United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued February 14, 2008 Decided March 28, 2008

No. 06-1403

MAINE PUBLIC UTILITIES COMMISSION

PETITIONER

v.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

CONNECTICUT DEPARTMENT OF PUBLIC UTILITY CONTROL, ET

AL.,

INTERVENORS

Consolidated with

06-1427, 07-1193

On Petitions for Review of Orders of the

Federal Energy Regulatory Commission

Lisa Fink, Attorney, Maine Public Utilities Commission,

and John S. Wright, Assistant Attorney General, Attorney

General’s Office of State of Connecticut, argued the cause for

petitioners. With them on the briefs were Lisa S. Gast, L. Elise
2

Dieterich, Richard Blumenthal, Attorney General, Attorney

General’s Office of State of Connecticut, Michael C.

Wertheimer, Assistant Attorney General, Martha Coakley,

Attorney General, Attorney General’s Office for the

Commonwealth of Massachusetts, and Jesse S. Reyes, Assistant

Attorney General.

Donald J. Sipe, Mary E. Grover, Stephen L. Teichler,

Robert A. Weishaar, Jr., and Vasiliki Karandrikas were on the

briefs for intervenors in support of petitioners. Jonathan G.

Mermin and Linda S. Lockhart entered appearances.

Jeffery S. Dennis, Attorney, Federal Energy Regulatory

Commission, argued the cause for respondent. With him on the

brief were Cynthia A. Marlette, General Counsel, and Robert H.

Solomon, Solicitor.

John N. Estes, III argued the cause for intervenors FPL

Energy, LLC. With him on the brief were Randall L. Speck,

Scott Harris Strauss, Scott Phillip Myers, James Kilburn

Mitchell, Paul Franklin Wight, Larry F. Eisenstat, George E.

Johnson, Christopher C. O’Hara, Kenneth L. Wiseman, Mark F.

Sundback, Christopher Rhodes Jones, Kenneth Richard

Carretta, David Talmage Musselman, and Aaron James

Bullwinkel. Jennifer L. Spina entered an appearance.

Sherry A. Quirk, Robin E. Remis, and Kathleen A. Carrigan

were on the brief for intervenor ISO New England Inc. in

support of respondent. Kerim P. May entered an appearance.

Barry S. Spector and Paul M. Flynn were on the brief for

amicus curiae PJM Interconnection, L.L.C. in support of

respondent.
3

1

 It would have been helpful if the parties had actually defined

“capacity” before delving into the intricacies of New England’s

capacity market. Also, the briefs would have been much easier to read

if the parties had used fewer acronyms.

Before: ROGERS and GARLAND, Circuit Judges, and

SILBERMAN, Senior Circuit Judge.

PER CURIAM: The consolidated petitions for review

challenge FERC’s approval of a comprehensive settlement that

redesigned New England’s capacity market. The Maine Public

Utilities Commission and the Attorneys General of Connecticut

and Massachusetts assert that FERC’s approval of the settlement

was arbitrary and capricious, contrary to law, and beyond the

Commission’s jurisdiction. We reject most of these arguments,

but we agree with the petitioners that the Commission has

unlawfully deprived non-settling parties of their rights under the

Federal Power Act.

I.

In a “capacity” market – as opposed to a wholesale

electricity market – “the [transmission provider] compensates

the generator for the option of buying a specified quantity of

power irrespective of whether it ultimately buys the electricity.”1

Keyspan-Ravenswood, LLC v. FERC, 474 F.3d 804, 806 (D.C.

Cir. 2007). In order to maintain the reliability of the grid,

transmission providers generally purchase more capacity than is

necessary to meet their customers’ demand for electricity. This

ensures that the transmission providers are able to respond

adequately to unexpected fluctuations in demand.

For many years, New England’s capacity market has been
4

2

 An ISO is an independent company that has operational

control, but not ownership, of the transmission facilities owned by

member utilities. ISOs “provide open access to the regional

transmission system to all electricity generators at rates established in

a single, unbundled, grid-wide tariff . . . .” Midwest ISO Transmission

Owners v. FERC, 373 F.3d 1361, 1364 (D.C. Cir. 2004) (citation

omitted). In 2004, the New England ISO was organized as a Regional

Transmission Organization (“RTO”). RTOs are given greater

regulatory flexibility by FERC, provided that they (inter alia): are

regional in scope, have exclusive operational control over all

transmission facilities within their control, and have sole authority to

approve or deny requests for transmission service. Id. at 1365.

rife with problems. As the Commission explained in 2003,

“existing generators needed for reliability are not earning

sufficient revenues (and are in fact losing money), and [ ]

additional infrastructure is needed soon to avoid violations of

reliability criteria.” Devon Power LLC, 115 FERC ¶ 61,340 at

62,315 (2006). In other words, the supply of capacity was

barely sufficient to meet the region’s demand.

FERC, the generators, the transmission providers, and the

power customers have made several attempts to address these

issues. In 2003, a group of generators sought to enter into

“Reliability Must-Run” agreements with the New England

Independent System Operator (“ISO”), which operates the

transmission system in New England.2

 Under a Must-Run

agreement, a financially-troubled generator in an area with

supply shortages may recover up to its full cost-of-service in

order to remain in operation. Those agreements have several

important drawbacks. As FERC explained:

[Must-Run] contracts suppress market-clearing prices,

increase uplift payments, and make it difficult for new
5

3

 Although the parties refer to this as a “demand curve,” that

term is misleading. Normally, a “demand curve” is a model of the

relationship between prices and consumer preferences in a free market.

In contrast, the “demand curve” proposed by the ISO is an entirely

generators to profitably enter the market. . . . [E]xpensive

generators under [Must-Run] contracts receive greater

revenues than new entrants, who would receive lower

revenues from the suppressed spot market price. In short,

extensive use of [those] contracts undermines efficient

market performance.

Devon Power LLC, 103 FERC ¶ 61,082 at 61,270 (2003). For

these reasons, FERC accepted the Must-Run agreements filed by

the New England generators, but only allowed these generators

to recover certain maintenance costs, not their full cost-ofservice. Id. at 61,270-71.

In its orders addressing the Must-Run agreements, the

Commission simultaneously directed the ISO to develop a new

market mechanism that would include a location requirement.

Id. at 61,271. In a locational market, prices are set separately for

various geographical sub-regions. Thus, prices would be highest

in the regions with the most severe capacity shortages, which

would encourage new entry.

In response to FERC’s directive, the ISO proposed a

locational capacity market structure in March 2004. This

proposed market mechanism included four sub-regions, each of

which would have a monthly auction for capacity. The auctions

would be based on an “administratively-determined demand

curve” that would establish the price and quantity of capacity

that must be procured within each sub-region.3

 Devon Power
6

artificial construct that specifies the prices that must be paid for

various quantities of capacity. 107 FERC at 62,022; see also Elec.

Consumers Res. Council v. FERC, 407 F.3d 1232, 1234-35 (D.C. Cir.

2005) (explaining the construction of a similar “demand curve” by the

New York ISO). This proposal was intended to make revenues and

price movements more stable and predictable. 107 FERC at 62,022.

That may or may not have been sound policy, but it more accurately

should be termed a “non-demand demand curve” reminiscent of the

once regulatory invention, a “non-bank bank.”

LLC, 107 FERC ¶ 61,240 at 62,022 (2004). FERC commended

the ISO for adopting a locational pricing mechanism that took

account of transmission constraints between different subregions within New England. Id. at 62,028. However, the

demand curve proposed by the ISO was extremely controversial

– numerous parties submitted comments and testimony

regarding the proper height and slope of the curve. Id. at

62,031. FERC set the matter for hearing before an

Administrative Law Judge (“ALJ”).

In June 2005, the ALJ issued a 177-page order that largely

accepted the ISO’s proposed demand curve. Devon Power LLC,

111 FERC ¶ 63,063 (2005). Several parties filed exceptions to

this decision, arguing that the ALJ wrongfully excluded

evidence and failed to respond to comments about flaws in the

ISO’s demand curve. On September 20, 2005, the full

Commission held an all-day oral argument on the locational

market structure and the proposed demand curve. FERC

subsequently established settlement procedures to allow the

parties to develop a new market mechanism.

After four months of negotiations involving 115 parties, a

settlement was reached. As FERC has repeatedly reminded us,

only eight of these parties opposed the final settlement. 115
7

FERC at 62,306. The key feature of the settlement agreement

is the Forward Capacity Market, which would replace the ISO’s

earlier proposal and eliminate the need for the controversial

demand curve. Under the Forward Market, there will be annual

auctions for capacity, which will be held three years in advance

of when the capacity is needed. Id. The settling parties

determined that a three-year lead time will “provide for a

planning period for new entry and allow potential new capacity

to compete in the auctions.” Id. Each transmission provider

will be required to purchase enough capacity to satisfy its

“installed capacity requirement,” which is the minimum level of

capacity that is necessary to maintain reliability on the grid. Id.

at 62,307. As FERC requested, the Forward Market also

includes a locational component – the annual auctions will be

held in different “capacity zones” based on transmission

constraints between the various sub-regions within New

England. Id.

The most contentious issue regarding the Forward Market

is the set of “transition payments” that will be required from

December 1, 2006 until June 1, 2010. As explained above, the

Forward Market provides for a three-year lead time in the

capacity auctions, in order to allow new entrants to bid in the

auctions. However, this leaves a three-year gap between the

first auction and the time when the capacity procured in this

auction will be provided. The parties addressed this issue by

negotiating a series of fixed payments that will be paid to

generators during the transition period. 115 FERC at 62,308.

The agreement also provides that challenges to the transition

payments and the final Forward Market auction clearing prices

– regardless of whether the challenge is brought by a settling

party, a non-settling party, or the Commission – will be

adjudicated under the highly-deferential “public interest”

standard rather than the usual “just and reasonable” standard.
8

Id. at 62,332-33.

On June 16, 2006, FERC approved the settlement

agreement, finding that “as a package, it presents a just and

reasonable outcome for this proceeding consistent with the

public interest.” Id. at 62,304. Most importantly, the

Commission determined that the settlement would address the

problems that had plagued New England’s capacity market:

The settlement package, including both the [Forward

Market] and the interim transition mechanism, resolves the

issues raised in this proceeding concerning the undercompensation of capacity resources in New England, and

provides the appropriate market structure to ensure that

generating resources are appropriately compensated based

on their location and contribution to system reliability and

provides incentives to attract new infrastructure where

needed.

Id. at 62,316. FERC conceded that the transition payments were

not ideal “as a single market design element,” but concluded that

they were a “reasonable transitory mechanism that enables the

New England region to shift to the [Forward Market].” Id. at

62,319. In particular, the Commission determined that the

transition payments “fall at the very low end” of the range of

demand curves (prices) submitted by Maine and the ISO during

the litigation over the ISO’s previous market structure proposal.

Id. at 62,321. FERC also approved the agreement’s

incorporation of the “public interest” standard of review because

use of the more deferential standard in a limited number of

circumstances would promote “rate stability.” Id. at 62,335.

After FERC denied rehearing, the Maine Public Utilities

Commission and the Attorneys General of Connecticut and
9

4

 The orders under review are Devon Power LLC, 115 FERC

¶ 61,340 (2006); Devon Power LLC, 117 FERC ¶ 61,133 (2006); ISO

New England, Inc., 117 FERC ¶ 61,132 (2006); and ISO New

England, Inc., 119 FERC ¶ 61,044 (2007). 

Massachusetts petitioned for review, arguing that the

Commission’s approval of the settlement was arbitrary and

capricious, contrary to law, and beyond the scope of FERC’s

jurisdiction.4

 Specifically, petitioners assert that: (1) FERC’s

acceptance of the transition payments was arbitrary and

capricious because the record did not contain sufficient data

about generators’ costs; (2) FERC unreasonably accepted the

transition payments even though the payments did not include

a locational pricing mechanism; (3) FERC unlawfully accepted

a “Mobile-Sierra” provision that imposed the deferential “public

interest” standard of review on rate challenges brought by nonsettling parties; and (4) FERC lacks jurisdiction to approve the

settlement agreement because the Forward Market will

effectively force states to acquire a specific level of capacity.

For the reasons set forth below, we grant the petition for review

with respect to the Mobile-Sierra issue, but we deny the petition

with respect to the other three issues.

II.

The petitioners argue that FERC’s approval of the

settlement’s transition payments was arbitrary and capricious, in

violation of the Administrative Procedure Act, 5 U.S.C. §

706(2)(A). To withstand review under that standard, FERC

must have “examine[d] the relevant data and articulate[d] a

satisfactory explanation for its action including a ‘rational

connection between the facts found and the choice made.’”
10

Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co.,

463 U.S. 29, 43 (1983) (quoting Burlington Truck Lines, Inc. v.

United States, 371 U.S. 156, 168 (1962)). The Commission’s

findings of fact, “if supported by substantial evidence,” are

conclusive. 16 U.S.C. § 825l(b). When the record would

support more than one outcome, we must uphold FERC’s order

because “[t]he question we must answer . . . is not whether

record evidence supports [the petitioner’s desired outcome], but

whether it supports FERC’s.” Fla. Mun. Power Agency v.

FERC, 315 F.3d 362, 368 (D.C. Cir. 2003). See generally

NorAm Gas Transmission Co. v. FERC, 148 F.3d 1158, 1162

(D.C. Cir. 1998) (“[I]n reviewing the Commission’s approval of

a contested settlement, we must determine whether the

Commission has supplied a ‘reasoned decision’ that is supported

by ‘substantial evidence.’” (quoting 18 C.F.R. §

385.602(h)(1)(I)).

In this case, after considering the merits of the settlement as

a whole, FERC examined the record evidence and concluded

that the transition payments fell within a “reasonable range of

capacity prices.” 115 FERC at 62,319. The Commission

correctly noted that there is not a single “just and reasonable

rate” but rather a zone of rates that are just and reasonable; a just

and reasonable rate is one that falls within that zone. Id.; see

Montana-Dakota Utils. Co. v. N.W. Pub. Serv. Co., 341 U.S.

246, 251 (1951) (“Statutory reasonableness is an abstract quality

represented by an area rather than a pinpoint. It allows a

substantial spread between what is unreasonable because too

low and what is unreasonable because too high.”); Pac. Gas &

Elec. Co. v. FERC, 306 F.3d 1112, 1116 (D.C. Cir. 2002)

(“[T]he court may only set aside a rate that is outside a zone of

reasonableness, bounded on one end by investor interest and the

other by the public interest against excessive rates.”); cf. In re

Permian Basin Area Rate Cases, 390 U.S. 747, 767 (1968)
11

(“[T]his Court has often acknowledged that the Commission is

not required by the Constitution or the Natural Gas Act to adopt

as just and reasonable any particular rate level; rather, courts are

without authority to set aside any rate selected by the

Commission which is within a ‘zone of reasonableness.’”);

ExxonMobil Gas Mktg. Co. v. FERC, 297 F.3d 1071, 1084 (D.C.

Cir. 2002) (“The burden is on the petitioners to show that the

Commission’s choices are unreasonable and its chosen line of

demarcation is not within a zone of reasonableness as distinct

from the question of whether the line drawn by the Commission

is precisely right.” (internal quotation marks omitted)).

In challenging FERC’s decision to approve the transition

payments, the petitioners argue that there was no record

evidence of existing generators’ costs and that without such

evidence FERC could not find that the payments fell within a

reasonable range of capacity prices. In its early orders in Devon

Power, however, FERC determined that reliance on

individualized cost recovery proceedings was not a policy in the

public interest and that, instead, capacity payments should be

made to all suppliers with a single market-clearing price. See,

e.g., Devon Power LLC, 110 FERC ¶ 61,315 at 62,227 (2005).

FERC is correct that it need not rely on generators’ costs to

determine rates. The Supreme Court has disavowed the notion

that rates must depend on historical costs and has held that rates

may be determined by a variety of formulae. See, e.g., FPC v.

Hope Natural Gas Co, 320 U.S. 591, 602 (1944) (“[T]he

Commission [i]s not bound to the use of any single formula or

combination of formulae in determining rates.”); see also Mobil

Oil Corp. v. FPC, 417 U.S. 283, 316 (1974) (“Mobil’s argument

assumes that there is only one just and reasonable rate possible

for each vintage of gas, and that this rate must be based entirely

on some concept of cost plus a reasonable rate of return. We

rejected this argument in Permian Basin and we reject it again
12

5

 The petitioners cite NSTAR Electric & Gas Corp. v. FERC,

481 F.3d 794 (D.C. Cir. 2007), for the proposition that FERC cannot

approve a rate without reviewing cost data, but this mischaracterizes

the holding of that case. In NSTAR, FERC approved contracts

between ISO-New England and certain generators because those

contracts provided compensation to generators at a percentage of fixed

or variable costs. We remanded the case because, although FERC’s

rationale relied on costs, there was no substantial evidence of those

costs in the record. The NSTAR court specifically recognized,

however, that FERC need not always rely on historic cost data. See id.

at 804 (“Nor, of course, do we mean to suggest that only prices in line

with historic accounting costs would qualify as just and reasonable.”).

here.”); Am. Pub. Power Ass’n v. FPC, 522 F.2d 142, 146 (D.C.

Cir. 1975) (“Congress carefully eschewed tying ‘just and

reasonable’ rates to any particular method of deriving the rates.

Certainly there is nothing in the Federal Power Act specifically

endorsing historic test year ratemaking or any other technique of

ratemaking. Congress clearly intended to allow the Commission

broad discretion in regard to the methodology of testing the

reasonableness of rates.”).5

Of course, FERC cannot pluck rates out of thin air; it must

rely on record evidence to establish a reasonable range of rates.

But contrary to the petitioners’ suggestion, FERC’s statement

that “the transition payments are reasonable rates for existing

generators until the [Forward Market] begins,” 115 FERC at

62,321, was not simply an assertion but rather a conclusion

based on the Commission’s analysis of two pieces of record

evidence: (1) projected prices under demand curves introduced

by Maine and Vermont load representatives and by ISO-New

England at the hearing on the locational installed capacity

mechanism, and (2) the estimated cost of entry for a new peaker

unit. Only after reviewing this evidence to establish a “zone of
13

reasonableness” did FERC conclude that the transition payments

fell within the zone. Id.; see also 117 FERC at 61,718

(discussing FERC’s reliance on demand curve and cost of new

entry evidence in evaluating the transition payments).

In establishing the reasonable range of capacity prices,

FERC first reviewed evidence introduced at the hearing on the

locational installed capacity mechanism (which was later

replaced by the Forward Market). FERC decided to look at

projected prices for Maine and Northeastern Massachusetts

under both the demand curve proposed by Maine and Vermont

load representatives and the demand curve proposed by the ISO.

The Commission acknowledged that these were not the only two

demand curves proposed at the hearing, but, as it explained more

fully in the order on rehearing, it chose to rely on these two

curves because they came from two different sectors. Load

representatives offered demand curves that projected low prices,

while supplier representatives offered demand curves that

projected high prices; thus, FERC noted that “[i]f the

Commission relied only upon demand curves proposed by

parties representing load, the transition payments may have

appeared excessive; relying only on demand curves proposed by

suppliers would imply that the transition payments were

inadequate.” 117 FERC at 61,719. FERC accordingly

“conclude[d] that relying on proposed demand curves from a

single sector would have been unreasonable” and focused on

two curves – from two different sectors – that provided a narrow

range of price projections. Id.; see also 115 FERC at 62,319-20.

Comparing the transition payments to these demand curve

projections, FERC found that the transition payments fell within

the range of capacity prices projected by both demand curves.

115 FERC at 62,321.

The petitioners object that FERC improperly relied on the
14

demand curves as a basis of comparison because FERC did not

expressly find them to be just and reasonable. Since it never

made that finding, the petitioners insist, FERC could not rely on

the demand curves to find that the transition payments were

reasonable. It is true that FERC may not use unexamined rates

as a basis of comparison. Cf. Laclede Gas Co. v. FERC, 997

F.2d 936, 946-47 (D.C. Cir. 1993). But here, FERC examined

the record evidence and concluded that these two curves

“establishe[d] a reasonable range of capacity prices for

comparison.” 117 FERC at 61,719; see also 115 FERC at

62,319-21. FERC’s determination that these curves offered a

reasonable range of prices for comparison was further supported

both by the fact that FERC had explicitly endorsed the demand

curve approach in earlier orders, see 110 FERC at 62,221

(“[W]e preliminarily find the use of ICAP regions and an ICAP

demand curve as proposed by ISO-NE to be just and reasonable

. . . .”); Devon Power LLC, 107 FERC ¶ 61,240 at 62,031 (2004)

(“We agree with ISO-NE’s overarching proposal to use a

demand curve, and in particular a downward sloping demand

curve, as part of the eventual LICAP mechanism in New

England.”), and by the fact that the administrative law judge had

adopted the ISO’s demand curve – which contained higher price

projections than the Maine-Vermont curve – after a lengthy

proceeding, Devon Power LLC, 111 FERC ¶ 63,063 at 65,217

(2005) (“[T]he undersigned finds the ISO’s demand curve

proposal to be just and reasonable . . . .”); see 115 FERC at

62,319 (“[T]he Initial Decision did adopt ISO-NE’s proposal .

. . .”); see also id. at 62,320-21. In light of this evidence,

FERC’s determination was sufficient. A binding merits decision

was not required; indeed, such a requirement would largely

vitiate the purpose of a settlement.

The petitioners also object to FERC’s reliance on evidence

of the estimated cost of new entry to determine a reasonable
15

range of rates. The petitioners raise two concerns. First, they

argue that cost of new entry represents the estimated costs of a

new peaker, not those of an existing generator, and that the two

may have different capital costs. The Commission determined,

however, that new peakers have “capital costs [that] are lower

than most, if not all, other plants.” 115 FERC at 62,321. Hence,

if cost of new entry is used as a reference point, the transition

payments “are likely to be significantly lower than a cost-ofservice payment for most, if not all, new generators.” Id.; see id.

at 62,319 (concluding that “in the first years,” the transition

“payments are less than the cost of new entry, accurately

reflecting market conditions”).

Second, the petitioners argue that cost of new entry is an

arbitrary reference point for the transition period because,

although cost of new entry provides a starting point for the

Forward Market auction, the Forward Market does not exist

during the transition period. But the fact that cost of new entry

is used to kick off the auction does not mean that it is relevant

only for that purpose. If anything, the reliance on cost of new

entry as a starting point of the Forward Market auction

underscores its relevance to appropriate rates: it is used to

commence the auction because it approximates reasonable

compensation for existing as well as new generators. See id. at

62,326. FERC sets rates to ensure both that existing generators

are adequately compensated and that prices support new entry

when additional capacity is needed. See, e.g., Recording of Oral

Arg. at 1:02:34-1:03:01, 1:09:30-1:10:35. As FERC therefore

noted, cost of new entry is “a key factor in determining

appropriate rates for capacity” and was central to the demand

curves under the locational installed capacity market as well as

the Forward Market design. 117 FERC at 61,718; cf. Elec.

Consumers Res. Council v. FERC, 407 F.3d 1232, 1235, 1237-

38 (D.C. Cir. 2005) (upholding FERC’s approval of a demand
16

curve that sets prices based on the annualized cost of a new

peaker plant); New York Indep. Sys. Operator, Inc., 117 FERC

¶ 61,086 at 61,443 n.7 (2006) (“In a competitive market, prices

should reach equilibrium at or near to the levelized net cost of

new entry.”). We conclude that it was reasonable for the

Commission to look to cost of new entry as a basis of

comparison in its review of the transition payments.

 

Finally, the petitioners claim that FERC did not respond

meaningfully to their objections to the transition payments. See

PPL Wallingford Energy LLC v. FERC, 419 F.3d 1194, 1198

(D.C. Cir. 2005) (“An agency’s ‘failure to respond

meaningfully’ to objections raised by a party renders its decision

arbitrary and capricious.” (quoting Canadian Ass’n of Petroleum

Producers v. FERC, 254 F.3d 289, 299 (D.C. Cir. 2001))).

Specifically, the petitioners argue that FERC did not address the

argument of the Attorneys General that the transition payments

do not reflect market conditions, reliability contributions, or

cost-of-service; and they cite testimony by an expert witness that

the transition payments are significantly in excess of what is

needed to retain existing resources because many generators rely

in part on sources of energy other than oil and gas (e.g., nuclear

and hydro power). The Commission did, however, respond to

these objections, discussing the long-term commitment and

enhanced reliability contributions of generators that the

transition payment mechanism requires. See 115 FERC at

62,322; 117 FERC at 61,720, 61,724. FERC also rejected the

petitioners’ premise that their expert’s testimony was the only

relevant evidence about whether the transition payments were

reasonable and explained that cost of new entry and the demand

curves were relevant evidence. E.g., 117 FERC at 61,718-20.

In short, FERC’s conclusion that the transition payments fell

within a reasonable range of capacity prices was a reasoned
17

6

 The petitioners also argue that FERC acted arbitrarily and

capriciously in ordering an overbroad remedy to the market problem

it had identified. According to the petitioners, the ongoing use of

Reliability Must-Run contracts during the transition period

contravenes FERC’s initial desire to implement a market structure to

replace Must-Run contracts. This objection was not raised before the

agency and is therefore waived. See 16 U.S.C. § 825l(b) (“No

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.”).

decision supported by substantial evidence.6

 

III.

Petitioner Maine Public Utilities Commission (Maine PUC)

argues that FERC’s acceptance of non-locational pricing during

the transition period was arbitrary and capricious, attacking

FERC’s decision on both general and specific grounds.

At a general level, Maine PUC contends that FERC acted

arbitrarily in approving non-locational transition payments when

FERC had previously insisted that a locational structure was

necessary for New England. Maine PUC’s claim is that, by

approving non-locational transition payments, FERC abandoned

the core of the market reform it set out to implement, a

mechanism that would “appropriately value capacity resources

according to their location.” Pet’r Br. 48 (quoting Devon Power

LLC, 109 FERC ¶ 61,154 at 61,631 (2004)). But the Forward

Market, which is the ultimate product of the settlement, includes
18

7

 For the Forward Market, capacity is purchased three years

in advance, so the full market design, including the locational element,

cannot be implemented until 2010.

locational pricing.7 Hence, the settlement does satisfy FERC’s

initial concern about non-locational pricing. See 115 FERC at

62,322 (“The locational feature in the [Forward Market]. . .

appropriately addresses on a long-term basis issues regarding

payments to capacity in constrained regions.”); 117 FERC at

61,720 (“In the June 16 Order, we concluded that the [Forward

Market] itself appropriately recognizes location.”); see also 115

FERC at 62,325 (accepting the locational feature of the Forward

Market). The fact that the transition period lacks a locational

component does not change the fact that the ultimate result of

the settlement proceedings is a new market structure that does

account for location.

Maine PUC’s specific contention is that separate prices are

warranted for Maine during the transition period because Maine

has a capacity surplus and is export constrained (so that it would

experience lower capacity prices in an actual market). It

maintains that FERC refused to consider the evidence that it

presented to support this contention. But FERC did consider

Maine’s argument that it should pay lower transition payments

because of its capacity surplus. The Commission offered two

interrelated reasons for its conclusion that the transition

payments should not have a locational component. First, FERC

cited record evidence that projected “little to no variability in

capacity prices across New England regions for the period

covered by the transition mechanism.” 115 FERC at 62,322.

Second, to the extent that import constraints do exist in other

areas of New England, thereby creating a need for additional

capacity, FERC noted that Reliability Must-Run agreements had
19

already been approved and would continue during the transition

period, with the costs for these contracts paid locally. Id.

To be sure, Maine PUC offered some contradictory

evidence about capacity price variability, see, e.g.,J.A. 1941-47

(Supplemental Affidavit of Thomas D. Austin), but FERC’s

orders do “not lack substantial evidence simply because

petitioners offered some contradictory evidence,” Ariz. Corp.

Comm’n v. FERC, 397 F.3d 952, 954 (D.C. Cir. 2005) (internal

quotation marks omitted). FERC was entitled to reject Maine

PUC’s evidence and to base its conclusion on different evidence

in the record. See, e.g., Elec. Consumers Res. Council, 407 F.3d

at 1236 (“[T]he court defers to the Commission’s resolution of

factual disputes between expert witnesses.”); see also Fla. Mun.

Power Agency, 315 F.3d at 368. 

Maine PUC insists that FERC cannot rely on the rationale

that price separation between Maine and the rest of New

England was unsupported by the record. Although FERC did

rely on this rationale in its initial order, Maine PUC claims that

the Commission abandoned it in its order on rehearing.

According to Maine PUC, on rehearing FERC refused to

consider data presented by the petitioners and instead found that

it was irrelevant whether Maine was export constrained. But

despite somewhat infelicitous language in its rehearing order,

FERC did not abandon the findings and conclusions of its initial

order. To the contrary, the rehearing order first discussed both

the evidence presented by Maine PUC, including Dr. Austin’s

affidavits, and the data and arguments in the record that

contradicted this evidence. See 117 FERC at 61,722-23; see

also id. at 61,724 (“The Commission did consider arguments

presented in Dr. Austin’s affidavits in approving the Settlement

Agreement.”). FERC’s subsequent statement that the “issue of

Maine being export-constrained is not the subject of this
20

proceeding,” id. at 61,724, did not undo all of that previous

discussion. Rather, it merely clarified that the question of

whether Maine was export constrained was relevant only insofar

as it affected FERC’s determination of reasonable rates; it was

not an independent question before the Commission. See id.

Finally, Maine PUC challenges FERC’s denial of a motion

that it filed on September 8, 2006, following the Commission’s

initial June 16 order. By that motion, Maine PUC sought to

lodge the Department of Energy’s National Electric

Transmission Congestion Study, which Maine PUC argued

supported its claim that the transition payments should be

locational. We accord the Commission “broad discretion in

fashioning hearing procedures,” Mich. Consol. Gas Co. v.

FERC, 883 F.2d 117, 125 (D.C. Cir. 1989) (quoting Lyons v.

Barrett, 851 F.2d 406, 410 (D.C. Cir. 1988)), and find no abuse

of discretion here. The motion at issue was filed nearly three

months after FERC’s decision approving the settlement, and

FERC acted reasonably in holding that it “would be

inappropriate to accept evidence at this extremely late date in

this proceeding (after a dispositive order has been issued), since

it would effectively deny parties the opportunity to respond to

the evidence.” 117 FERC at 61,724. FERC similarly denied

untimely motions to intervene by Bridgeport Energy, LLC and

Casco Bay Energy Company, LLC, which had been filed several

weeks before Maine PUC’s motion. See id. at 61,715.

Accordingly, we reject all of Maine PUC’s attacks on

FERC’s decision to accept non-locational pricing during the

transition period.
21

IV.

Section 4.C of the settlement agreement provides that the

transition payments and the final prices from the Forward

Market auctions will be reviewed under the “public interest”

standard rather than the “just and reasonable” standard. 115

FERC at 62,333. This is more than a matter of semantics: the

public interest standard is “much more restrictive” than the just

and reasonable standard, which means that the settlement

agreement makes it harder to successfully challenge the

transition payments and Forward Market auction prices. Wisc.

Pub. Power, Inc. v. FERC, 493 F.3d 239, 271 (D.C. Cir. 2007)

(citation omitted). The agreement states that the public interest

standard will apply to all future challenges to the transition

payments and final auction prices “whether the change is

proposed by a Settling Party, a non-Settling Party, or the FERC

acting sua sponte.” 115 FERC at 62,333. Petitioners – who

were not parties to the settlement agreement – assert that this

provision will deprive them of their statutory right to challenge

rates under the “just and reasonable” standard. We agree, and

we grant the petition for review on this issue.

* * *

Under the Mobile-Sierra doctrine, “FERC may abrogate or

modify freely negotiated private contracts that set firm rates or

establish a specific methodology for setting the rates for service

. . . only if required by the public interest.” Atl. City Elec. Co.

v. FERC, 295 F.3d 1, 14 (D.C. Cir. 2002). This doctrine

recognizes the superior efficiency of private bargaining, and its

purpose is “to subordinate the statutory filing mechanism to the

broad and familiar dictates of contract law.” Borough of

Lansdale v. FPC, 494 F.2d 1104, 1113 (D.C. Cir. 1974). Thus,

when the parties to a rate dispute reach a contractual settlement,
22

8

 As one commentator has noted, the Mobile-Sierra doctrine

“recognize[s] that the existence of a contract infuses the rate with the

attribute of reasonableness . . . .” Carmen L. Gentile, The MobileSierra Rule: Its Illustrious Past and Uncertain Future, 21 ENERGY L.J.

353, 357 (2000).

FERC must enforce the terms of the bargain unless the public

interest requires otherwise – that is, unless the negotiated rates

“might impair the financial ability of the public utility to

continue its service, cast upon other customers an excessive

burden, or be unduly discriminatory.” FPC v. Sierra Pac.

Power Co., 350 U.S. 348, 355 (1956). In the instant case, we

are presented with a question of first impression: may the

Commission approve a settlement agreement that applies the

highly-deferential “public interest” standard to rate challenges

brought by non-contracting third parties? We think not.

Section 206 of the Federal Power Act provides: “Whenever

the Commission, after a hearing had upon its own motion or

upon complaint, shall find that any rate, charge, or classification

. . . is unjust, unreasonable, unduly discriminatory or

preferential, the Commission shall determine the just and

reasonable rate . . . and shall fix the same by order.” 16 U.S.C.

§ 824e(a). In other words, when a party files a complaint

against a rate or charge, FERC must adjudicate the challenge

under the “just and reasonable” standard. The Mobile-Sierra

doctrine carves out an exception to this rule based on the

“familiar dictates of contract law.” Lansdale, 494 F.2d at 1113.

When two or more parties reach a negotiated settlement over a

disputed rate, FERC applies a strong presumption that the settled

rate is just and reasonable, and the Commission may only set

aside the contract for the most compelling reasons.8

 The

purpose of the Mobile-Sierra doctrine is “to preserve the
23

benefits of the parties’ bargain as reflected in the contract,

assuming that there was no reason to question what transpired

at the contract formation stage.” Atl. City, 295 F.3d at 14. For

example, in the Sierra case, Pacific Gas & Electric (PG&E) had

surplus hydroelectric power, which it sold to Sierra Pacific

Power Company at a very low rate. 350 U.S. at 351-52. When

the surplus power was no longer available, PG&E – with the

Commission’s approval – reneged on its contract and increased

Sierra’s rates. Id. at 352. The Supreme Court held for Sierra,

stating that “neither PG&E’s filing of the new rate nor the

Commission’s finding that the new rate was not unlawful was

effective to change PG&E’s contract with Sierra.” Id. at 353.

The Court required the Commission to apply the highlydeferential “public interest” standard of review to challenges to

contractually-established rates, in order to preserve the terms of

the parties’ bargain. Id. at 355; see also Lansdale, 494 F.2d at

1107-14 (holding that FERC may not approve a utility’s breach

of a settled rate contract unless the contract rates “contravened

the public interest”).

Courts have rarely mentioned the Mobile-Sierra doctrine

without reiterating that it is premised on the existence of a

voluntary contract between the parties. In Mobile, the Supreme

Court stated that “the relations between the parties” may be

established by contract, subject only to “public interest” review.

United Gas Pipeline Co. v. Mobile Gas Serv. Corp., 350 U.S.

332, 339 (1956) (emphasis added). Similarly, this Court has

emphasized that the deferential public interest standard only

applies to “freely negotiated private contracts that set firm rates

or establish a specific methodology for setting the rates for

service.” Atl. City, 295 F.3d at 14 (emphasis added); see also

Maine PUC v. FERC, 454 F.3d 278, 283-84 (D.C. Cir. 2006);

Richmond Power & Light v. FPC, 481 F.2d 490, 493 (D.C. Cir.

1973) (“The contract between the parties governs the legality of
24

the filing.”).

This case is clearly outside the scope of the Mobile-Sierra

doctrine. As we explained, Mobile-Sierra is invoked when “one

party to a rate contract on file with FERC attempts to effect a

unilateral rate change by asking FERC to relieve its obligations

under a contract whose terms are no longer favorable to that

party.” Maine PUC, 454 F.3d at 284. Here, the settling parties

are attempting to thrust the “public interest” standard of review

upon non-settling third parties who have vociferously objected

to the terms of the settlement agreement. As the Supreme Court

has noted, “[i]t goes without saying that a contract cannot bind

a nonparty.” EEOC v. Waffle House, Inc., 534 U.S. 279, 294

(2002). The Mobile-Sierra doctrine applies a more deferential

standard of review to preserve the terms of the bargain as

between the contracting parties. Atl. City, 295 F.3d at 14. But

when a rate challenge is brought by a non-contracting third

party, the Mobile-Sierra doctrine simply does not apply; the

proper standard of review remains the “just and reasonable”

standard in section 206 of the Federal Power Act.

In defense of the Mobile-Sierra provision, FERC argues

that the “public interest” standard will only apply to future

challenges to a narrow category of rates: the transition payments

and the final auction clearing prices from the Forward Market.

115 FERC at 62,335. This is not persuasive. It is equivalent to

arguing that FERC will use an illegal standard sparingly.

Despite the “limited” applicability of the public interest

standard, FERC’s approval of this agreement still deprives nonsettling parties of their statutory right to have rate challenges

adjudicated under the “just and reasonable” standard. And in

any event, we are skeptical of FERC’s characterization of the

Mobile-Sierra provision as “narrow” or “limited.” As

petitioners’ counsel noted at oral argument, if circumstances
25

9

 FERC asserts that third parties’ interests are adequately

safeguarded because under Mobile-Sierra, the Commission “retains

significant authority to protect non-parties to the settlement from

harm.” 115 FERC at 62,335. But whatever comfort third parties

might derive from FERC’s continued ability to defend their interests,

the existence of such powers does not justify derogation of the

statutory right to “just and reasonable” review of rates.

change after a rate has initially been approved by the

Commission, then (under the settlement agreement) subsequent

challenges to that rate would be reviewed under the public

interest standard. Recording of Oral Arg. at 29:25-31:20. The

Mobile-Sierra provision thus departs from the usual “just and

reasonable” standard and makes it harder for petitioners to

successfully challenge rates in cases of changed circumstances.9

FERC also argues that in other recent cases, the

Commission has approved contracts that apply the “public

interest” standard to non-contracting third parties. 117 FERC at

61,727 n.103. This may show that the Commission’s policy has

been consistent – although even FERC concedes that is so only

since 2002 – but it does not necessarily support the policy’s

legality, since none of the cited orders have been subject to

judicial review on the Mobile-Sierra issue. FERC states that

“there is no Commission or court precedent that supports a

finding that a non-signatory may unilaterally seek changes to a

Mobile-Sierra ‘public interest’ contract under the ‘just and

reasonable’ standard of review.” 115 FERC at 62,335 (citation

omitted). It could just as easily be said that there is no “court

precedent” that supports altering third parties’ statutory rights

based on a contract that they refused to sign. Moreover, while

FERC can find no “precedent” in support of petitioners’

arguments, the relevant statutory language is quite clear: section
26

206 of the FPA states that “upon complaint” the Commission

must determine whether the challenged rate is “unjust,

unreasonable, unduly discriminatory or preferential.” 16 U.S.C.

§ 824e(a). Lastly, FERC argues that the Mobile-Sierra

provision is necessary to promote price certainty and contract

stability. As explained above, the Mobile-Sierra doctrine is

designed to ensure contract stability as between the contracting

parties – i.e., to make it more difficult for either party to shirk

its contractual obligations. Atl. City, 295 F.3d at 14. It makes

no sense to say that the values of “stability” and “certainty” are

furthered by applying the deferential standard of review to the

eight parties that refused to agree to the terms of the settlement.

V.

Petitioners also contend that FERC’s approval of the

Forward Market exceeds the Commission’s jurisdiction because

it forces utilities to purchase a specific amount of capacity.

Petitioners assert that FERC lacks jurisdiction under the Federal

Power Act, which provides that the Commission “shall not have

jurisdiction . . . over facilities used for the generation of electric

energy.” 16 U.S.C. § 824(b)(1). In response, FERC argues that

the settlement agreement only addresses prices, which are

unquestionably within FERC’s jurisdiction. The Commission’s

interpretation of the scope of its jurisdiction is entitled to

Chevron deference. Okla. Natural Gas Co. v. FERC, 28 F.3d

1281, 1283-84 (D.C. Cir. 1994).

We agree with the Commission that the Forward Market

itself does not exceed FERC’s jurisdiction. The Federal Power

Act grants the Commission broad authority over “the sale of

electric energy at wholesale in interstate commerce.” 16 U.S.C.

§ 824(b)(1). The protracted litigation over Must-Run
27

agreements, the locational installed capacity market, and the

Forward Market is fundamentally a dispute over the rates that

will be paid to suppliers of capacity. The two key components

of the settlement agreement – the transition payments and the

Forward Market auctions – “establish a mechanism and market

structure for the purchase and sale of installed capacity at

wholesale . . . [and] determine the prices for those sales.” 115

FERC at 62,339 (emphasis added). Of course, it is a basic

principle of economics that prices affect supply – the auction

clearing prices in each sub-region of New England will certainly

influence the amount of capacity that generators are willing to

supply. Indeed, one of the primary purposes of the new market

mechanism is to “provide[] incentives to attract new

infrastructure where needed.” Id. at 62,316. But an incentive is

not a mandate. The mere fact that the Forward Market will

encourage new supply does not mean that it regulates “facilities

used for the generation of electric energy.” 16 U.S.C. §

824(b)(1). Rather, the Forward Market is designed to address

pricing issues, which fall comfortably within FERC’s statutory

authority over “the sale of electric energy at wholesale in

interstate commerce.” Id. We have previously held that the

Commission has jurisdiction over a “deficiency charge” that was

imposed upon transmission providers who failed to procure a

specified amount of capacity:

The deficiency charge . . . must be deemed to be within the

Commission’s jurisdiction because it [ ] represents a charge

for the power and service the overloaded participant

receives – or it is at least a rule or practice affecting the

charge for these services.

Municipalities of Groton v. FERC, 587 F.2d 1296, 1302 (D.C.

Cir. 1978).
28

In support of their jurisdictional argument, petitioners focus

heavily upon the “installed capacity requirement,” which is “the

total amount of capacity required by the system to meet peak

load plus a reserve margin.” 115 FERC at 62,338-39 n.177.

This requirement ensures that transmission providers have

procured enough capacity to maintain the reliability of the grid.

Under the settlement agreement, transmission providers must

purchase at least enough capacity in the annual auctions to meet

their installed capacity requirements. Id. at 62,307. The

Forward Market simply takes the capacity requirement as a

given and uses it as an input into the auction mechanism. As

FERC explained, “[the Forward Market] only establishes a

market design for determining capacity charges; it does not alter

[the capacity requirement] or in any way determine the

appropriate amount of capacity that must be available.” 117

FERC at 61,730. Rather, the capacity requirement is computed

by ISO-New England in conjunction with a regional standardsetting body. 115 FERC at 62,338-39 n.177. To be sure, the

methodology for calculating the installed capacity requirement

is part of the ISO’s tariff, and must be filed with the

Commission for approval. See ISO New England, Inc., 120

FERC ¶ 61,234 at 61,974-75 (2007). To the extent petitioners

believe they are aggrieved by the ISO’s installed capacity

requirement, and more specifically, FERC’s approval of that

requirement on jurisdictional grounds, they may challenge that

agency action. In fact, petitioners have already filed such a suit.

Conn. Dep’t of Public Util. Control v. FERC, No. 07-1375 (D.C.

Cir. filed Sept. 19, 2007). But the Forward Market does not

exceed FERC’s jurisdiction merely because it incorporates the

exogenously-determined installed capacity requirement into the

auction mechanism. We thus deny the petition for review with

respect to the jurisdictional issue.
29

VI.

For the aforementioned reasons, the consolidated petitions

for review are granted with respect to the Mobile-Sierra issue,

denied with respect to all other issues, and remanded to the

Commission for further proceedings.

So ordered.