BRAINTREE ELECTRIC LIGHT DEPARTMENT, et al., Petitioners v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent ISO New England Inc., et al., Intervenors.
Nos. 09–1231, 10–1395.
Argued Sept. 12, 2011. -- February 07, 2012
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.Carmen L. Gentile and Mary E. Gover were on the brief for intervenor NSTAR Electric Company in support of respondent.
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.
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 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 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 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 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 argument for cost reallocation as barred by the settlement. These petitions for review followed.
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. § 825 l (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 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.
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 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 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.
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 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.
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 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 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 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.
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.
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
For the foregoing reasons, the petitions for review are denied.
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.
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.”
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).
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.
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 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.
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.
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.
GARLAND, Circuit Judge:
Opinion for the Court filed by Circuit Judge GARLAND.