NSTAR Electric & Gas Corp. v. Federal Energy Regulatory Commission

United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued December 8, 2006 Decided March 9, 2007

No. 05-1362

NSTAR ELECTRIC & GAS CORPORATION,

PETITIONER

V.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

USGEN NEW ENGLAND, INC., ET AL.,

INTERVENORS

Consolidated with

05-1363

On Petitions for Review of Orders of the

Federal Energy Regulatory Commission

Stephen L. Teichler argued the cause for petitioners.

With him on the briefs were Harvey L. Reiter, John E.

McCaffrey, Lucy H. Plovnick, 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.

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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: Mirant

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

3

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

4

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; Rehearing 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

Rehearing 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).

5

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

“ensur[ing] that the generator remains available during

transmission constraints.” 105 FERC at 62,616 P 2.

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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.

7

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.

8

* * *

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, No. 05-1285, slip op. at 7 (D.C.

Cir. Feb. 13, 2007).

9

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

10

added). And a filing 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

11

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.

* * *

We 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, No. 05-1332, slip op. at 9 (D.C. Cir. Jan. 12,

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 (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. (We follow here the familiar practice of applying

“interchangeably” judicial interpretations of provisions from

the Natural Gas Act to their “substantially identical”

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counterparts in the Federal Power Act. See Arkansas

Louisiana, 453 U.S. at 577 n.7 (quoting FPC v. Sierra Pacific

Power Co., 350 U.S. 348, 353 (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

ratemaking 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

13

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

14

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. § 825l(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, No. 05-1285, slip op. at 5 (D.C. Cir. Feb. 13,

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

15

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 “‘[i]ssues 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 “refus[ing] 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’

16

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

17

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 O&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

18

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.

19

***

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.

* * *

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.