Nstar Electric & Gas Corporation 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 C OMMISSION ,
RESPONDENT
USGEN NEW ENGLAND , I NC., ET AL .,
I NTERVENORS
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

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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

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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).

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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.

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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.

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* * *
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).

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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

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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

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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

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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

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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

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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’

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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

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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

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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.
* * *
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.

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