Braintree Electric Light Department v. Federal Energy Regulatory Commission , 667 F.3d 1284 ( 2012 )

United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued September 12, 2011 Decided February 7, 2012
No. 09-1231
BRAINTREE ELECTRIC LIGHT DEPARTMENT, ET AL.,
PETITIONERS
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
ISO NEW ENGLAND INC., ET AL.,
INTERVENORS
Consolidated with No. 10-1395
On Petitions for Review of Orders
of the Federal Energy Regulatory Commission
John P. Coyle argued the cause for petitioners. With him
on the briefs were Scott H. Strauss and Jeffrey A. Schwarz.
Carol J. Banta, Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With her on the
brief was Robert H. Solomon, Solicitor.
2
Carmen L. Gentile and Mary E. Gover were on the brief for
intervenor NSTAR Electric Company in support of respondent.
Before: TATEL, GARLAND, and BROWN, Circuit Judges.
Opinion for the Court filed by Circuit Judge GARLAND.
GARLAND, Circuit Judge: Braintree Electric Light
Department and other municipally owned utilities in
southeastern Massachusetts petition for review of four orders of
the Federal Energy Regulatory Commission (FERC). The
orders denied the petitioners’ claim that they were being
unjustly charged in order to ensure system reliability on Cape
Cod. The dispute was first addressed in a FERC-approved
settlement agreement that reserved certain litigation rights to the
petitioners. Because the Commission reasonably resolved the
claims that were reserved, and reasonably construed the
settlement agreement to foreclose the petitioners’ additional
claims, we affirm the Commission’s orders and deny the
petitions for review.
I
Two oil-powered generators, known as the Canal Units,
have provided electricity to Cape Cod since the 1970s.
Braintree Elec. Light Dep’t v. ISO New England Inc., 124 FERC
¶ 61,061, 61,360 & n.3 (2008) [hereinafter Complaint Order].
In 2006, the rising price of oil made the Canal Units more
expensive to run, and they became largely uneconomic. The
Independent System Operator for New England (“ISO New
England” or “ISO-NE”), however, determined that running the
generators remained necessary to avoid blackouts on Cape Cod
in the event that more than one transmission line providing
power to the Cape were damaged in quick succession (a “second
3
contingency”).1 The ISO therefore designated the Canal Units
as a “Local Second Contingency Protection Resource”
(LSCPR). Under the ISO New England tariff, an effect of this
designation was to spread the cost of running the Canal Units
among all participants in the Southeastern Massachusetts
(SEMA) Reliability Region, in proportion to their load
obligations. ISO-NE Tariff § III.6.4.4 (Resp’t Br. A-12). The
petitioners are load-serving entities that are within the region but
do not serve Cape Cod.
ISO New England’s designation of the Canal Units as
LSCPRs prompted the petitioners, other utilities, ISO New
England, and the transmission owners in the region to take part
in a FERC-supervised mediation. After almost a year of
negotiations, FERC approved the resulting Settlement
Agreement in 2007. See J.A. 205-55. Under the settlement, the
transmission owners agreed to reimburse the petitioners for
some of the Canal Units’ 2006 charges. Settlement Agreement
§ 3.1. Section 4.1 of the agreement provided that the costs of
operating the Canal Units after 2006 would be allocated on the
same basis that costs for an LSCPR are allocated under the ISO
New England tariff -- “[s]ubject to” the petitioners’ reserved
litigation rights under Section 7 (and to provisions in certain
other sections). Also subject to the petitioners’ reserved
1
An independent system operator 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.’” NRG Power
Mktg., LLC v. Me. Pub. Utils. Comm’n, 130 S. Ct. 693, 697 n.1 (2010)
(quoting Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361,
1364 (D.C. Cir. 2004)). Under its tariff, ISO-NE is obligated to assure
that New England’s power supply “conforms to proper standards of
reliability.” ISO-NE Tariff § I.1.3.
4
litigation rights, the parties were barred from attempting to
reclassify the Canal Units under the tariff and thereby from
changing the method of cost allocation. Id. § 4.1; see also id.
§§ 8(c), 10.1.
Section 7 defined the reserved litigation rights of the
petitioners, preserving future claims of two sorts. First, Section
7.1 permitted the petitioners to seek
relief from SEMA [reliability] Charges for LSCPR
through litigation . . . over whether consistent with
[applicable reliability criteria] such charges could be or
should be reduced through implementation of [a
Special Protection System] or Post-First Contingency
Switching arrangement.
In other words, the petitioners were permitted to litigate
whether, consistent with maintaining system reliability, one of
two identified alternatives to the Canal Units -- a specified type
of protection system or switching arrangement -- could or
should be implemented. Section 7.2 set forth the second
reservation, which stated:
The Parties, other than the Municipals [i.e. the
petitioners], agree not to seek a change . . . in the ISO-
NE definition of the SEMA Reliability Region . . . ;
provided that the Municipals may seek such a change
to become effective no earlier than January 1, 2008.
That is, the petitioners were permitted to petition for a change in
the definition of the SEMA reliability region to take effect on or
after January 1, 2008.
If successfully pursued, either reserved litigation right
would permit the petitioners to reduce their share of Canal Unit
5
charges. If the petitioners could show that one of the identified
alternatives could or should be implemented without degrading
reliability, they would be entitled to financial relief. Likewise,
if the SEMA reliability region were divided in a way that left the
petitioners outside the subregion to which the costs of the Canal
Units were allocated, they would be insulated from sharing those
costs under ISO New England’s tariff.
The petitioners filed a complaint with the Commission on
March 28, 2008. They contended (1) “that ISO-NE should
implement Post First Contingency Switching or a Special
Protection System” as an alternative that would reduce LSCPR
charges; and (2) that “costs that are incurred to protect Cape Cod
should not be allocated to the entire SEMA region but that the
region should be divided into two sub-regions, Upper and Lower
SEMA, and the costs should be allocated only to Lower
SEMA.” 124 FERC at 61,360, 61,361. In its Complaint Order,
FERC denied the first request because it “would inappropriately
degrade reliability.” Id. at 61,364. As to the second, it found
that “whether or not the cost allocations resulting from the
boundaries of the current SEMA region are just and reasonable
raises issues of material fact” and, accordingly, it scheduled a
hearing on the issue. Id. FERC held the hearing in abeyance,
however, until ISO New England could consider the division of
the SEMA region through its stakeholder process. Id. FERC
ordered ISO New England to address “cost allocation issues” as
part of that process and thereafter to submit a report to the
Commission. Id. The petitioners filed a request for a rehearing,
which was denied. Braintree Elec. Light Dep’t v. ISO New
England Inc., 128 FERC ¶ 61,008 (2009) [hereinafter 2009
Rehearing Order].
In compliance with the Complaint Order, ISO New England
submitted a filing on June 17, 2009 that detailed the outcome of
its stakeholder process. In the ISO’s view, “the SEMA regional
6
boundary resulted in just and reasonable cost allocations” and no
change was warranted. Braintree Elec. Light Dep’t v. ISO New
England Inc., 129 FERC ¶ 61,077, 61,351 (2009) [hereinafter
Compliance Order]. Specifically, it reported that upgrades to
the transmission system -- which effectively eliminated system
reliance on out-of-merit dispatch of the Canal Units2 -- had
obviated the need for prospective change to the SEMA
boundary, and that no party continued to “advocate[] a
permanent change to the boundary.” Id. at 61,357. In its
Compliance Order, the Commission “agree[d] with ISO’s
proposal to retain the existing SEMA reliability region
boundary,” and it rejected the petitioners’ request for “additional
procedures.” Id.The petitioners filed a request for rehearing, which the
Commission denied. Braintree Elec. Light Dep’t v. ISO New
England Inc., 132 FERC ¶ 61,248 (2010) [hereinafter 2010
Rehearing Order]. In its 2010 Rehearing Order, the
Commission clarified its reading of the Settlement Agreement,
holding that Section 7.2 reserved only the right to litigate for an
actual change in the SEMA boundary. In FERC’s view, the
settlement did not permit the petitioners to argue for a refund of
Canal Unit charges based upon a hypothetical change in the
SEMA region limited to an earlier period. Since the petitioners
had abandoned their request for actual and prospective (from
March 2008 forward) change, FERC viewed their remaining
2
In the New England Power Pool, generators are usually
employed in order of “economic merit”; that is, units offering lower
bids to supply power are employed first. NSTAR Elec. & Gas Corp.
v. FERC, 481 F.3d 794, 797 (D.C. Cir. 2007). Sometimes, however,
generators “whose bids exceed the market-clearing price are called
into service to ensure system reliability.” Id. This is referred to as
“out-of-merit dispatch.”
7
argument for cost reallocation as barred by the settlement.
These petitions for review followed.
II
We review FERC’s orders under the “arbitrary or
capricious” standard of the Administrative Procedure Act,
seeking to determine whether they are “arbitrary, capricious, an
abuse of discretion, or otherwise not in accordance with law.”
5 U.S.C. § 706(2)(A); see PSEG Energy Res. & Trade LLC v.
FERC, No. 10-1103, 2011 WL 6450762, at *3 (D.C. Cir. Dec.
23, 2011); TNA Merch. Projects, Inc. v. FERC, 616 F.3d 588,
591 (D.C. Cir. 2010). To survive this review, FERC “must
‘examine the relevant data and articulate a satisfactory
explanation for its action including a rational connection
between the facts found and the choice made.’” PPL
Wallingford Energy LLC v. FERC, 419 F.3d 1194, 1198 (D.C.
Cir. 2005) (quoting Motor Vehicle Mfrs. Ass’n v. State Farm
Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)). The Commission’s
factual findings are conclusive if supported by substantial
evidence. 16 U.S.C. § 825l(b).
FERC’s interpretation of a settlement agreement within its
jurisdiction is entitled to deference under the familiar two-step
analysis of Chevron U.S.A. Inc. v. Natural Resources Defense
Council, Inc., 467 U.S. 837 (1984). See MarkWest Mich.
Pipeline Co., LLC v. FERC, 646 F.3d 30, 34 (D.C. Cir. 2011).
At step one, we “‘consider de novo whether the settlement
agreement unambiguously addresses the matter at issue. If so,
the language of the agreement controls . . . .’” Id. (quoting
Ameren Servs. Co. v. FERC, 330 F.3d 494, 498 (D.C. Cir.
2003)). At step two, “[i]f the agreement is ambiguous or silent,
. . . ‘we defer to the Commission’s construction of the provision
at issue so long as that construction is reasonable.’” Id. (quoting
8
Koch Gateway Pipeline Co. v. FERC, 136 F.3d 810, 814-15
(D.C. Cir. 1998)).
The petitioners contend that Chevron deference is
unwarranted because the Commission did not expressly state
that the settlement agreement it was interpreting was ambiguous.
But the Chevron two-step is a dance for the court, not the
Commission. To be sure, “[i]f the Commission’s decision turns
on an erroneous assertion that the plain language of the relevant
wording is unambiguous, . . . we must remand the matter to the
Commission to require the agency to consider the question
afresh in light of the ambiguity we see.” Ameren, 330 F.3d at
498-99 (internal quotation marks omitted). But the Commission
made no such erroneous assertion here, and no contrary
assertion of ambiguity is required. As long as the text is
ambiguous and the agency does not insist that it is clear, a
reasonable interpretation will warrant our deference. There is no
reason for us to assume that the Commission sees clarity where
we do not.
With this understanding of the scope of our review, we
proceed to examine the petitioners’ contentions.
A
The petitioners’ first contention, which on its face appears
to track their first reserved litigation right, is that ISO New
England could have reduced the petitioners’ charges by using
one of the alternatives identified in Section 7.1 -- a Special
Protection System or a Post-First Contingency Switching
arrangement -- instead of operating the Canal Units to maintain
compliance with reliability criteria. FERC, however, disagreed.
It found that either alternative “would expose Cape Cod to the
risk of involuntary load shedding” if one of the transmission
lines that provide power to the Cape were lost -- a result it
9
deemed unacceptable. Complaint Order, 124 FERC at 61,363.
If “ISO-NE relied on a [Post First Contingency Switching] or a
[Special Protection System],” FERC said, “then the next step
after a first contingency would be the involuntary shedding of
firm load.” 2009 Rehearing Order, 128 FERC at 61,032. Such
a scenario “would inappropriately degrade reliability” by
increasing the likelihood of forced outages. Id.; see Complaint
Order, 124 FERC at 61,364 (finding that either alternative “has
the potential to black out Cape Cod load for up to 24 hours”).
We ordinarily defer to this kind of technical judgment, see B&J
Oil & Gas v. FERC, 353 F.3d 71, 76 (D.C. Cir. 2004), and the
petitioners proffer nothing that persuades us to take a different
path here.
The petitioners do point out that, in a report authored
pursuant to the Settlement Agreement, ISO New England stated
that a “switching alternative” could “technically be implemented
under Applicable Criteria up to a New England load level of
approximately 17,000 MW.” Short-Term Report of ISO New
England, Inc. at 17 (July 17, 2007) (J.A. 164) (emphasis added).
But the report ultimately recommended against a switching
arrangement because “the need for load shedding” in the event
of a second contingency “would occur at virtually all hours of
the year.” Id. As the petitioners concede, the New England load
level is above the 17,000 MW specified in the report roughly
70% of the time. Pet’rs Reply Br. 4. Moreover, under a
switching arrangement, “system restoration” could “take 24
hours” after a second contingency. Short-Term Report at 18
(J.A. 165). In these circumstances, FERC reasonably
determined that implementation of a switching arrangement
would not satisfy applicable reliability criteria.
The petitioners respond that they did not mean to suggest
that ISO New England should actually adopt either of the
identified alternatives, and that FERC “addressed a strawman
10
argument about whether [a Post First Contingency Switching or
Special Protection System] arrangement should be
implemented.” Pet’rs Br. 39-40. Their true argument,
petitioners maintain, was that the alternatives should serve as
hypothetical arrangements under which their charges would be
reduced. They further argue that, in light of the alternatives, the
Canal Units were not “necessary” for adherence to applicable
reliability standards and hence did not meet the definition of
LSCPRs under the ISO New England tariff.3 Thus, the
petitioners conclude, the units may be reclassified for billing
purposes only, and because no physical change would actually
be implemented, there would be no blackouts.
But the so-called “strawman” argument that FERC
addressed was the very argument the settlement had reserved for
future litigation. In words that largely parallel the argument the
petitioners now characterize as a strawman, Section 7 of the
Settlement Agreement reserved for the petitioners the right to
seek “relief from [reliability] Charges for LSCPR through
litigation . . . over whether consistent with [applicable reliability
criteria] such charges could be or should be reduced through
implementation of [a Special Protection System] or Post-First
Contingency Switching arrangement.” Settlement Agreement
§ 7.1. FERC can hardly be faulted for thinking that the
petitioners were making the argument that Section 7 reserved for
them.
3
ISO New England’s tariff defines an LSCPR as a resource
“identified by the ISO on a daily basis as necessary for the provision
of Operating Reserve Requirements and adherence to [North
American Electric Reliability Council, Northeast Power Coordinating
Council], and ISO reliability criteria over and above those Resources
required to meet first contingency reliability criteria within a
Reliability Region.” ISO-NE Tariff § III.6.1 (Resp’t Br. A-11).
11
Moreover, FERC made clear that the settlement did not
reserve, but rather barred, the billing reclassification argument
the petitioners press here. See 2009 Rehearing Order, 128
FERC at 61,034-35 (“[T]he SEMA Settlement resolves the issue
of classification of the Canal Unit out-of-merit dispatch costs as
LSCPR.”). FERC explained that any argument that the Canal
Units should merely be reclassified for financial purposes was
barred by Section 4.1 of the agreement, which provides that no
party shall seek a “‘reclassification of ISO-NE’s designation of
Canal as an LSCPR’” -- “‘subject’” only to Section 7 (and other
sections not relevant here). 2010 Rehearing Order, 132 FERC
at 62,416 (quoting § 4.1).4 The suggestion that a special
protection system or contingency switching arrangement should
be considered on a hypothetical basis did not come within the
Section 7 proviso, FERC said, because that section reserved
only the possibility that “charges ‘could or should be reduced
through implementation of’” those alternatives. 2010 Rehearing
Order, 132 FERC at 62,416 (quoting § 7.1) (emphasis added);
see 2009 Rehearing Order, 128 FERC at 61,034.5 This was
certainly a reasonable construction, given that reclassification is
4
“Likewise,” the Commission noted, Section 8(c) provides that
no party shall argue for amendments “‘that would provide for a
different mechanism for allocation of NCPC charges for LSCPR, or
shall seek or support reclassification of ISO-NE’s designation of Canal
as a LSCPR[,] . . . other than as provided in Section[] . . . 7.’” 2010
Rehearing Order, 132 FERC at 62,416 (quoting Settlement Agreement
§ 8(c)) (emphasis in the Rehearing Order).
5
This is not to say that FERC believed Section 7.1 applied only
if one of the alternatives were actually implemented. In the
Commission’s view, a refund was also possible if the ISO “could have
implemented” it but had not done so. See 2010 Rehearing Order, 132
FERC at 62,413. This would only apply, however, if the alternative
could actually have been implemented consistent with applicable
reliability criteria. See id. at 62,415.
12
not among the litigation rights reserved in the text of Section 7.
See supra Part I (quoting Settlement Agreement § 7.1, 7.2).
At oral argument, the petitioners maintained that we should
infer the contents of the reserved rights not from the text of
Section 7 but from the provisions that are “subject to” its
reservations. Oral Arg. Recording at 44:10 - 45:15. They argue
that, because Section 4’s bar on reclassification of the Canal
Units is “subject to” the petitioners’ reserved litigation rights,
reclassification is itself one of those rights. But Section 7 is
quite explicit about what rights the settlement reserved, and it
was not unreasonable for FERC to conclude that the content of
the petitioners’ reserved litigation rights is defined by the
language of the section that sets out those rights.
B
The petitioners’ second contention, as stated in their initial
complaint to FERC, is that “the reliability costs that are incurred
to protect Cape Cod should not be allocated to the entire SEMA
region but [rather] the region should be divided into two
sub-regions, Upper and Lower SEMA.” Complaint Order, 124
FERC at 61,361. On its face, this contention again appears to
fall within the litigation rights reserved for the petitioners in
Section 7: specifically, the second reservation, as set out in
Section 7.2, which permits the petitioners “to seek a change . . .
in the ISO-NE definition of the SEMA Reliability Region to
become effective . . . no earlier than January 1, 2008.”
In the Complaint Order, FERC referred this issue for initial
consideration to the ISO New England stakeholder process.6
6
The petitioners contend that the Commission “unreasonably
deferred to the ISO-NE stakeholder process,” and that its adoption of
ISO-New England’s recommendations was an “abdication of its
13
But by the time ISO New England supplied its analysis to
FERC, it was plain to all parties that system upgrades that
largely eliminated reliance on the Canal Units had made division
of the SEMA region unnecessary, and the petitioners had
dropped their request for a prospective division. Compliance
Order, 129 FERC at 61,357 (“Both ISO-NE and Municipals
agree that prospectively redrafting the SEMA boundary is
unnecessary due to upgrades to the transmission system. The
completion of these upgrades mitigates the need for out-of-merit
dispatch of the Canal Units and the resulting LSCPR charges
that are the subject of this dispute.”). Accordingly, the
petitioners told FERC that they were “not seeking to ‘modif[y]’
the SEMA zone during the refund effective period. Rather, they
[were] seeking refunds of Canal LSCPR charges that were
unjustly or unreasonably allocated to them because of the zonal
boundaries during that period.” Protest and Request to Resume
Hearing at 3 n.5, Braintree Elec. Light Dep’t v. ISO New
England Inc., Docket No. EL08-48-002 (August 7, 2009) (J.A.
681). At oral argument before this court, the petitioners again
made clear that they were not seeking a permanent change in the
boundaries of SEMA, but rather financial relief “as if” the
regulatory responsibilities.” Pet’rs Br. 52, 53. We reject these
contentions for two reasons. First, FERC merely referred the issue in
order to obtain input from the interested parties; the Compliance Order
provided FERC’s own independent assessment. See 129 FERC at
61,357-58; see also 2009 Rehearing Order, 128 FERC at 61,038
(“Because the Commission will ultimately review and act on any
resulting proposal, there is no issue with respect to delegation of
Commission authority.”). We have previously approved this kind of
process. See Pub. Serv. Comm’n of Wis. v. FERC, 545 F.3d 1058,
1062-64 (D.C. Cir. 2008). Second, as we discuss below, FERC
ultimately based its resolution of the petitioners’ argument about
dividing the region on its construction of the Settlement Agreement,
not on the stakeholder process.
14
boundaries had been retroactively changed for the “locked-in”
2008-09 period. Oral Arg. Recording at 6:50 - 7:15.7
The Commission, however, held that the Settlement
Agreement precluded a claim for financial relief based on this
kind of hypothetical, temporary, and retroactive change to the
SEMA region that would apply only for the “locked-in” period.
Section 4.1 of the settlement provides that “no Party shall seek
or support a different allocation mechanism” for Canal Unit
charges -- “[s]ubject to” Section 7 (and other sections not
relevant here). Section 7.2, in turn, reserves for the petitioners
the right “to seek a change . . . in the ISO-NE definition of the
SEMA Reliability Region to become effective . . . no earlier
than January 1, 2008.” Once the petitioners abandoned their
claim for an actual, prospective change to the region’s boundary,
FERC considered their remaining request for a hypothetical,
retroactive bifurcation -- for cost-allocation purposes only -- to
be barred by the settlement. “Contrary to Municipals’
assertion,” FERC held, “neither Section 7.1 nor Section 7.2
contains language to permit reallocation of Canal LSCPR costs
because the SEMA boundary ‘should have been changed,’
absent a change in the definition of the SEMA region.” 2010
7
The parties’ pleadings refer to a “locked-in” refund period that
extends from March 28, 2008 through June 28, 2009. See, e.g., 2010
Rehearing Order, 132 FERC at 62,423. Under Section 206 of the
Federal Power Act, if FERC finds that any “rate, charge, or
classification” is “unjust, unreasonable, unduly discriminatory or
preferential,” the Commission is authorized to “order refunds of any
amounts paid” for a fifteen-month period following the “refund
effective date.” 16 U.S.C. § 824e(a), (b). In this case, FERC set
March 28, 2008 -- the day the petitioners filed their complaint -- as the
refund effective date. Complaint Order, 124 FERC at 61,360. As it
happened, by the end of the fifteen-month statutory refund period,
system upgrades had largely eliminated the disputed charges, making
a division of SEMA no longer relevant. See Resp’t Br. 2.
15
Rehearing Order, 132 FERC at 62,416; see also id. at 62,415
(“[We] determin[e] that the SEMA Settlement permits
Municipals to seek a change in the SEMA boundary, but not
reallocation in the absence of such a change . . . .”).
We defer to this construction of the Settlement Agreement
under Chevron principles. The agreement provides that the
petitioners may seek “a change” in the definition of the SEMA
Region “to become effective no earlier than January 1, 2008.”
Settlement Agreement § 7.2. It is (at best) unclear from the text
whether “a change” encompasses the hypothetical and
temporary bifurcation the petitioners seek, or only an actual and
prospective change. The phrase “to become effective” suggests
the latter. Moreover, other provisions of the agreement indicate
an overarching intent to have the settlement resolve all cost
allocation issues among the parties, see id. §§ 4.1, 8(c), and
therefore counsel against construing Section 7 to permit what
are essentially cost-reallocation claims in the guise of a litigation
reservation. FERC’s reading of the ambiguous Settlement
Agreement is reasonable and entitled to deference.
C
Finally, the petitioners contend that FERC’s orders should
be overturned because they violate the “cost causation”
principle. Pet’rs Br. 44. “We have described this principle as
‘requir[ing] that all approved rates reflect to some degree the
costs actually caused by the customer who must pay them.’”
Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361,
1368 (D.C. Cir. 2004) (quoting KN Energy, Inc. v. FERC, 968
F.2d 1295, 1300 (D.C. Cir. 1992)). The petitioners maintain that
the costs they were charged were far out of proportion to the
reliability benefits they obtained from the operation of the Canal
Units.
16
The short answer to the petitioners’ cost causation
argument, and the only one we need consider, is that it is beyond
the scope of the litigation rights reserved in the Settlement
Agreement. As we have discussed, FERC construed the
settlement to reserve two types of claims: whether an alternative
to the Canal Units could or should be implemented, and whether
the SEMA region should be divided. 2010 Rehearing Order,
132 FERC at 62,418-19. The petitioners’ cost causation claim
comes within neither of these categories. As the Commission
explained in the 2010 Rehearing Order, “[c]ontrary to
Municipals’ assertion, the Commission did not [in the
Compliance Order] improperly avoid consideration of Canal
Unit out-of-merit dispatch costs and resulting benefits.” Id. at
62,419. Rather, “the Commission did not review such issues
because we found that the SEMA Settlement, to which
Municipals are a party, barred reallocation and, in the
compliance phase, no party continued to advocate a change in
the definition of the SEMA boundary as permitted by the SEMA
Settlement, section 7.2.” Id. We affirm FERC’s reasonable
determination that the Settlement Agreement bars the
petitioners’ cost causation argument.8
8
In the 2010 Rehearing Order, FERC went on to consider and
reject the petitioners’ cost causation argument on the merits. See 2010
Rehearing Order, 132 FERC at 62,419-21. It also considered and
rejected the merits of the petitioners’ proposal to “divide SEMA for
the interim period.” Id. at 62,424; see supra Part II.B. We need not
address those determinations here. “When an agency offers multiple
grounds for a decision, we will affirm the agency so long as any one
of the grounds is valid, unless it is demonstrated that the agency would
not have acted on that basis if the alternative grounds were
unavailable.” BDPCS, Inc. v. FCC, 351 F.3d 1177, 1183 (D.C. Cir.
2003) (citing, inter alia, SEC v. Chenery Corp., 318 U.S. 80, 88
(1943)). The 2010 Rehearing Order makes it clear that the settlement
bar constituted an independent rationale for the Commission’s
decision. See 2010 Rehearing Order, 132 FERC at 62,415.
17
III
For the foregoing reasons, the petitions for review are
denied.