
    NSTAR ELECTRIC & GAS CORPORATION, Petitioner v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent USGen New England, Inc., et al., Intervenors.
    Nos. 05-1362, 05-1363.
    United States Court of Appeals, District of Columbia Circuit.
    Argued Dec. 8, 2006.
    Decided March 9, 2007.
    
      Stephen L. Teichler argued the cause for petitioners. With him on the briefs were Harvey L. Reiter, John E. McCaf-frey, Lucy H. Plovniek, Linda M. Nagel, Mary E. Grover, and Lisa Fink.
    Robert H. Solomon, Solicitor, Federal Energy Regulatory Commission, argued the cause for respondent. With him on the brief were John S. Moot, General Counsel, and Beth G. Pacella, Senior Attorney. Lona T. Perry, Attorney, entered an appearance.
    Howard H. Shafferman argued the cause for intervenor ISO New England Inc. With him on the brief was Perry D. Robinson.
    Allan B. Taylor, Michael P. Shea, Donald K. Dankner, Jeanne M. Dennis, and Margaret H. Claybour were on the brief for intervenors USGen New England, Inc. and New England Power Pool. Raymond B. Wuslich entered an appearance.
    Before: ROGERS and TATEL, Circuit Judges, and WILLIAMS, Senior Circuit Judge.
   Opinion for the Court filed by Senior Circuit Judge WILLIAMS.

WILLIAMS, Senior Circuit Judge.

This dispute involves agreements over the wholesale price of electricity in situations where local transmission shortages obstructed competitive market pricing in the New England power market. Petitioner NSTAR Electric & Gas Corporation seeks review of three orders of the Federal Energy Regulatory Commission: Mir-ant Americas Energy Marketing, L.P., 112 FERC ¶ 61,056 (2005) (“Rehearing Order ”); Mirant Americas Energy Marketing, L.P., 106 FERC ¶ 61,243 (2004) (“Compliance Order ”); and Mirant Americas Energy Marketing, L.P., 105 FERC ¶ 61,359 (2003) (“Remand Order”).

NSTAR challenges the Commission’s orders on what amount to four grounds: first, that the Commission erred in waiving a statutory 60-day notice requirement for changes to filed rates; second, that the Commission’s orders violated the filed rate doctrine and its cousin, the rule against retroactive ratemaking, by allowing certain negotiated rate agreements to govern rates charged prior to their being filed with the agency; third, that the Commission did not satisfy its obligation under 16 U.S.C. § 824e(a) to determine whether the filed rates were just and reasonable; and fourth, that the Commission’s refusal to order refunds for purchasers who were charged the negotiated rates was an abuse of discretion.

We find no merit in petitioners’ first two claims. But we do not find in the record a clear basis for the Commission’s finding that the rates were just and reasonable; this leaves open the possibility of a refund for unjust or unreasonable rates charged. We therefore remand the case for further consideration by the Commission.

The New England Power Pool (the “Power Pool”) is a voluntary trade association of participants in the New England electric power business. In 1998 the Power Pool proposed, and FERC ultimately approved, comprehensive market reforms including a shift of the New England wholesale power market from cost-based regulated prices to market pricing, and the creation of ISO-New England (“ISO-NE”), a private, non-profit entity to administer New England energy markets and operate the region’s bulk power transmission system. See New England Power Pool, 83 FERC ¶ 61,045 (1998) (“NEPOOL I”), 85 FERC ¶ 61,379 (1998) (“NEPOOL II”), reh’g denied 95 FERC ¶ 61,074 (2001) (approving reforms).

Prices in the restructured market are governed by rules developed by the Power Pool (the “Market Rules”) and filed with the Commission under § 205 of the Federal Power Act, 16 U.S.C. § 824d(d). See also NEPOOL II, 85 FERC at 62,459. During normal system operation, ISO-NE uses an incremental pricing scheme: it sets a market-clearing price by working up the range of generators’ bids to find the lowest bid available to supply an increment of power beyond the load demanded for the period in question. Id. at 62,459-60, 62,463. All suppliers receive the same price. Under this system generators are employed in order of “economic merit,” beginning with least-cost units.

During periods of transmission constraint, however, when the constraint makes it impossible to deliver enough conventionally priced energy to a so-called “load pocket,” generators whose bids exceed the market-clearing price are called into service to ensure system reliability. See NEPOOL II, 85 FERC at 62,461; Rehewing Order, 112 FERC at 61,491-92 P 2 & n. 5 (noting “voltage collapse” and other constraint-induced system instabilities). Under Market Rule 17 (in effect during the period in dispute — the mitigation procedures have now been amended), bids offered by these “reliability must run” units did not affect the market-clearing price paid to in-merit generators, and any excess over market was charged to transmission customers as a “congestion uplift” charge. NEPOOL II, 85 FERC at 62,463; see also Rehewing Order, 112 FERC at 61,491 P 2 n. 3.

Initially, FERC anticipated that these uplift charges would be “small and predictable.” NEPOOL I, 83 FERC at 61,237. But it later acknowledged that congestion costs had become “substantial and rapidly increasing,” totaling by one measure some $20 million in March 2000 alone. ISO New England, Inc., 91 FERC ¶ 61,227 at 61,829 n.7 (2000).

Generators called on to operate in constrained conditions will commonly have localized market power; the transmission constraint both justifies use of an out-of-merit resource and accounts for the resource’s market power. Accordingly, Market Rule 17 contained procedures for monitoring and “mitigating” (i.e., capping) such bids either according to a predetermined formula or at a higher alternative price agreed on by ISO-NE and the resource owner. NEPOOL II, 85 FERC at 62,481. Absent an agreement between the generator and the ISO, bids from resources that regularly compete in the unconstrained market were capped at a 30-day weighted average of that generator’s prior in-merit bids. Where a generator seldom ran in merit order (and thus did not have a history of competitive bids), its out-of-merit bids were capped at a default price that could range from 105% to 500% of the market clearing price. NSTAR Electric & Gas Corp., 101 FERC ¶ 61,064 at 61,230 P 24 n. 15 (2002). But Market Rule 17.3.3(b) explicitly allowed agreed-on prices above these caps, saying:

The ISO may enter into negotiation with a resource owner for any reasonable payment terms if the ISO reasonably expects the markets will function more reliably, competitively, or efficiently as a result.

Market Rule 17.3.3(b), Joint Appendix (“J.A.”) 6; see also Compliance Order, 106 FERC at 61,861 P 21 (quoting Rule 17.3.3(b)). In the Remand Order, FERC paraphrased the above formula about the ISO’s expectations in terms of “ensuring] that the generator remains available during transmission constraints.” 105 FERC at 62,616 P 2.

Rule 17.3 sets out the rationale and expected operation of the scheme as applied to seldom-run generators, especially in reference to the parties’ incentives:

The price screen for Resources that seldom run in economic merit order is designed to create a powerful incentive for such generators to come forward and negotiate an appropriate contract with the ISO. The price screen itself is a default case designed to ensure that the ISO has sufficient bargaining leverage in such negotiations. Until the Resource owner and the ISO reach agreement, the default price screen will enable the Resource to be paid for running in the short term, while providing a strong incentive to negotiate an appropriate arrangement with the ISO ... as the screen price rapidly and progressively drops to just 5% above the higher of the same-hour [clearing price] or applicable Reference [clearing price] in the unconstrained market.

Market Rule 17.3.2.2(b), J.A. 4-5.

In earlier proceedings FERC granted power customers’ request for a ruling that the mitigation agreements negotiated under Market Rules 17.3.2.2(b) and 17.3.3(b) were subject to § 205’s filing requirement. Mirant Americas Energy Marketing, L.P., 97 FERC ¶ 61,108 at 61,556/2 (2001). At the same time, however, the Commission exercised its authority under § 205 to grant ISO-NE a waiver of that section’s requirement of 60 days notice prior to the effective dates of the agreements. Id.

On appeal, we granted review of the Mirant orders and remanded for additional explanation of FERC’s waiver of the 60-day notice requirement. NSTAR Electric & Gas Corp. v. FERC, 64 Fed.Appx. 786 (D.C.Cir.2003) (unpublished decision). On remand, FERC conceded that its precedents contemplated waiver of the 60-day notice requirement only in “extraordinary circumstances,” but held that such circumstances existed: the agreements were necessary to ensure the continued availability of generators critical to system stability while mitigating those units’ potential exercise of market power; and, because such generators were typically called into service on short notice, the agreements “by their very nature” could not be negotiated and filed 60 days in advance. Remand Order, 105 FERC at 62,617-18 PP 13-15.

In a separate set of orders, FERC approved ISO-NE’s filing of the mitigation agreements and concluded that the agreements’ provisions were “just and reasonable” as required by § 205(a), 16 U.S.C. § 824d(a). See Mirant Americas Energy Marketing, L.P., 99 FERC ¶ 61,003 at 61,-019 P 16 (2002); Compliance Order, 106 FERC at 61,860 P 14.

On requests for rehearing of the Remand and Compliance orders, FERC affirmed its waiver of the 60-day statutory notice requirement, denial of refunds to purchasers charged the mitigation rates, and determination that the agreements’ provisions were just and reasonable. Rehearing Order, 112 FERC at 61,493-96 (incorporating by reference reasonableness analysis from ISO New England Inc., 112 FERC ¶ 61,057 at 61,498 PP 10-13 (2005)). FERC also rejected the contention, raised on rehearing, that the Commission had exceeded its statutory authority in allowing the rates to become effective prior to their filing date. Rehearing Order, 112 FERC at 61, 494 P 19. NSTAR filed a timely petition for review.

Section 205(d) requires a utility to file a notice 60 days prior to a rate’s taking effect, but expressly provides for waiver of the requirement:

Unless the Commission otherwise orders, no change shall be made by any public utility in any such rate, charge, classification, or service, or in any rule, regulation, or contract relating thereto, except after sixty days’ notice to the Commission and to the public. [But][t]he Commission, for good cause shown, may allow changes to take effect without requiring the sixty days’ notice herein provided for by an order specifying the changes so to be made and the time when they shall take effect and the manner in which they shall be filed and published.

16 U.S.C. § 824d(d).

NSTAR contends that the Commission’s waiver of the 60-day notice rule was arbitrary and capricious and contrary to such agency precedents as Central Hudson Gas & Electric Corp., 60 FERC ¶ 61,106 (“Central Hudson I ”), reh’g denied, 61 FERC ¶ 61,089 (1992) (“Central Hudson II ”). Our review of the Commission’s waiver rulings is “quite limited,” as “Congress, through § 205, has clearly delegated waiver discretion to the Commission and not to the courts.” City of Girard, Kan. v. FERC, 790 F.2d 919, 925 (D.C.Cir.1986); see also San Diego Gas & Electric Co. v. FERC, 904 F.2d 727, 731 (D.C.Cir.1990). And we defer to the Commission’s interpretations of its own precedents. Columbia Gas Transmission Corp. v. FERC, 477 F.3d 739, 742-43 (D.C.Cir.2007).

In Central Hudson I, the Commission stated that “[a]bsent extraordinary circumstances, we will not grant waiver of notice when an agreement for new service is filed on or after the day service has commenced.” 60 FERC at 61,339. Where a rate agreement was filed a week after taking effect, the utility could not simply “state[ ] only that the agreement ... could not be negotiated and prepared for filing 60 days prior to the commencement of service.” Id. “[T]he press of other business,” the Commission held, would not constitute good cause for waiver. Id.

Here, FERC relied on a number of factors in finding extraordinary circumstances. Most critically, it argued that “the mitigation agreements by their very nature do not always lend themselves to being filed 60 days before service commences,” as out-of-merit generators were often called into service “only ... on very short notice.” Remand Order, 105 FERC at 62,618 P 15; see also Rehearing Order, 112 FERC at 61,493 P 13. Moreover, refusing waiver here would wrongly penalize the out-of-merit generators for ISO-NE’s “good faith, albeit erroneous[]” determination that the agreements didn’t need to be filed. Rehearing Order, 112 FERC at 61,494 P 15.

NSTAR claims that FERC improperly ignored the rule of Central Hudson I that the “press of other business” doesn’t constitute good cause. But FERC’s point here was that the delay in filing the mitigation agreements resulted from the need to provide high-cost generation at short notice in response to market constraints. NSTAR says the record does not support the proposition that agreements needed to be negotiated at short notice. But Market Rule 17.3 anticipated that some agreements would be negotiated retroactively: “Normally such arrangements will be negotiated prospectively.” Market Rule 17.3.2.2(b), J.A. 4-5 (emphasis added). And a fifing by ISO-NE indicated that the time consumed in identifying the constrained units and applying the price screens had precluded prospective negotiations. Compliance Order, 106 FERC at 61,861 P 22 & n. 22. NSTAR further objects to FERC’s reliance on ISO-NE’s “good faith” conclusion that the agreements need not be filed. But Central Hudson II explicitly contemplated that the Commission would balance deterrence of violations of the filing requirement against the inappropriateness of making rates confiscatory, 61 FERC at 61,357; the Commission’s consideration of an actor’s good faith seems quite compatible with that balance.

NSTAR also argues that waiver was arbitrary because of purported deficiencies in the negotiation of the agreements, such as that they ratified prior courses of conduct, reflected oral understandings, or were communicated by email. But petitioners do not explain why the Commission should regard such circumstances as undermining the ultimate agreements’ validity. NSTAR also appears to complain that the filed agreements did not cover all time periods relevant to this dispute. But this argument is found in a single footnote in NSTAR’s opening brief, and such a reference is not enough to raise an issue for our review. See Covad Communications Co. v. FCC, 450 F.3d 528, 546 (D.C.Cir.2006); see also Sugar Cane Growers Co-Op. of Florida v. Veneman, 289 F.3d 89, 93 n. 3 (D.C.Cir.2002) (“On appeal, appellants failed to raise their ... claim—a footnote at the end of their opening brief does not suffice.”).

Finally, NSTAR’s assertion that FERC granted waiver before having seen the agreements is without merit, as the orders on review supersede the order to which NSTAR presumably refers. Compare Mirant Americas Energy Marketing, L.P., 97 FERC ¶ 61, 108 at 61,556 (2001), with ISO-NE Compliance Filing, Apr. 22, 2003, J.A. 177 and Rehearing Order, 112 FERC at 61,491.

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? next turn to NSTAR’s assertion that the filed rate doctrine and the rule against retroactive ratemaking precluded FERC from giving effect to the mitigation agreements. We review this claim under the arbitrary and capricious standard of 5 U.S.C. § 706(2)(A), and will affirm where the Commission has articulated a “rational connection between the facts found and the choice made.” Keyspan-Ravenswood, LLC v. FERC, 474 F.3d 804, 809 (D.C.Cir.2007) (applying arbitrary and capricious review to FERC’s conclusion that utility did not violate filed rate doctrine).

The filed rate doctrine arises out of filing requirements in § 205 of the Federal Power Act and parallel sections of other statutes. Originating in the Supreme Court’s cases interpreting the Interstate Commerce Act and subsequently extended “across the spectrum” of regulated utilities, the doctrine “forbids a regulated entity to charge rates for its services other than those properly filed with the appropriate federal regulatory authority.” Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 577, 101 S.Ct. 2925, 69 L.Ed.2d 856 (1981). A corollary is the rule against retroactive ratemaking, which the Supreme Court has described in the context of the Natural Gas Act as “prevent[ing] the Commission itself from imposing a rate increase for gas already sold.” Arkansas Louisiana, 453 U.S. at 578, 101 S.Ct. 2925. (We follow here the familiar practice of applying “interchangeably” judicial interpretations of provisions from the Natural Gas Act to them “substantially identical” counterparts in the Federal Power Act. See Arkansas Louisiana, 453 U.S. at 577 n. 7, 101 S.Ct. 2925 (quoting FPC v. Sierra Pacific Power Co., 350 U.S. 348, 353, 76 S.Ct. 368, 100 L.Ed. 388 (1956)); Consolidated Edison Co. of New York v. FERC, 347 F.3d 964, 969 (D.C.Cir.2003).) We’ve explained the rules as serving the dual purposes of “ensur[ing] rate predictability” for purchasers of regulated electricity and promoting equity among customers by “preventing discriminatory pricing.” Consolidated Edison, 347 F.3d at 969-70.

Although these doctrines and the 60-day notice requirement jointly arise out of § 205, a rate change that qualifies for waiver of the 60-day requirement doesn’t necessarily survive scrutiny under the filed rate and retroactive ratemaking doctrines. See Consolidated Edison, 347 F.3d at 969; see also Columbia Gas Transmission Corp. v. FERC, 895 F.2d 791, 795-97 (D.C.Cir.1990) (“Columbia Gas ”) (holding that analogous waiver provision in Natural Gas Act did not grant the Commission authority to waive the filed rate doctrine). Thus our decision upholding the Commission’s waiver ruling leaves these issues entirely open.

But the filed rate doctrine and bar on retroactive ratemaking are satisfied, in keeping with their functions, “when parties have notice that a rate is tentative and may be later adjusted with retroactive effect, or where they have agreed to make a rate effective retroactively.” Consolidated Edison, 347 F.3d at 969. Notice to affected parties, we have explained, “changes what would be purely retroactive ratemak-ing into a functionally prospective process by placing the relevant audience on notice at the outset that the rates being promulgated are provisional only and subject to later revision.” Columbia Gas, 895 F.2d at 797. See also Exxon Co., USA v. FERC, 182 F.3d 30, 49 (D.C.Cir.1999). One very practical application of this principle is the acceptability of tariffs with a rate formula, under which rates may constantly change (as long as they do so consistently with the formula) without prior notice to the Commission or the public, and are thus not precisely knowable at the time of sale. Pub. Utilities Comm’n v. FERC, 254 F.3d 250, 254 (D.C.Cir.2001).

In its Rehearing Order, FERC relied on these well established principles: “Market Rule 17 allowed ISO-NE to [negotiate the agreements], and ... was the subject of Commission proceedings and Commission approval.” Thus ISO-NE’s authority to negotiate mitigation agreements “was part of a filed and accepted tariff, and market participants were on notice of its provisions.” Rehearing Order, 112 FERC at 61,494 P 19.

Despite NSTAR’s objections, we find nothing arbitrary in the Commission’s conclusion that Market Rule 17.3 provided adequate notice to market participants that the default prices listed in the Market Rules were, in the language of Columbia Gas, “provisional only and subject to later revision.” Both the text and structure of Rule 17.3 put transmission customers on notice that the default rates would apply only absent a separate negotiated agreement. The rule provides: “In place of its bid price, each [seldom-run] Resource ... will receive ... (a) The applicable screen price from Table 1 or Table 2; or (b) A price negotiated with the ISO.” Market Rule 17.3.3, J.A. 5-6. See also Market Rule 17.3.2.2(b), J.A. 4 (“The ISO may determine that some of these [high-cost] Resources should ... have a special contractual arrangement to ensure their availability.”). The Rules also explicitly vest in ISO-NE the authority to negotiate agreements with producers, Market Rule 17.3.3 & n.9, J.A. 5-6, and suggest that agreements may have retroactive effect. See Rule 17.3.2.2(b), J.A. 4-5 (“Normally such arrangements will be negotiated prospectively.” (emphasis added).)

In the face of Market Rule 17’s indisputable notice of possible change, NSTAR claims an incompatibility between the Commission’s finding to that effect and its prior holding that § 205 required filing of the mitigation agreements. See Mirant Americas Energy Marketing, L.P., 97 FERC at 61,556. The Commission objects that we are jurisdictionally barred from hearing this claim under 16 U.S.C. § 825i(b), under which “[n]o objection to the order of the Commission shall be considered by the court unless such objection shall have been urged before the Commission in the application for rehearing unless there is reasonable ground for failure so to do.” But FERC’s discussion of the filed rate doctrine appeared for the first time in its Rehearing Order, 112 FERC at 61,494, and we have held that when FERC makes no change in the result on rehearing but merely supports the old outcome with new arguments, a party can obtain judicial review without filing a new petition for rehearing. Columbia Gas Transmission Corp. v. FERC, 477 F.3d 739, 741-42 (D.C.Cir.2007).

Though properly before us, NSTAR’s claim is unconvincing. In our view there is no necessary incompatibility between the Commission’s holdings. For one thing, requiring the mitigation agreements (even those with retroactive effect) to be filed under § 205 facilitates complaints by purchasers under § 206, 16 U.S.C. § 824e(a) — a function independent of the considerations underlying the filed rate doctrine. Moreover, Columbia Gas’s discussion of rates that are “provisional only and subject to change” did not contain any suggestion that FERC lacked authority to require filling of the documents implementing the adjustments prefigured in the earlier filings. (The parties here do not appeal FERC’s determination that the mitigation agreements must be filed under § 205.)

NSTAR’s next contention is that the Commission did not fulfill its statutory obligation to ensure that the rates contemplated by the mitigation agreements were just and reasonable. See 16 U.S.C. § 824d(a). Our review of such determinations is “highly deferential,” as “ ‘[ijssues of rate design are fairly technical and, insofar as they are not technical, involve policy judgments that lie at the core of the regulatory mission.’ ” Northern States Power Co. v. FERC, 30 F.3d 177, 180 (D.C.Cir.1994) (quoting Town of Norwood v. FERC, 962 F.2d 20, 22 (D.C.Cir.1992)) (alteration in original). But the Commission must demonstrate that it has “made a reasoned decision based upon substantial evidence in the record,” and “the path of [its] reasoning must be clear.” Sithe/Independence Power Partners, L.P. v. FERC, 165 F.3d 944, 948 (D.C.Cir.1999) (alteration in original, internal quotation marks omitted).

NSTAR’s primary complaint is that FERC did not independently assess whether the mitigation agreements were just and reasonable. See NSTAR Electric & Gas Corp., Request for Rehearing at 6 (Apr. 8, 2004), J.A. 324, 329 (arguing that the Commission erred in “refusing] to obtain and independently review the cost support data for the mitigation agreements”). We note, however that NSTAR does not mount — and thus we do not here consider — any substantive challenge to the reasonableness of the agreements’ formulas or rates. See Compliance Order, 106 FERC at 61,861 PP 19-20.

FERC said in the Compliance Order that it “reviewed the agreements, and, based on that review, ... we find that they are reasonable.” 106 FERC at 61,860 P 14. FERC rejected NSTAR’s idea that the agreed rates could survive only if strictly based on cost (presumably referring to conventional historic accounting cost); rather it found it “reasonable” for ISO-NE to have negotiated prices aimed at assuring the availability of the units in question “when needed to protect system reliability.” Id. at 61,860 P 15. FERC noted that the agreements compensated generators based on “average variable costs or marginal costs, plus an adder” and that in “most” of the agreements, the adder was “a percentage of variable costs (usually ten percent).” Id. at 61,861 & n. 18. The New Boston generators, for example, FERC said, were compensated at 110% of “fuel, compressor fuel, variable operation and maintenance and fuel transportation costs.” Id. The Commission ultimately concluded that the adders were “reasonable compensation for such units to reflect lost opportunity costs” (the exact nature of the opportunities foregone is never explored), and rejected the contention that recovery of fixed costs would be per se inappropriate, given that the units in question were “essential ... for reliability purposes and only rarely run in economic merit order.” Id. at 61,861 P 17.

We find, however, a critical gap in this reasoning. The bare fact that the agreements set compensation at a percentage of fixed or variable costs does not support the conclusion that the rates contained in the agreements are just and reasonable when the Commission lacks data concerning the generators’ costs. Many of the agreements contained no actual cost data for relevant time periods. For instance, according to ISO-NE’s filing, the Yarmouth and Mason generators were compensated, respectively, at average variable cost and a sum of “fuel cost, variable 0 & M cost and contributions to fixed cost,” but, so far as appears, no cost data were provided for FERC’s review. See ISO-NE Compliance Filing, Summary of Negotiated Arrangements and Cost Data, Apr. 22, 2003, J.A. 186, 225-27. Similarly, the Bridgeport Harbor 3 unit was mitigated at “actual fuel cost, emissions cost, variable O & M, plus 10 percent of such costs,” but the filing contained no cost data. Id. at 186; cf. J.A. 182-83, 193-97 (Salem Harbor 4 generator’s bids capped at $125/hour); J.A. 183, 211-12 (New Boston unit mitigated at 110% of certain enumerated costs, resulting in approximate mitigation price of $69.90/MWh).

FERC’s primary response to this objection is that, under Market Rule 17.3, ISO-NE was authorized to negotiate for “reasonable payment terms” only where it “reasonably expect[ed] the markets w[ould] function more reliably, competitively or efficiently as a result.” Market Rule 17.3.3(b) n.9, J.A. 6. Thus, the Commission concluded, the agreements were “negotiated in a manner that produced reasonable results.” Compliance Order, 106 FERC at 61,861 P 18. In fact, the record does give reason to believe that the generators filed cost data with ISO-NE— if not the Commission — for its review. See ISO-NE Compliance Filing at J.A. 211 (cost figures “subject to true-up” by ISO-NE after generator filed cost data).

But the Commission does not explain its basis for believing that the ISO’s actions satisfied the statutory requirement. Given the apparent absence of effective monitoring by the Commission itself (in the form of independent review of cost data), we should think, as a first approximation, that ISO-NE’s scrutiny could work as a substitute only if ISO-NE had both incentive and ability to bargain for “reasonable” rates (i.e., rates not materially exceeding the range needed to assure availability of the needed generating capacity). Although the system operator plainly has an incentive to ensure that system-critical power is available to ensure grid stability and reliability, FERC neither in its decisions nor at oral argument was able to identify incentives driving ISO-NE to bargain for low prices. See Or. Arg. Transcript at 25-26. We note that the Market Rules explained that the price cap applicable in the absence of agreement served as “a default case designed to ensure that the ISO has sufficient bargaining leverage in such negotiations,” Market Rule 17.3.2.2(b), J.A. 5, but in the orders before us the Commission neither invoked that proposition nor discussed the incentives of the ISO. While we by no means foreclose the possibility of FERC’s reliance on a market participant with appropriate incentives and strategic position, FERC has made no showing that such conditions exist here. See Tejas Power Corp. v. FERC, 908 F.2d 998 (D.C.Cir.1990) (rejecting FERC’s reliance on participants’ agreement to pipeline’s gas inventory charge where FERC made no finding that pipeline lacked market power at time of agreement). Nor, of course, do we mean to suggest that only prices in line with historic accounting costs would qualify as just and reasonable.

Thus neither FERC’s reasonableness analysis nor its stated reliance on ISO-NE’s actions appears to have satisfied its statutory obligation to ensure that rates are just and reasonable.

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Finally, NSTAR asserts that the Commission erred in denying refunds to consumers for the difference between the mitigation rates and the Rule’s reference prices. To the extent NSTAR’s refund demand relies on its claims under the 60-day notice requirement, filed rate doctrine and rule against retroactive ratemaking, it cannot survive our rejection of those claims.

Our remand with respect to FERC’s procedure for determining that the mitigation rates were just and reasonable poses a different question. As we noted above, NSTAR has not here attacked the substance of that determination, though it and others apparently did before the Commission. See Compliance Order, 106 FERC at 61,860 P 11 (summarizing protestors’ demand for refund of “amounts paid under the agreements that are found to be unlawful, unjust, or unreasonable”). If that omission poses no procedural bar to such refund claims, and if on remand some of the rates are found unjust or unreasonable, presumably the Commission would go on to consider an award of refunds.

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In sum, we find no merit in NSTAR’s first or second claim, but remand to the Commission for additional consideration of whether the rates adopted in the mitigation agreements were just and reasonable and, given that analysis, whether petitioners are entitled to any refund of amounts charged under those agreements.

So ordered.  