 62,164, 2001 WL 34075781 (2001) (“2001 Order ”). In pricing this service, Allegheny bundled the cost of generating the electricity with the cost of sending it to AEC. At the time, such bundling was commonplace in contracts between vertically integrated utilities and them customers. Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1363-64 (D.C.Cir.2004).

In 1996, FERC concluded that this type of bundling allowed vertically integrated utilities to discriminate in favor of them own generators. To ensure open and equal access to the grid and thereby foster competition in sale and generation of power, the Commission in Order No. 888 required every utility transmitting electric power in interstate commerce to adopt, for the sale of its “transmission services,” a non-discriminatory schedule of terms and conditions, with prices reflecting transmission costs unbundled from generation costs. Such a schedule is known as an Open Access Transmission Tariff (“OATT”). 18 C.F.R. § 35.28(c)(1); Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Ptiblic Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. Preambles ¶ 31,036, at 31,654, 61 Fed.Reg. 21,540, at 21,552 (1996) (“Order No. 888”).

Order No. 888 indisputably covers the service that Allegheny provides to AEC. See Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 695-96 (D.C.Cir.2000) (construing Order No. 888 to cover, inter alia, any transfer of electricity from a utility to a customer who then resells it, regardless of the type of facilities involved), aff'd on other grounds sub nom. New York v. FERC, 535 U.S. 1, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002).

FERC policy requires that rates subject to Order No. 888 be unbundled “at the earliest contractual opportunity,” which includes the first time a contract becomes subject to extensions. 2001 Order, 97 FERC at 62,167. In Allegheny’s 1994 contract with AEC, the initial term was to expire on November 30, 2001, and the contract was to be automatically renewed annually, subject to “revised charges, terms, and conditions,” unless either party terminated it on two years’ notice. Id. at 62,164. In the months leading up to the initial term’s expiration, Allegheny informed AEC that, for the one-year renewal period beginning December 1, 2001, it would unbundle the generation and transmission charges, the latter to be determined by an OATT adopted by PJM Interconnection, L.L.C. (“PJM”). Id. at 62,165. PJM is a regional transmission organization that operates the transmission facilities of its member utilities (including Allegheny) to ensure open access.

The PJM OATT specifies terms and conditions for the use of all Allegheny transmission facilities with voltage of 138 kV or greater. For Allegheny transmission facilities of lesser voltage, the PJM OATT punts, stating simply that service “will be provided at rates determined on a case-by-case basis.” See Pennsylvania-New Jersey-Maryland Interconnection, 92 FERC ¶ 61,282, at 61,952, 2000 WL 1457019 (2000) (approving this provision of the PJM OATT); Pennsylvania-New Jersey-Maryland Interconnection, 81 FERC ¶ 61,257, at 62,251, 1997 WL 760259 (1997) (same). For purposes of simplicity, we will refer to the facilities whose rates are specified in the PJM OATT as “transmission facilities” and those whose rates are determined case-by-case as “subtransmission facilities.”

Thus — as a result of the unbundling mandated by Order No. 888, the Allegheny-AEC contract’s terms for its initial expiration, and the provisions of the PJM OATT — the rate that AEC would pay for use of Allegheny’s subtransmission facilities during the one-year renewal period was to be determined on a “case-by-case” basis. Shortly before the expiration of the initial contract term, Allegheny filed a unilateral addendum stating that, for the upcoming renewal period, it would assess AEC “sub-transmission charges for service over facilities not covered by the OATTs,” and would calculate these charges through the method of “direct assignment.” 2001 Order, 97 FERC at 62,165; Addendum to Agreement (Oct. 19, 2001) at 3^4 and Attachment D. Direct assignment was the method by which Allegheny had calculated subtransmission charges for all the settlement agreements that it had made with other wholesale customers whose contracts expired in the years after Order No. 888. Brief on Exceptions of Allegheny Power at 6.

Direct assignment allocates the cost of specific facilities to customers in proportion to them use of such facilities. Direct Testimony of Menhorn, Exh. Allegheny-1, at 2-10. The alternative is “rolled-in” pricing, under which every customer pays the same unit rate, based on the costs of all facilities, rolled-in together without differentiating on the basis of the role played by particular facilities in providing service to particular customers. Both methods are aimed at matching a user’s rates with the costs incurred to provide the service it enjoys. Rolled-in pricing is thought to make sense when the facilities are integrated, i.e., when the service to each customer is most practicably seen as depending on the entirety of the facilities in question. See generally Western Massachusetts Electric Co. v. FERC, 165 F.3d 922, 927-28 (D.C.Cir.1999); Maine Public Service Co. v. FERC, 964 F.2d 5, 8 (D.C.Cir.1992); Sierra Pacific Power Co. v. FERC, 793 F.2d 1086, 1088 (9th Cir.1986); Otter Tail Power Co., 12 FERC ¶ 61,169, at 61,420 (1980). To some extent, of course, the cost of information may influence Commission judgment; even where facility usage may be conceptually severable, the interdependency among the facilities may be such that the calculations necessary for direct assignment simply aren’t worth the effort.

In light of protests by AEC, the Commission conditionally accepted Allegheny’s addendum for filing, suspended it for a nominal period, pronounced it effective subject to refunds, and encouraged the parties to settle. 2001 Order, 97 FERC at 62,167.

Settlement negotiations failed to resolve all issues, and the matter was assigned to an ALJ to determine, inter alia, whether Allegheny’s calculation of the subtransmission rate was just and reasonable. Allegheny Power, 103 FERC ¶ 63,001, 2003 WL 21422410 (2003) (“ALJ Decision”). AEC agreed with Allegheny that direct assignment was the proper method but disagreed on how to apply it. Commission staff, however, argued that the rate for subtransmission service should be calculated via the rolled-in method, Direct Testimony of Farrokhpay, Exh. Staff-8, at 11, which the PJM OATT was (and is) using for service over Allegheny’s transmission facilities. Thus, Staff was effectively proposing that Allegheny charge AEC two distinct rolled-in rates, one that reflected the cost of the transmission facilities, and another that reflected the cost of the sub-transmission facilities. As FERC counsel noted at oral argument, use of two such rolled-in rates is a novelty, occasioned (in part) by PJM’s decision to specify a rate for Allegheny’s transmission facilities and to leave subtransmission to be priced case-by-case. Oral Arg. Recording at 31:45-32:40, 33:20-33:45.

Agreeing with staff, the ALJ ordered Allegheny to calculate the subtransmission charge to AEC by rolling in the costs of all the West Penn subtransmission facilities. ALJ Decision, 103 FERC at PP 10-17, pp. 65,001-02. The case then went to the full Commission, which affirmed the ALJ, Allegheny Power, 106 FERC ¶ 61,241, 2004 WL 434634 (2004) (“Opinion No. h69 ”), and later denied Allegheny’s petition for rehearing, Allegheny Power, 108 FERC ¶ 61,151, 2004 WL 1760022 (2004) (“Opinion No. 469-A ”).

Allegheny petitions to vacate FERC’s roll-in order and to remand with instructions to use direct assignment instead. AEC, having abandoned its prior support for direct assignment, intervenes in support of FERC.

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To begin, we address the issues of standard of review and burden of persuasion. Allegheny filed the addendum embodying its proposed direct assignment rate under § 205 of the Federal Power Act, 16 U.S.C. § 824d. Allegheny asserts (and no party questions) that that proposal is governed by § 205(e), which states that a utility seeking a rate increase bears “the burden of proof to show that the increased rate ... is just and reasonable.” FPA § 205(e), 16 U.S.C. § 824d(e).

At the same time, Allegheny contends that insofar as the Commission imposed its own preferred method (as distinct from merely rejecting Allegheny’s proposal), § 206(b) of the Act, 16 U.S.C. § 824e(b), assigns the agency the burden of showing its method to be just and reasonable. But § 206 applies only when the Commission seeks to impose its own preferred rate in place of the “existing rate.” Midwest ISO, 373 F.3d at 1368. Here, the rate at the time of filing was a charge that bundled generation, transmission, and subtransmission — a charge rendered unlawful by a pri- or FERC rulemaking and therefore off the table in this adjudication. In Midwest ISO, where FERC (as here) made a rate determination without there being an existing rate or practice to fall back on, we reviewed the agency’s decision under the arbitrary and capricious standard, 5 U.S.C. § 706(2)(A), and its factual findings under the substantial evidence standard, 16 U.S.C. § 825l (b). Midwest ISO, 373 F.3d at 1368. We shall apply the same standard here insofar as the agency went beyond rejecting the utility’s method and imposed its own. The arbitrary and capricious standard speaks, of course, to the degree of deference that we owe the agency, not to burden of proof or persuasion. As we shall see, however, the case relating to FERC’s imposition of its rolled-in method can be resolved without addressing issues of burden allocation.

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Before reaching the merits of Allegheny’s claims we must address the Commission’s arguments that Allegheny failed to preserve its objections adequately. Both arguments turn on the Act’s jurisdictional provision that the court may consider only objections that “have been urged before the Commission in the application for rehearing unless there is reasonable ground for failure so to do.” § 313(b), 16 U.S.C. § 825l(b).

The ALJ, in rejecting Allegheny’s direct assignment proposal and imposing staffs recommended roll-in, gave four reasons for his decision. The first was his conclusion that the facilities at issue were integrated. ALJ Decision, 103 FERC at PP 11-12, p. 65,002. The remaining three reasons all concerned independent failings in Allegheny’s support for its direct assignment proposal — -defects in its cost data and its identification of facilities used by AEC. Id. at PP 10, 13, pp. 65,001-02.

The Commission affirmed the ALJ’s roll-in order “for the reasons stated by the [ALJ],” and noted that, “as pointed out by the [ALJ] ..., Allegheny Power failed to provide adequate justification for its proposed direct assignment.” Opinion No. 469, 106 FERC at P 17, p. 61,850. Although the rest of the Commission’s discussion of the ratemaking method focused exclusively on the issue of integration, it plainly adopted by reference all four of the reasons articulated by the ALJ. This is enough. Gannett Rochester Newspapers, a Division of Gannett Co. v. NLRB, 988 F.2d 198, 204 (D.C.Cir.1993); United Food and Commercial Workers Int’l Union v. NLRB, 880 F.2d 1422, 1436 (D.C.Cir.1989).

Allegheny, in its petition for rehearing, objected specifically only to the integration finding, Request of Allegheny Power Company for Rehearing at 1-7, but also purported to incorporate by reference the entirety of its prior Brief on Exceptions, id. at 2. Unfortunately for Allegheny, what is sauce for the agency isn’t sauce for petitioner. Under § 313(b) an objection cannot be preserved “indirectly,” Office of the Consumers’ Counsel, State of Ohio v. FERC, 914 F.2d 290, 295 (D.C.Cir.1990) (construing the identical provision of the Natural Gas Act, 15 U.S.C. § 717r(b)), but must be raised with “specificity,” Wisconsin Power & Light Co. v. FERC, 363 F.3d 453, 460 (D.C.Cir.2004). Allegheny notes that, in Columbia Gas Transmission Corp. v. FERC, 404 F.3d 459, 462 (D.C.Cir.2005) (construing 15 U.S.C. § 717r(b)), “a terse request for rehearing was adequate when the Commission itself offered only a half-sentence explanation in its initial order and responded to the objection on rehearing,” Reply Brief of Petitioner at 6. But the objection in Columbia Gas was explicit and elicited a response from the Commission, 404 F.3d at 462, neither of which can be said for Allegheny’s attempted incorporation by reference. Allegheny therefore cannot now object to the other three findings.

The question remains whether those three findings are enough to support the Commission’s order. Surely they are as to its rejection of Allegheny’s proposed direct assignment method, as under § 205(e) Allegheny bears the burden of showing that method to be just and reasonable. What of FERC’s decision that Allegheny must instead conduct a roll-in of all West Penn subtransmission facilities? Allegheny’s loss on the cost and facility-identification issues would be fatal on the current record if direct assignment and the Wesb-Pennwide roll-in were the only two options. But that is not so here. In its petition for rehearing, Allegheny offered a “third way,” calling for adjustments in any rolled-in rate for AEC to remove the allegedly distorting effect of costs and loads charged to other subtransmission customers by direct assignment. See Request of Allegheny Power Company for Rehearing at 7, Allegheny Appendix (“A.A.”) at 693; see also Allegheny Brief on Exceptions at 21-23, AA. at 672-74; ALJ Hearing Tr. 1/28/03 at 395-98, A.A. at 573-76 (testimony of staff witness Farrokhpay on examination by Allegheny). The ALJ’s findings on cost data and identification of facilities do not necessarily explain the Commission’s rejection of Allegheny’s proposal of an adjusted roll-in.

The Commission acknowledged the proposal, Opinion No. 469-A, 108 FERC at P 20, p. 61,864, and specifically explained its rejection of a related alternative argument (that the other customers should have them rates converted to the rolled-in method, rejected by FERC on the ground that their rates weren’t before the Commission), id. at PP 35-37, 40, pp. 61,866-67. As to the proposal itself, the Commission lumped it together with all of Allegheny’s objections (including its plea for direct assignment), declared that “[a]ll of these objections ... are beside the point,” and rejected them all in blanket fashion, relying upon Allegheny’s failure to substantiate its direct assignment methodology and upon the “integration” findings from its own previous order. Id. at PP 21-22, p. 61,865. (Insofar as Allegheny may suggest that the Commission has initiated a default rule in favor of roll-in, we are unconvinced, as the cases cited by the Commission relied on findings of integration. See id. & n. 3.) Thus, the Commission’s response to the adjusted roll-in proposal was so framed as to make that response’s adequacy contingent on the factual .support for, and the reasonableness of, its integration findings.

There remains a final hurdle for Allegheny on this point — its failure to raise the adjusted roll-in issue in its briefs before this court. But as FERC, in rejecting the adjusted roll-in on rehearing, implicitly relied solely on the integration findings, and as Allegheny before us plainly put FERC on notice to defend those findings, we see no unfairness to FERC in our addressing them, even though the route has proven circuitous.

The Commission makes a second waiver argument — namely that Allegheny’s petition for rehearing failed to question what the Commission says was a finding in Opinion No. 469 that the Allegheny sub-transmission facilities serving AEC are integrated with Allegheny’s larger network of transmission facilities. Instead, says the Commission, the petition for rehearing attacked a non-existent Commission theory — that the facilities in question were operated as “a single integrated subtransmission network.” Brief, for Respondent at 16.

The difficulty with this argument is that it invokes a Commission finding in Opinion No. 469 that either didn’t exist, or existed only in such obscurity as to be undetectable by a reasonable litigant. Opinion No. 469, in a section titled “Commission Finding,” explicitly directed that the “subtransmission service charges to AEC should be calculated based on the system-wide average costs of Allegheny Power’s subtransmission facilities.” Opinion No. 469, 106 FERC at P 17, p. 61,850. In the same section it states that “we find that the facilities used by Allegheny Power to serve AEC are part of an integrated sub-transmission/distribution network.” Id. Although the term “distribution” is not entirely precise, it certainly refers to lower-voltage facilities of some kind, not transmission facilities. What is more, the “Commission Finding” says nothing about transmission facilities. Admittedly, a more peripheral section of Opinion No. 469 — the summary of ALJ findings — is somewhat ambiguous. Id. at P 4, p. 61,-848 (stating that the ALJ found that the facilities at issue “constitute part of Allegheny Power’s total integrated network” and referring to the “integrated subtransmission/distribution network serving Allegheny Power’s entire system”). But such ambiguity cannot override the clear language of the “Commission Finding.” Besides, the ALJ decision to which the summary refers is quite clear that the facilities at issue “are part of an integrated sub-transmission/distribution network.” ALJ Decision, 103 FERC at P 11, p. 65,002.

FERC counsel responds that, even if the Commission did invoke an integrated subtransmission/distribution network in Opinion No. 469 and introduced the theory of integration with the larger transmission network only in Opinion No. 469-A, Allegheny is barred by its failure to file a second petition for rehearing to contest the new rationale. Oral Arg. Recording at 23:25-23:55. This argument relies upon Town of Norwood, Massachusetts v. FERC, 906 F.2d 772, 775 (D.C.Cir.1990), in which we held that § 313(b) requires “an application for rehearing of an order on rehearing when the later order modifies the results of the earlier one in a significant way, raising objections to the rehearing order that are substantially different from those raised against the original one.” But Nonvood requires a second petition only when the result is different; a petitioner need not file a second petition “when the outcome had not been changed but the Commission had ‘supplie[d] a new improved rationale.’ ” California Department of Water Resources v. FERC, 306 F.3d 1121, 1126 (D.C.Cir.2002) (quoting Southern Natural Gas Co. v. FERC, 877 F.2d 1066, 1073 (D.C.Cir.1989)); see also Norwood, 906 F.2d at 775 (“[T]he Federal Power Act does not require an endless cycle of rehearing applications.”). The rule is thus analogous to the circumstances under which an appellee must file a cross-appeal. See, e.g., Freeman v. B & B Associates, 790 F.2d 145, 151 (D.C.Cir.1986) (“Only when an appellee attempts to overturn or modify a district court’s judgment must the appellee file a cross-appeal.”). Here, the rationale changed, but the result — a roll-in of all West Penn sub-transmission facilities — remained the same.

Thus none of the Commission’s waiver arguments insulates from review its rejection of Allegheny’s argument that any rolled-in rates must be adjusted. As the Commission gave no explicit explanation for that rejection and implicitly relied only on its integration finding, its order can survive only if its integration finding is itself neither arbitrary nor capricious.

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We therefore at last reach the merits of the Commission’s treatment of integration. We find it to be arbitrary and capricious and not supported by substantial evidence.

As noted above, FERC mandated a rolled-in rate for Allegheny’s subtransmission facilities separate and distinct from the PJM OATT’s rolled-in rate for Allegheny’s transmission facilities. It did so for the stated reason that all the facilities — both transmission and subtransmission — are integrated, i.e., act together as a single piece of equipment. Opinion No. 469-A, 108 FERC at P 22, p. 61,865. Several aspects of this decision are unexplained.

First, the Commission shifted without a word from a theory of integration among subtransmission facilities to integration between facilities for subtransmission and transmission. Given that the evidence before the ALJ addressed the first and not the second (so far as appears), this left gaps either of data or analysis or both (matters to which we return below). At the very least, it appeared inconsistent with the Commission’s decision in PP & L, 88 FERC ¶ 61,235,1999 WL 718965 (1999), reh’g denied 95 FERC ¶ 61,160, 2001 WL 469993 (2001), which appeared to present a parallel issue. A utility whose transmission rates were also determined by the PJM OATT sought an outcome similar to the one FERC mandated here: it wanted a separate rolled-in rate for low-voltage facilities to be charged to those of its wholesale customers who took delivery from those facilities. FERC rejected the request in terms that appeared to treat integration among the subtransmission facilities as a prerequisite. PP & L had “provided no support for its assertions that the low voltage facilities operate as an integrated system and that the use of the rolled-in rate methodology is thus the proper basis for rates for transmission service over these facilities.” 88 FERC at 61,770.

By the same token, if the record in fact showed integration between the subtransmission and transmission facilities — that they act together as a single piece of equipment — the precedent invoked by FERC suggests that the solution is a rolled-in rate encompassing both high-voltage and low-voltage facilities, not a separate roll-in of low-voltage facilities only. The aggregated subtransmission-transmission rate, in any event, was the solution in all cases invoked on this point by the Commission and AEC: Maine Public Service Co., 964 F.2d at 8-9; Niagara Mohawk Power Corp., 42 FERC ¶ 61,143, at 61,532-33, 1988 WL 243720 (1988); Kansas Gas & Electric Co., 39 FERC ¶ 63,013, at 65,053-55, 1987 WL 116577 (1987), aff'd in relevant part, 49 FERC ¶ 61,295, at 62,117, 1989 WL 263098 (1989); reh’g granted in part, 52 FERC ¶ 61,301, 1990 WL 318149 (1990); Utah Power & Light Co., 24 FERC ¶ 63,108, at 65,176-79, 1983 WL 39311 (1983), aff'd, 27 FERC ¶ 61,258, at 61,486-87, 1984 WL 56728 (1984), reh’g denied, 28 FERC ¶ 61,088, at 61,165-67, 1984 WL 57543 (1984), aff'd sub nom. Sierra Pacific, 793 F.2d at 1087-90; Potomac Edison Co., 20 FERC ¶ 63,060, at 65,257-59, 1982 WL 41127 (1982), aff'd in relevant part, 23 FERC ¶ 61,106, at 61,-255-56, 1983 WL 39434 (1983); Minnesota Power & Light Co., 16 FERC ¶ 63,012, at 65,069-80, 1981 WL 34182 (1981) (because the record showed no integration between subtransmission and transmission facilities, it did not support petitioner’s request for aggregating the cost of the two sets of facilities), aff’d in relevant part, 21 FERC ¶ 61,233, at 61,519, 1982 WL 39117 (1982); see also Oral Arg. Recording at 33:30-33:40 (statement of FERC counsel that this is the “first time the Commission had before it a case-by-case situation where we have a roll-in of the low-voltage transmission rates, and yes this is different”); Reply Brief of Allegheny Power (before ALJ) at 6.

In short, the Commission appears hitherto to have applied the following matching principles: (1) If subtransmission and transmission facilities are integrated with each other, a single rate rolling them both together is appropriate. (2) If subtransmission facilities are integrated with each other, a separate rolled-in rate for sub-transmission facilities is appropriate. As noted, in PP & L the Commission said the factual predicate for application of Rule # 2 was not shown. 88 FERC at 61,770. In Puget Sound Energy, Inc., 98 FERC ¶ 61,168, 2002 WL 228461 (2002), it approved separate roll-ins for high-voltage and low-voltage facilities, but simply on the ground that the new arrangement did not entail a rate increase for any customer, id. at 61,622. The Commission apparently hasn’t developed a rale specific to the case where subtransmission facilities are integrated with each other and with transmission facilities. Given the Commission’s scuttling away from its earlier supposition that the subtransmission facilities were integrated with each other, it appears to be asserting the finding required for Rule # 1 and yet to have adopted the rate indicated by Rule # 2.

As we suggested earlier, there seem to be gaps either in the data before the Commission or in the necessary analysis. In part this arises from its shift from an idea of integrated subtransmission facilities to the broader integration claim. As noted above, FERC originally stated — in the ALJ decision and in Opinion No. 469 — that the subtransmission facilities were integrated among themselves. It then concluded — when denying rehearing in Opinion No. 469-A — that those facilities were integrated with the transmission facilities. The evidence marshaled in the ALJ decision and in Opinion No. 469 was, not surprisingly, aimed at proving the staffs contention and the agency’s conclusions in those decisions, i.e., the first proposition and not the second. Opinion No. 469, closely following the ALJ, focused on nine of the 18 interconnection points between Allegheny and AEC, and invoked five defining elements of integration:

Trial Staff states that 9 of the 18 Allegheny Power interconnection points with AEC are normally served in network configurations and that the integrated nature of Allegheny Power’s facilities are based on the following: (1) the facilities are looped, not radial; (2) energy does not flow in just one direction over these Allegheny Power facilities; (3) Allegheny Power selves not only AEC but also its own customers over these facilities; (4) the looped configuration enables Allegheny Power to provide support and added reliability to the other looped lines; and (5) an outage on any one of these facilities affects the power flows on other facilities.

Opinion No. 469, 106 FERC at P 17, p. 61,850. Putting aside for a moment the nine interconnection points not covered by this finding, the integration here appears to be only what the Commission was then claiming — integration among subtransmission facilities. This certainly appears to be the focus of the direct testimony of the staff engineering expert — which the Commission decisions track very closely. Direct Testimony of Farrokhpay, Exh. Staff-3, at 1-18, esp. 7-12. But when the agency in its denial of rehearing switched to the broader integration theory, it largely repeated the same evidence as before, neither adding new evidence nor explaining-why the old evidence supported the new conclusion. Opinion No. 469-A 108 FERC at P 22, p. 61,865. While at least one FERC precedent suggests that integration of subtransmission facilities with each other is relevant to their integration with the transmission grid, Utah Power, 28 FERC at 61,166, here the Commission did not articulate such a proposition, much less establish its logical role.

The second problem relates to how the Commission fills the gap left by the recognition that the finding on the five integration factors covered only nine of the 18 interconnection points. By way of background we observe that these five factors were articulated — with similar wording and in the same sequence — in Mansfield Municipal Electric Department v. New England Power Co., 97 FERC ¶ 61,134, at 61,613-14, 2001 WL 1379456 (2001). In Northeast Texas Electric Cooperative, Inc., 2004 WL 1700584, 108 FERC ¶ 61,-084, at P 51, p. 61,434 (2004), the Commission crowned them the “five-factor Mansfield Test,” and appeared to rule that a negative showing on all five factors constituted “ ‘exceptional circumstances’ that merit[ ] direct assignment.” (FERC didn’t cite Mansfield in any of its decisions here or in its brief.) For the remaining nine points, Opinion No. 469 — again following the ALJ — simply stated that those points, “while radially connected to Allegheny Power, are typically backed up by an Allegheny Power network of 25 kV lines.” Opinion No. 469, 106 FERC at P 17, p. 61,850. It is not clear whether “back-up” is synonymous with one of the five Mansfield factors (e.g., an indicator that the facilities provide “support and added reliability”) or whether it is a distinct factor that the Commission means to add to the test. It is also unclear how the Commission defines back-up on the facts of this case. Its entire treatment of the concept consists of the sentence quoted above.

This cursory treatment might be permissible if prior FERC cases revealed a clear and consistent policy on how back-up is defined and how it contributes to integration and justifies roll-in. But the cases reveal no such policy. Perhaps most important, they are inconsistent as to whether the back-up required to show integration refers to back-up capability that is used with some level of frequency or that merely has the potential for use. The distinction is plainly important for this case, as FERC counsel acknowledged that there was “no evidence about how often it [i.e., utilization of back-up] happens.” Oral Arg. Recording at 28:05-28:10; see also Direct Testimony of Farrokhpay, Exh. Staff-3, at 10-11; ALJ Hearing Tr. 1/23/03 at 375.

In general, the Commission appears to have regarded potential back-up as insufficient. In Minnesota Power, 21 FERC at 61,519, the Commission adopted the decision of the ALJ, 16 FERC ¶ 63,012, who, in turn, although recognizing that certain facilities could back up others if certain switches normally kept open were closed (switch closure enables power transmission), id. at 65,071, ruled that the choice of ratemaking method should be premised on “the common, prevailing situation, not on what physically could take place,” id. at 65,071-72 (emphasis added). And in Niagara Mohawk, 42 FERC at 61,533, the Commission shunned reliance on mere potential. Responding to an argument that staff had demonstrated that certain sub-transmission lines were “only theoretically capable of providing” additional reliability, it insisted that the evidence showed support “ ‘on an everyday basis.’ ” Id. (citation omitted).

Qualifying this is a FERC decision of considerable ambiguity. In Utah Power, 28 FERC at 61,166, the Commission suggested that Minnesota Power’s focus on the “common, prevailing situation” did not apply to a case where integration was clearly demonstrated by other evidence; but it is unclear why the matter would be of any consequence at all in such a case. The Ninth Circuit, affirming Utah Power, in dictum quoted with approval a passage from the intervenor’s brief to the effect that parallel paths establish integration even where connection between the two is interrupted by an open switch. Sierra Pacific, 793 F.2d at 1088. Of course the Ninth Circuit doesn’t establish FERC policy-

In the present case, FERC counsel, when pressed at oral argument to articulate a standard, stated that the “mere potentiality” for back-up was sufficient for roll-in. Oral Arg. Recording at 30:10-30:20. To distinguish Minnesota Power, counsel emphasized, Oral Arg. Recording at 34:20-36:15, that the outcome there rested partly on the fact that closing the switches for the sake of back-up could have damaged the facilities, 16 FERC at 65,072, suggesting that Minnesota Power stands for a very narrow “damage” exception to the supposed rule that potential back-up suffices for roll-in. But counsel has pointed to nothing said by FERC itself establishing such a concept. SEC v. Chenery Corp., 332 U.S. 194, 196, 67 S.Ct. 1575, 91 L.Ed. 1995 (1947).

The above discussion would be inaccurate if it conveyed the impression that the actual/potential distinction is the only aspect of “back-up” that is obscure to this court. The discussion does, however, pinpoint what appears the most critical uncertainty in the Commission’s handling of the matter. On remand we assume that the Commission will address the parties’ contentions with enough clarity for any later reviewing court to comprehend its position.

* * *

We dismiss Allegheny’s petition insofar as it challenges FERC’s rejection of direct assignment. We vacate FERC’s order of a Wesi>-Penn-wide roll-in and remand for the Commission to consider whether or not an adjusted roll-in is appropriate (and such additional alternatives as it may deem appropriate to consider).

So ordered. 
      
      . Actually, Allegheny’s proposal was slightly more complex: the charges were to be governed by PJM's OATT only for the last eleven months of the one-year extension period; for the first month, they were to be governed by a different OATT devised by Allegheny itself. The two OATTs were apparently identical in the .aspect that matters for our opinion, i.e., they both failed to specify rates for sendees below 138 kV. See Addendum to Agreement •(Oct. 19, 2001) at 3-4 and Attachment D (proposing a single rate for subtransmission facilities throughout the one-year extension period, supporting the inference that the facilities not covered by the PJM OATT were the same as those not covered by the Allegheny OATT). Some of our references below to the PJM OATT would be more accurate if we also mentioned the parallel implications of the Allegheny OATT, but since it makes no difference to the analysis, we shall omit such cumbersome details.
     
      
      . The expert did mention the transmission system in his oral testimony, but he said only that some subtransmission facilities were "connected” to the grid, ALJ Hearing Tr. 1/28/03 at 379. As FERC counsel admits, connection does not necessarily mean integration.
     
      
      . The quoted sentence is obviously drawn from Direct Testimony of Farrokhpay, Exh. Staff-3, at 11. Farrokhpay later said the modifier "25 kV" should be corrected to read "subtransmission,” AU Hearing Tr. 1/23/03 at 367, and thus to extend his claim to facilities in north-central and south-central Pennsylvania (which are 12.5 kV, 46 kV, etc.), rather than limit it to western Pennsylvania, where the 25 kV facilities are located. System Map; Legend for AEC Interconnection Points, Exh. Staff-14. Thus Farrokhpay’s sentence, though obscure for the reasons stated in the text, is more supportive of the Commission than the Commission noticed.
     